# CALIFORNIA REGULATORY INTELLIGENCE > Covering Resource Adequacy, Integrated Resource Planning, Demand Response, Transportation Electrification, natural gas planning, and more Public Ghost content for AI and LLM tooling. This file includes a bounded export of public pages first, then recent public posts. Append `.md` to any post or page URL to get the content in Markdown (for example, `/example-post.md`). ## Pages ### CRI's Topical Index URL: https://www.calregulatory.com/categories-topics/ Last updated: 2026-02-24T00:44:27.000Z *This is a routinely updated, living document to assist with site navigation.* ## CONCEPTS, FRAMEWORKS, PRINCIPLES - [**Duck Curve**](https://www.calregulatory.com/tag/duck-curve/) - [**Loss of Load Expectation**](https://www.calregulatory.com/tag/loss-of-load-expectation/) - [**Risk-Based Decision-Making Framework**](https://www.calregulatory.com/tag/risk-based-decision-making-framework/) ## CRITICAL ASSETS & FLASHPOINTS - [**Aliso Canyon**](https://www.calregulatory.com/tag/aliso-canyon/) - [**Bioenergy** ](https://www.calregulatory.com/tag/bioenergy/) - [**Biofuels** ](https://www.calregulatory.com/tag/biofuels/) - [**Diablo Canyon**](https://www.calregulatory.com/tag/diablo-canyon/) - [**Hydrogen**](https://www.calregulatory.com/tag/hydrogen/) - [ARCHES](https://www.calregulatory.com/tag/arches/) ## INFRASTRUCTURE - [**Advanced Metering Infrastructure**](https://www.calregulatory.com/tag/advanced-metering-infrastructure/)**/**[**AMI**](https://www.calregulatory.com/tag/ami/) - [**CPCN**](https://www.calregulatory.com/tag/cpcn/) - [**Crude Oil Transportation**](https://www.calregulatory.com/tag/crude-oil-transportation/) ## INSTITUTIONS and AGENCIES - [**CAISO**](https://www.calregulatory.com/tag/caiso/) - [**CARB**](https://www.calregulatory.com/tag/carb/) - [**CEC**](https://www.calregulatory.com/tag/cec/) - [IEPR](https://www.calregulatory.com/tag/iepr/) - [**CPUC**](https://www.calregulatory.com/tag/cpuc/) - [Energy Division](https://www.calregulatory.com/tag/energy-division/) - [Safety Policy Division](https://www.calregulatory.com/tag/safety-policy-division/) - [**FERC**](https://www.calregulatory.com/tag/ferc/) - [**PHMSA**](https://www.calregulatory.com/tag/phmsa/) ## MARKETS + ENTITIES - [**Cap and Trade**](https://www.calregulatory.com/tag/cap-and-trade-2/)**/**[**Cap and Invest** ](https://www.calregulatory.com/tag/cap-and-invest/) - [**Community Choice Aggregators**](https://www.calregulatory.com/tag/community-choice-aggregators/)**/**[**CCAs**](https://www.calregulatory.com/tag/ccas/) - [CalCCA](https://www.calregulatory.com/tag/calcca/) - [Clean Energy Alliance](https://www.calregulatory.com/tag/clean-energy-alliance/) - [Clean Power Alliance](https://www.calregulatory.com/tag/clean-power-alliance/) - [East Bay Community Energy](https://www.calregulatory.com/tag/east-bay-community-energy/) - [San Diego Community Power](https://www.calregulatory.com/tag/san-diego-community-power/) - [Sonoma Clean Power](https://www.calregulatory.com/tag/sonoma-clean-power/) - [**Data Centers**](https://www.calregulatory.com/tag/data-centers/) - [**Direct Access**](https://www.calregulatory.com/tag/direct-access/) - [**EDAM**](https://www.calregulatory.com/tag/edam/) - [**Investor-Owned Utilities**](https://www.calregulatory.com/tag/investor-owned-utilities/)/[**IOUs**](https://www.calregulatory.com/tag/ious/) - [PG&E](https://www.calregulatory.com/tag/pg-e/) - [SCE](https://www.calregulatory.com/tag/sce/) - [SDG&E](https://www.calregulatory.com/tag/sdg-e/) - [SoCalGas](https://www.calregulatory.com/tag/socalgas/) ## OPERATIONS & EMERGENCY PROTOCOLS - [**Flex Alert**](https://www.calregulatory.com/tag/flex-alert/) - [**Natural Gas Curtailment**](https://www.calregulatory.com/tag/natural-gas-curtailment/) - [**Public Safety Power Shutoff**](https://www.calregulatory.com/tag/public-safety-power-shutoff/)**/**[**PSPS**](https://www.calregulatory.com/tag/psps/) ## POLICY DOMAINS - [**Affordability**](https://www.calregulatory.com/tag/affordability/) - [Disadvantaged Communities ](https://www.calregulatory.com/tag/disadvantaged-communities/) - [**Biomethane**](https://www.calregulatory.com/tag/biomethane/)**/**[**Renewable Natural Gas**](https://www.calregulatory.com/tag/renewable-natural-gas/) - [**Building Decarbonization**](https://www.calregulatory.com/tag/building-decarbonization/) - [**Demand Flexibility**](https://www.calregulatory.com/tag/demand-flexibility/)**/**[**Load Flexibility** ](https://www.calregulatory.com/tag/load-flexibility/) - [**Demand Response**](https://www.calregulatory.com/tag/demand-response/) - [**Distributed Energy Resources**](https://www.calregulatory.com/tag/distributed-energy-resources/)**/**[**DERs**](https://www.calregulatory.com/tag/ders/) - [DERMS](https://www.calregulatory.com/tag/derms/) - [High DER Future](https://www.calregulatory.com/tag/high-der-future/) - [Virtual Power Plant](https://www.calregulatory.com/tag/virtual-power-plant/) - [**Distribution Planning** ](https://www.calregulatory.com/tag/distribution-planning/) - [**Electric Vehicles**](https://www.calregulatory.com/tag/electric-vehicles/)**/**[**Transportation Electrification** ](https://www.calregulatory.com/tag/transportation-electrification/) - [EV Charging](https://www.calregulatory.com/tag/ev-charging/) - [Vehicle Grid Integration](https://www.calregulatory.com/tag/vehicle-grid-integration-2/) - [Vehicle to Everything](https://www.calregulatory.com/tag/vehicle-to-everything/) - [**Energy Efficiency**](https://www.calregulatory.com/tag/energy-efficiency/) - [**Energy Storage** ](https://www.calregulatory.com/tag/energy-storage/)**/**[**Long-Duration Storage**](https://www.calregulatory.com/tag/long-duration-storage/) - [**Microgrids**](https://www.calregulatory.com/tag/microgrids/) - [Microgrid Incentive Program](https://www.calregulatory.com/tag/microgrid-incentive-program/) - [**Natural Gas Storage**](https://www.calregulatory.com/tag/natural-gas-storage/) - [**Reliability**](https://www.calregulatory.com/tag/reliability-2/)**/**[**Resilience**](https://www.calregulatory.com/tag/resiliency/) - [Nuclear](https://www.calregulatory.com/tag/nuclear/) - [**Renewables**](https://www.calregulatory.com/tag/renewables/)**/**[**RPS**](https://www.calregulatory.com/tag/rps/) - [BioMat](https://www.calregulatory.com/tag/biomat/) - [Geothermal](https://www.calregulatory.com/tag/geothermal/) - [Hydroelectric](https://www.calregulatory.com/tag/hydroelectric/) - [Solar](https://www.calregulatory.com/tag/solar/) - [Solar PV](https://www.calregulatory.com/tag/solar-pv/) - [Wind](https://www.calregulatory.com/tag/wind/) - [**Transmission**](https://www.calregulatory.com/tag/transmission/) - [Rule 30](https://www.calregulatory.com/tag/rule-30/) - [TACBAA](https://www.calregulatory.com/tag/tacbaa/) - [**Wildfires**](https://www.calregulatory.com/tag/wildfires/) - [Resolution SPD-37](https://www.calregulatory.com/tag/resolution-spd-37/) - [Undergrounding](https://www.calregulatory.com/tag/undergrounding/) - [Vegetation Management](https://www.calregulatory.com/tag/vegetation-management/) - [Wildfire Mitigation](https://www.calregulatory.com/tag/wildfire-mitigation/) - [Wildfire Mitigation Plan](https://www.calregulatory.com/tag/wildfire-mitigation-plan/) - [**Zonal Electrification**](https://www.calregulatory.com/tag/zonal-electrification/) ## PROGRAMS, MECHANISMS, TOOLS - [**Avoided Cost Calculator**](https://www.calregulatory.com/tag/avoided-cost-calculator/) - [**LCFS**](https://www.calregulatory.com/tag/lcfs/)**/**[**Low Carbon Fuel Standard**](https://www.calregulatory.com/tag/low-carbon-fuel-standard/) - [**Market Price Benchmark**](https://www.calregulatory.com/tag/market-price-benchmark/) - [**Non-Bypassable Charge** ](https://www.calregulatory.com/tag/non-bypassable-charge/) - [**PPP**](https://www.calregulatory.com/tag/ppp/)**/**[**Public Purpose Program**](https://www.calregulatory.com/tag/ppp/) - [CARE](https://www.calregulatory.com/tag/care/) - [ESA](https://www.calregulatory.com/tag/esa/) - [FERA](https://www.calregulatory.com/tag/fera/) - [RD&D](https://www.calregulatory.com/tag/rd-d/) - [Self-Generation Incentive Program](https://www.calregulatory.com/tag/self-generation-incentive-program/)/[SGIP](https://www.calregulatory.com/tag/sgip/) - [**Reliable and Clean Power Procurement Program** ](https://www.calregulatory.com/tag/reliable-and-clean-power-procurement-program-2/) - [**Renewable Energy Credits**](https://www.calregulatory.com/tag/renewable-energy-credits/)**/**[**RECs**](https://www.calregulatory.com/tag/rec/) ## RATES - [**Cost Allocation Proceeding**](https://www.calregulatory.com/tag/cost-allocation-proceeding/) - [**Cost of Capital**](https://www.calregulatory.com/tag/cost-of-capital/) - [ROE](https://www.calregulatory.com/tag/roe/) - [Yield Spread Adjustment](https://www.calregulatory.com/tag/yield-spread-adjustment/) - [**Electricity Rates**](https://www.calregulatory.com/tag/electricity-rates/) - [Net Energy Metering](https://www.calregulatory.com/tag/net-energy-metering/)/[NEM](https://www.calregulatory.com/tag/net-energy-metering/) - [NBT](https://www.calregulatory.com/tag/nbt/)/[Net Billing Tariff](https://www.calregulatory.com/tag/net-billing-tariff/) - [Volumetric Performance Fee](https://www.calregulatory.com/tag/volumetric-performance-fee/) - [**ERRA**](https://www.calregulatory.com/tag/erra/)**/**[**ERRA COMPLIANCE**](https://www.calregulatory.com/tag/erra-compliance-2/)**/**[**ERRA Forecast**](https://www.calregulatory.com/tag/erra-forecast/) - [PABA](https://www.calregulatory.com/tag/paba/)/[Portfolio Allocation Balancing Account](https://www.calregulatory.com/tag/portfolio-allocation-balancing-account/) - [**Gas Cost Allocation Proceeding**](https://www.calregulatory.com/tag/gas-cost-allocation-proceeding/)**/**[**GCAP**](https://www.calregulatory.com/tag/gcap/) - [**Gas Transmission & Storage**](https://www.calregulatory.com/tag/gas-transmission-storage/)**/**[**GT&S**](https://www.calregulatory.com/tag/gt-s/) - [Backbone Transportation Service](https://www.calregulatory.com/tag/backbone-transportation-service/)/[BTS](https://www.calregulatory.com/tag/bts/) - [Baja Path](https://www.calregulatory.com/tag/baja-path/) - [TIMP](https://www.calregulatory.com/tag/timp/)/[TIMPBA](https://www.calregulatory.com/tag/timpba/) - [**GCARD**](https://www.calregulatory.com/tag/gcard/) - [**General Rate Case**](https://www.calregulatory.com/tag/general-rate-case/)**/**[**GRC**](https://www.calregulatory.com/tag/grc/) - [O&M](https://www.calregulatory.com/tag/o-m/) - [**Natural Gas Rates**](https://www.calregulatory.com/tag/natural-gas-rates/) - [GCIM](https://www.calregulatory.com/tag/gcim/) - [**PCIA**](https://www.calregulatory.com/tag/pcia/) - [**RAMP**](https://www.calregulatory.com/tag/ramp/) ## RECURRING INTERVENORS - [**Alliance for Nuclear Responsibility**](https://www.calregulatory.com/tag/alliance-for-nuclear-responsibility/) - [**AReM**](https://www.calregulatory.com/tag/arem/) - [**Bioenergy Association of California**](https://www.calregulatory.com/tag/bioenergy-association-of-california/) - [**Bloom Energy**](https://www.calregulatory.com/tag/bloom-energy/) - [**Cal Advocates**](https://www.calregulatory.com/tag/cal-advocates/) - **Center for Accessible Technology/CforAT** - [**Central Valley Gas Storage**](https://www.calregulatory.com/tag/central-valley-gas-storage/) - [**City of Long Beach**](https://www.calregulatory.com/tag/city-of-long-beach/) - [**CLECA**](https://www.calregulatory.com/tag/cleca/) - [**Energy Producers & Users Coalition**](https://www.calregulatory.com/tag/energy-producers-and-users-coalition/)**/**[**EPUC**](https://www.calregulatory.com/tag/epuc/) - [**Indicated Shippers**](https://www.calregulatory.com/tag/indicated-shippers/) - [**Lodi Gas Storage**](https://www.calregulatory.com/tag/lodi-gas-storage/) - [**NRDC**](https://www.calregulatory.com/tag/nrdc/) - [**San Luis Obispo Mothers for Peace**](https://www.calregulatory.com/tag/san-luis-obispo-mothers-for-peace/) - [**Sierra Club**](https://www.calregulatory.com/tag/sierra-club/) - [**Small Business Utility Advocates**](https://www.calregulatory.com/tag/small-business-utility-advocates/) - [**Southern California Generation Coalition**](https://www.calregulatory.com/tag/southern-california-generation-coalition/) - [**TURN**](https://www.calregulatory.com/tag/turn/) - [**Utility Consumers Action Network**](https://www.calregulatory.com/tag/utility-consumers-action-network-2/) ## STATUTES - [**Assembly Bill 32**](https://www.calregulatory.com/tag/assembly-bill-32/) - [**Assembly Bill 205**](https://www.calregulatory.com/tag/assembly-bill-205/) - [**Assembly Bill 1054**](https://www.calregulatory.com/tag/assembly-bill-1054/) - [**Assembly Bill 1207**](https://www.calregulatory.com/tag/assembly-bill-1207/) - [**CEQA**](https://www.calregulatory.com/tag/ceqa/) - [**Powering Up Californians Act**](https://www.calregulatory.com/tag/powering-up-californians-act/)**/**[**Senate Bill 410**](https://www.calregulatory.com/tag/senate-bill-410/) - [**Public Utilities Code**](https://www.calregulatory.com/tag/public-utilities-code/) - [**PURPA**](https://www.calregulatory.com/tag/purpa/) - [**Senate Bill 100**](https://www.calregulatory.com/tag/senate-bill-100/) - [**Senate Bill 254**](https://www.calregulatory.com/tag/senate-bill-254/) - [**Senate Bill 520**](https://www.calregulatory.com/tag/senate-bill-520/) - [**Senate Bill 846**](https://www.calregulatory.com/tag/senate-bill-846/) - [**Senate Bill 884**](https://www.calregulatory.com/tag/senate-bill-884/) - [**Senate Bill 1137**](https://www.calregulatory.com/tag/senate-bill-1137/) - [**Senate Bill 1221**](https://www.calregulatory.com/tag/senate-bill-1221/) ## SYSTEM PLANNING & OBLIGATIONS - [**Energization**](https://www.calregulatory.com/tag/energization/) - [Flexible Service Connection](https://www.calregulatory.com/tag/flexible-service-connection/) - [**Integrated Resource Planning**](https://www.calregulatory.com/tag/integrated-resource-planning/)**/**[**IRP**](https://www.calregulatory.com/tag/irp/) - [**Interconnection**](https://www.calregulatory.com/tag/interconnection/) - [Rule 2](https://www.calregulatory.com/tag/rule-2/) - [Rule 15](https://www.calregulatory.com/tag/rule-15/) - [Rule 21](https://www.calregulatory.com/tag/rule-21/) - [**Long-Term Natural Gas Planning** ](https://www.calregulatory.com/tag/long-term-natural-gas-planning/) - [**Provider of Last Resort**](https://www.calregulatory.com/tag/provider-of-last-resort/) - [**Procurement**](https://www.calregulatory.com/tag/procurement/) - [Mid-Term Reliability ](https://www.calregulatory.com/tag/mid-term-reliability/) - [**Resource Adequacy**](https://www.calregulatory.com/tag/resource-adequacy/) - [Slice of Day](https://www.calregulatory.com/tag/slice-of-day/) ## TECHNOLOGY - [**AI**](https://www.calregulatory.com/tag/ai/) - [**Fuel Cell**](https://www.calregulatory.com/tag/fuel-cell/) - [**Lithium-Ion Battery**](https://www.calregulatory.com/tag/lithium-ion-battery/) - [**SCADA**](https://www.calregulatory.com/tag/scada/) ### Contact Us URL: https://www.calregulatory.com/contact-us/ Last updated: 2025-10-23T19:42:02.000Z **California Regulatory Intelligence (CRI)** 1484 Pollard Road, #3013 Los Gatos, CA 95032 **Michael Cade/Principal Analyst** [mike@calregulatory.com](mailto:mike@calregulatory.com) **General Inquiries** [info@calregulatory.com](mailto:info@calregulatory.com) (503) 208‑4233 ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/09/salt-1-3.png) ### CPUC Voting Meeting Results URL: https://www.calregulatory.com/cpuc-voting-meeting-results/ Last updated: 2026-09-08T19:09:54.000Z ### [September 3, 2026](https://www.calregulatory.com/september-3-2026-cpuc-voting-meeting-results-grc-overhaul-fire-threat-maps-and-iou-financing/) - **GENERAL RATE CASE FRAMEWORK:** The CPUC [voted 5-0](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-to-consider-updates-to-rate-case-process?ref=calregulatory.com) to open [a rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M615/K919/615919167.PDF?ref=calregulatory.com) to comprehensively update its General Rate Case Plan for utilities, which has not been fully revised since 2007. - **PG&E CAPITAL STRUCTURE**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M616/K877/616877851.PDF?ref=calregulatory.com) partially grants PG&E’s request to exclude certain costs from its regulatory capital structure. - **AVOIDED COST CALCULATOR:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M616/K868/616868986.PDF?ref=calregulatory.com) adopts changes to the CPUC's Avoided Cost Calculator beginning with the 2026 ACC. The model will use a single electricity-based greenhouse gas value for both electric and natural gas resources. - **HIGH DER GRID MODERNIZATION**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M616/K887/616887513.PDF?ref=calregulatory.com) cuts Integration Capacity Analysis workshops from quarterly to every six months beginning in the first quarter of 2027, aligning the workshops with the existing biannual ICA reports. - **WILDFIRE MITIGATION**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M617/K264/617264597.PDF?ref=calregulatory.com) approves SCE’s request to add 47 areas totaling about 208 square miles to the High Fire-Threat District but denies its proposal to remove 61 areas totaling about 168 square miles. - **UTILITY FINANCES:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M613/K032/613032078.PDF?ref=calregulatory.com) authorizes SDG&E to issue up to **$2.583 billion** in new long-term debt and another **$1.348 billion** in roll-over debt, for **$3.931 billion** in new authority on top of unused prior amounts. - **PIPELINE RATES/PETROLEUM TRANSPORTATION:** [Resolution O-0101](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M615/K007/615007608.PDF?ref=calregulatory.com) approves a 10% rate increase for crude shipments on Torrance Basin Pipeline Co.’s M-131 line, raising the tariff to **$0.5122/barrel**. The rate has been in effect since December 1, 2025, under a statutory process allowing oil pipelines to implement noticed rate changes before CPUC approval. - **CLEAN MILES STANDARD:** The CPUC adopted its [Phase 2 Clean Miles Standard decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M616/K868/616868920.PDF?ref=calregulatory.com), continuing exemptions for autonomous-vehicle passenger services and rides provided under charter-party carrier permits. --- ### [August 13, 2026](https://www.calregulatory.com/august-13-2026-cpuc-voting-meeting-results/) - **ELECTRIC RELIABILITY:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K125/614125926.PDF?ref=calregulatory.com) requires PG&E, SCE and SDG&E to use a unified template for reporting customer-level distribution reliability beginning in **2027**. - **WILDFIRES**: [Resolution SED-13](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M610/K764/610764138.pdf?ref=calregulatory.com) approves a **$22 million** shareholder-funded settlement between the CPUC's Safety and Enforcement Division (SED) and PG&E resolving potential enforcement claims arising from the [2022 Mosquito Fire](https://en.wikipedia.org/wiki/Mosquito%5FFire?ref=calregulatory.com). - **LOW CARBON FUEL STANDARD**: [Resolution E-5463](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K580/614580847.PDF?ref=calregulatory.com) approves, with modifications, PG&E, SCE and SDG&E's proposal to streamline CPUC review of programs funded by LCFS credit revenue. - **NATURAL GAS INFRASTRUCTURE**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K134/614134939.PDF?ref=calregulatory.com) allows PG&E to withdraw its application for a **$93.5 million** electrical-upgrade project at the Hinkley Compressor Station. - **GAS SYSTEM RELIABILITY:** [Resolution G-3620](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M613/K623/613623039.PDF?ref=calregulatory.com) approves SoCalGas' gas purchases and sales to maintain minimum flows and reliability on its Southern System from October 1, 2024, through September 30, 2025\. The resolution also revises Rule 41 to give SoCalGas greater procurement flexibility in a less-liquid gas market. - **UTILITY FINANCES**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M611/K106/611106832.PDF?ref=calregulatory.com) grants PG&E half of its requested increase in short-term borrowing authority, raising the cap by **$1 billion** to **$9.5 billion** rather than the requested $10.5 billion. - **ARREARAGES**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K468/614468742.PDF?ref=calregulatory.com) requires PG&E, SCE, SDG&E and SoCalGas to continue offering their Arrearage Management Payment (AMP) plans to eligible residential customers until February 1, 2027\. This extends the program beyond its current October 1, 2026, sunset date. - **HYDROELECTRIC ASSETS**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M612/K823/612823522.PDF?ref=calregulatory.com) authorizes SCE to sell the 2.5-MW Lower Tule Hydroelectric Plant in Tulare County to Lower Tule Hydro. The century-old plant has been offline since 2017 because of wildfire damage and would require substantial refurbishment, - **CORPORATE RESTRUCTURING**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K515/609515710.PDF?ref=calregulatory.com) authorizes SoCalGas and SDG&E to create Sempra California LLC as an intermediate holding company between Sempra and the utilities' existing parent companies, Enova Corporation and Pacific Enterprises. --- ### [July 16, 2026](https://www.calregulatory.com/july-16-2026-cpuc-voting-meeting-results-2/) - **DISCONNECTIONS & RECONNECTIONS:** [Resolution E-5468](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M610/K667/610667282.pdf?ref=calregulatory.com) lowers the extreme-heat thresholds at which PG&E, SCE and SDG&E must suspend residential electric disconnections for nonpayment. - **NATURAL GAS STORAGE INTEGRITY:** [Resolution G-3616](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M610/K428/610428497.pdf?ref=calregulatory.com) grants SoCalGas authority to recover about **$54.4 million** from ratepayers for undercollected costs in its Storage Integrity Management Program Balancing Account for the 2019-2023 rate case cycle, with the balance measured through December 2024. - **RENEWABLES PROCUREMENT/MID-TERM RELIABILITY**: [Resolution E-5470](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K580/609580804.PDF?ref=calregulatory.com) approves PG&E’s amendments to two power purchase agreements with Atlas Solar XII and Atlas Solar XIII for the Atlas Solar North 1 and Atlas Solar North 2 projects in La Paz, Arizona. - **TRANSMISSION INFRASTRUCTURE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M611/K142/611142025.pdf?ref=calregulatory.com) grants PG&E a CPCN for the [Northern San Joaquin 230-kV Transmission Project](https://ia.cpuc.ca.gov/environment/info/ascent/NSJTP/index.html?ref=calregulatory.com), a reliability upgrade looping the Brighton-Bellota line through Lockeford Substation. - **PG&E FACILITY RELOCATION CONTRACTS**: Two resolutions address PG&E Actual Cost Contracts under Electric Rule 15.I.3’s Exceptional Cases provision for large utility-facility relocation work requested by third-party developers or contractors. - [Resolution E-5465](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K614/609614981.PDF?ref=calregulatory.com) covers work for KB Home South Bay’s Phase 3 commercial and residential condominium development near Communications Hill Boulevard in San Jose. - [Resolution E-5462](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K675/609675623.PDF?ref=calregulatory.com) covers work for Clark & Sullivan Construction and Broward Builders, Inc., a joint venture building a new California Highway Patrol office in Quincy. --- ### [July 2, 2026](https://www.calregulatory.com/july-2-cpuc-voting-meeting-results-pg-e-2-6b-capital-structure-decision-delayed-somah-expansion-denied/) - **RESOURCE ADEQUACY:** [A decision ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K912/609912508.pdf?ref=calregulatory.com)sets CAISO's recommended Local Capacity Requirements at **23,618 MW** for 2027, **24,545 MW** for 2028, and **25,480 MW** for 2029\. The decision also adopts CAISO's 2027 Flexible Capacity Requirements, which reach their system-wide maximum in March at **30,378 MW**, with the CPUC-jurisdictional share at **29,063 MW**. - **SENATE BILL 1221:** A[decision](https://www.calregulatory.com/sb-1221-cpuc-adopts-gas-decommissioning-pilot-framework-consent-rules-loosened-cost-shift-questions-remain/) establishes the application process for [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com&%5F%5Fcf%5Fchl%5Ff%5Ftk=vH6VhsGImisFwjXVTonIlzaoZljDakbxjCBkn7woSC0-1783030753-1.0.1.1-Z4IltYS2%5FzjmxZ1JtptD6o11Q0Iz2Wp4smW7RpS52FA) neighborhood decarbonization pilots. - **CUSTOMER-SITED SOLAR**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K896/609896162.pdf?ref=calregulatory.com) declines to expand the [Solar on Multifamily Affordable Housing](https://calsomah.org/?ref=calregulatory.com) program to new-construction, under-construction, or master-metered affordable multifamily properties. - **DEMAND RESPONSE:** Five demand-response resolutions approve targeted enrollment and AutoDR changes while rejecting larger mid-cycle incentive and program-design revisions. - [Resolution E-5456](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K910/609910285.PDF?ref=calregulatory.com) gives SCE approval to let customers enroll directly in its Capacity Bidding Program Elect, with SCE acting as aggregator. - [Resolution E-5444](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K735/609735577.PDF?ref=calregulatory.com) denies SDG&E approval for a new residential Capacity Bidding Program. - [Resolution E-5450](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K905/609905133.PDF?ref=calregulatory.com) gives PG&E partial approval for changes to its Automated Response Technology program. - [Resolution E-5451](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K618/609618815.PDF?ref=calregulatory.com) gives PG&E partial approval for mid-cycle updates to its [Base Interruptible Program](https://www.pge.com/assets/pge/docs/save-energy-and-money/energy-savings-programs/bip-fact-sheet.pdf?ref=calregulatory.com). - [Resolution E-5453](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K718/609718550.PDF?ref=calregulatory.com) approves, with modifications, a joint PG&E and SCE request to update their Automated Demand Response Technology Incentive Program guidelines. - **LOW-INCOME SUBSIDIES:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K723/609723761.pdf?ref=calregulatory.com) authorizes 2027 bridge-year budgets for the four major investor-owned utilities' income-qualified programs ([CARE, FERA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com) and [ESA](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/energy-savings-assistance?ref=calregulatory.com)) while leaving broader disputes for the 2028-2033 full-cycle applications pending. - **TRANSMISSION/INFRASTRUCTURE PERMITTING:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K222/607222555.PDF?ref=calregulatory.com) grants PG&E a permit to construct the Moraga-Oakland X 115-kV Rebuild Project, which would replace four circuits built between 1908 and 1931 that serve about 200,000 customers, including the Port of Oakland. - **NATURAL GAS/RATE RECOVERY:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K866/608866484.PDF?ref=calregulatory.com) approves a [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K874/608874865.pdf?ref=calregulatory.com) authorizing SDG&E to recover **$6.985 million** recorded in its Transmission Integrity Management Program Balancing Account for 2019-2023. --- ### [June 11, 2026](https://www.calregulatory.com/june-11-cpuc-voting-meeting-results-commission-makes-socalgas-shareholders-pay-for-safety-fixes/) - **UTILITY SAFETY:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K379/608379820.pdf?ref=calregulatory.com) approves SoCalGas's "Revised Safety Culture Improvement Plan" as a foundation for implementation, while explicitly declining to find the plan's specific interventions adequate or effective. - **UTILITY-OWNED GENERATION:** [Resolution E-5467](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K379/608379816.pdf?ref=calregulatory.com) approves SDG&E's Membership Interest Purchase Agreement to acquire [Westside Canal Phase 2a](https://ceqanet.lci.ca.gov/2020040122/4?ref=calregulatory.com) from [RWE](https://www.rwe.com/en/?ref=calregulatory.com) for **$267.9 million**, with RWE retained for operations and maintenance under a 10-year services agreement. The project is a **119 MW**, four-hour lithium-ion storage facility in Imperial Valley. - **SHARED RENEWABLES:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K372/608372079.PDF?ref=calregulatory.com) implements the California Shared Renewables Portfolio in a form far more limited than community solar advocates sought. A **$33 million** state appropriation reverted to the General Fund in June 2025, and the EPA terminated California's [Solar for All](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/state-of-california-solar-for-all-program?ref=calregulatory.com) award in August 2025, eliminating the external funding that a 2024 decision ([D.24-05-065](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M533/K188/533188781.PDF?ref=calregulatory.com)) assumed would make the program workable. - **REMAT PROGRAM:** [Resolution E-5457](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K150/608150933.pdf?ref=calregulatory.com) updates fixed avoided-cost prices for the CPUC's Renewable Market Adjusting Tariff program, the feed-in tariff for renewable generators of 3 MW or less. - **CORE TRANSPORT AGENTS:** [Resolution G-3621](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K566/608566014.pdf?ref=calregulatory.com) reaffirms the CPUC's 2026 annual fee structure for registered Core Transport Agents, keeping the base fee at **$5,000** while applying variable fees only to CTAs that generated consumer-protection costs in 2025. --- ### [May 14, 2026](https://www.calregulatory.com/may-14-cpuc-meeting-results-pg-e-reliability-assumptions-shift-wildfire-costs-repriced-and-diablo-oversight-changes-through-2030/) - **GAS SYSTEM RELIABILITY:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K932/604932014.PDF?ref=calregulatory.com) approves a full [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K724/605724316.pdf?ref=calregulatory.com) between PG&E and TURN resolving PG&E's updated Peak Day Supply Standard for winters 2024-2025 through 2026-2027. - **WOOLSEY FIRE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K621/606621820.PDF?ref=calregulatory.com) authorizes SCE to issue approximately **$1.951 billion** in Recovery Bonds to refinance costs arising from the 2018 Woolsey Fire. - **DIABLO CANYON:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K452/606452850.pdf?ref=calregulatory.com) partially grants a petition to modify a 2024 decision. The sole modification: for purposes of the 115% statutory threshold under the Public Utilities Code, the CPUC will use the final RA Market Price Benchmark rather than the forecast benchmark when evaluating whether Diablo Canyon costs remain insulated from further reasonableness review. - **CRUDE OIL TRANSPORTATION:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K439/606439113.pdf?ref=calregulatory.com) authorizes a **10%** rate increase for Crimson California Pipeline L.P.'s Southern California crude oil system. --- ### [April 30, 2026](https://www.calregulatory.com/april-30-cpuc-voting-meeting-results-biomethane-cut-hydrogen-denied-transmission-financing-opens/) - **BIOMETHANE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K801/605801938.PDF?ref=calregulatory.com) rebuilds the CPUC's Renewable Gas Standard around a hard cap on what ratepayers can be charged, not the volume targets that drove the original program**.** - **HYDROGEN:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com) denies SoCalGas's request to recover **$266 million** from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the [Angeles Link](https://www.socalgas.com/sustainability/innovation-center/angeles-link?ref=calregulatory.com) hydrogen pipeline project. - **TRANSMISSION:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K782/605782986.PDF?ref=calregulatory.com) conditionally authorizes PG&E to lease transmission "entitlements" to a Citizens Energy subsidiary. - **GENERAL RATE CASE**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K740/605740663.PDF?ref=calregulatory.com) resolves SCE's 2024 rate-design case. The decision approves nine of 10 settlements that parties negotiated and rejects the tenth, a Vehicle-to-Grid rate proposal. - **RISK ASSESSMENT:** A [successor docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com) launches to refine the [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com) that governs how utilities propose safety spending in GRCs. - **CLIMATE CREDIT:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K823/605823091.PDF?ref=calregulatory.com) orders interim, timing-only changes to the residential Climate Credit. - **ERRA COMPLIANCE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K456/605456157.pdf?ref=calregulatory.com) approves SDG&E's 2023 ERRA compliance application. - **DISTRIBUTED GENERATION**: [Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K799/605799271.pdf?ref=calregulatory.com) raises the [DGStats](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) budget from $990,000 to **$2.6 million** per three-year cycle and delegates annual inflation adjustment to Energy Division. --- ### [April 9, 2026](https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/) - **RATE DESIGN:** A [new rulemakin](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K776/601776967.PDF?ref=calregulatory.com)g provides the forum for a major reset of electricity rates. - **INTEGRATION CAPACITY ANALYSIS:** [Resolution E-5440](https://www.calregulatory.com/r/a4aa5e58?m=bb484012-a69a-425c-839a-750c0bd64e46) approves remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their [ICA](https://www.calregulatory.com/r/34db80bc?m=bb484012-a69a-425c-839a-750c0bd64e46) tools. - **ERRA COMPLIANCE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) approves SDG&E's 2023 Energy Resource Recovery Account compliance application. - **ENERGY STORAGE INVESTIGATION:** A [new investigation](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K525/604525374.PDF?ref=calregulatory.com) provides a forum to learn more about how long PG&E's Elkhorn Energy Storage System has been out of service. --- ### [March 19, 2026](https://www.calregulatory.com/march-19-2026-cpuc-voting-meeting-results-2/) - **TRANSMISSION INFRASTRUCTURE**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K738/602738106.PDF?ref=calregulatory.com) granting [LS Power Grid California](https://www.lspowergrid.com/utilities/ls-power-grid-california/?ref=calregulatory.com) a certificate to construct the [Power Santa Clara Valley Project](https://www.lspowergrid.com/wp-content/uploads/Power-Santa-Clara-Valley-2-Pager.pdf?ref=calregulatory.com), a **$1.593 billion** transmission upgrade. - A separate [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K351/599351814.PDF?ref=calregulatory.com) granting LS Power a CPCN to construct the [Power the South Bay Project](https://www.lspowergrid.com/wp-content/uploads/Power-the-South-Bay-2-Pager.pdf?ref=calregulatory.com), a 12-mile 230-kV transmission line connecting PG&E's Newark substation to [Silicon Valley Power](https://www.siliconvalleypower.com/?ref=calregulatory.com)'s Northern Receiving Station. - A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K823/602823258.pdf?ref=calregulatory.com) granting SCE a CPCN to construct the [Alberhill System Project](https://ia.cpuc.ca.gov/environment/info/ene/alberhill/Docs/CPUC%5FAlberhill%20System%20Project%20Staff%20Report%5F09152023.pdf?ref=calregulatory.com), a new 1,120 MVA 500/115 kV substation and associated transmission infrastructure in western Riverside County, at a cost cap of **$481.7 million** in 2023 dollars. - **DATA CENTERS:** [Resolution E-5447](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K207/602207312.pdf?ref=calregulatory.com), approving PG&E [Advice Letter 7653-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7653-E.pdf?ref=calregulatory.com), an agreement with [STACK Infrastructure](https://www.stackinfra.com/?ppc%5Fkeyword=stack%20infrastructure&gad%5Fsource=1&gad%5Fcampaignid=17068178771&gbraid=0AAAAACVjc4r35zmm0hA6afEsh5C%5FJYYDv&gclid=Cj0KCQjwve7NBhC-ARIsALZy9HU7WRkXmG%5Fsm5ngTUoAsZ4oQDHik5OqSjE7iAyzB9rW0hmLrRJYKLUaAotaEALw%5FwcB&ref=calregulatory.com) under the exceptional case provisions of Electric Rules 15 and 16. - [Resolution E-5433](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K365/602365009.pdf?ref=calregulatory.com), approving PG&E’s agreement to energize a [49 MW data center in Sunnyvale for Menlo Equities](https://therealdeal.com/san-francisco/2026/02/13/menlo-equities-toggles-to-data-center-plan-in-silicon-valley/?ref=calregulatory.com). - **CLIMATE CREDIT:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K742/602742724.pdf?ref=calregulatory.com) pausing the spring 2026 residential electric [Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) for PG&E, SCE, and SDG&E customers. - **FLEX ALERTS:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K742/602742657.pdf?ref=calregulatory.com) extending California's [Flex Alert](https://www.flexalert.org/?ref=calregulatory.com) paid media campaign through December 31, 2026, with a **$15 million** budget. - **PROVIDER OF LAST RESORT:** [Resolution E-5411](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K178/602178048.pdf?ref=calregulatory.com), denying SDG&E's request to preemptively establish a memorandum account to track incremental costs from a potential mass return of customers to Provider of Last Resort service. - **UTILITY FINANCES:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K762/602762078.pdf?ref=calregulatory.com) authorizing SCE to issue up to **$9.85 billion** in debt and **$1.155 billion** in preferred equity, $525 million less than originally requested after SCE voluntarily reconciled its forecast to its 2025 General Rate Case final decision. - **EV LOAD MANAGEMENT:** [Resolution E-5452](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K741/602741239.pdf?ref=calregulatory.com), approving SCE's ORCHARD program, a utility-orchestrated EV charging scheme funded by **$22.9 million** in [Low Carbon Fuel Standard](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification/charging-infrastructure-deployment-and-incentives/low-carbon-fuel-standard?ref=calregulatory.com) holdback revenue. - **RISK ASSESSMENT AND MITIGATION**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K740/602740008.pdf?ref=calregulatory.com) closing PG&E's 2024 RAMP ([A.24-05-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M531/K552/531552896.PDF?ref=calregulatory.com)), the front-end risk framework for its Test Year 2027 General Rate Case. - **SGIP**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K444/602444218.pdf?ref=calregulatory.com) denying [ENGIE North America](https://www.engie-na.com/?ref=calregulatory.com)’s [petition to modify](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K757/542757352.PDF?ref=calregulatory.com) a 2021 CPUC decision ([D.21-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M387/K064/387064243.PDF?ref=calregulatory.com)), which sought an exemption for wastewater treatment plants from the SGIP requirement that biogas used in internal combustion engines meet a **96%** methane standard. - **PETROLEUM PIPELINES**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K814/602814679.PDF?ref=calregulatory.com) approving Shell California Pipeline Company LLC's request to withdraw its Carson-to-LAX and Carson-to-Van Nuys petroleum pipelines from common carrier service and, upon satisfaction of specified conditions, terminate Shell California's status as a public utility entirely. - **CRUDE OIL TRANSPORTATION:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K430/602430281.pdf?ref=calregulatory.com) approving Crimson California's request to withdraw the southern segment of the Seal Beach Pipeline from public utility service. --- ### [February 26, 2026](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-results-president-alice-reynolds-final-meeting/) - **INTEGRATED RESOURCE PLANNING**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K854/600854771.pdf?ref=calregulatory.com) ordering California load-serving entities to undertake a new tranche of electric resource procurement for reliability during 2029–2032 while also transmitting recommended resource portfolios to the CAISO for the 2026–2027 transmission planning cycle. - **NATURAL GAS PRICE SPIKES**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K860/600860739.pdf?ref=calregulatory.com) in [Investigation 23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) concluding that the extraordinary spike in California natural gas prices during winter 2022–2023 resulted primarily from severe market conditions rather than misconduct by regulated utilities. - **EPIC**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K411/600411676.pdf?ref=calregulatory.com) adopting a comprehensive set of strategic objectives to guide the Electric Program Investment Charge Program’s 2026–2030 investment cycle, continuing the state’s ratepayer-funded energy innovation efforts while refining governance and accountability. - **VEHICLE-to-EVERYTHING PILOT**: [Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K860/600860735.pdf?ref=calregulatory.com) approving, with modifications, PG&E’s request to adjust its [Vehicle-to-Everything (V2X) Microgrid Pilot #3](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com), which is designed to test how bidirectional electric vehicles can support community microgrids during outages. - **MID-TERM RELIABILITY:** [Resolution E-5446](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K097/600097056.pdf?ref=calregulatory.com) approving two SDG&E mid-term reliability contracts with Golden Fields Solar VI, LLC ([Clearway](https://www.clearwayenergygroup.com/?ref=calregulatory.com)) for standalone battery storage projects totaling 92 MW of nameplate capacity, consisting of a 44 MW four-hour system and a 48 MW eight-hour system expected to begin deliveries on **June 1, 2027**. Both are 15-year power purchase tolling agreements. - **SELF-GENERATION INCENTIVE PROGRAM**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K055/600055458.pdf?ref=calregulatory.com) denying [Bloom Energy Corp.](https://www.bloomenergy.com/?ref=calregulatory.com)’s 2024 Petition for Modification of a 2011 decision ([D.11-09-015](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/143459.PDF?ref=calregulatory.com)), which governs aspects of the Self-Generation Incentive Program. Bloom sought to increase the program’s annual export cap from 25% to 50% of a project’s net generation, arguing that advancements in its fuel cell technology and evolving SGIP policies now justify greater exports to the grid. --- ### [February 5, 2026](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) - **ENERGIZATION**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K684/597684025.PDF?ref=calregulatory.com) in [R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com) directing PG&E and SCE to establish a standardized, tariffed “Standard Offer” Flexible Service Connection to accelerate energization for customers facing distribution capacity constraints. - **WILDFIRE COST RECOVERY:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K674/597674515.PDF?ref=calregulatory.com) granting partial approval of PG&E’s request to recover recorded costs related to wildfire mitigation, vegetation management, catastrophic events, and several programs, primarily incurred in 2022\. The decision authorizes recovery of **$1.607 billion**, largely reflecting wildfire mitigation activities, emergency storm response, and mandated program compliance, while denying **$172.5 million** in vegetation management costs. - **NATURAL GAS DISTRIBUTION INTEGRITY MANAGEMENT:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K021/597021734.PDF?ref=calregulatory.com) partially granting SoCalGas interim recovery of costs recorded in its Distribution Integrity Management Program Balancing Account for the 2019–2023 period. The decision authorizes **$35.5 million**, equal to **60%** of a [$59.1 million request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com), to be recovered over a 12-month period through interim rates. All interim collections are subject to refund with interest. - **CLEAN ENERGY CONTRACTS**: [Resolution E-5445](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673037.PDF?ref=calregulatory.com), which approves SCE’s request to enter into 10 clean energy contracts resulting from its 2024 Clean Energy Request for Offers. The approved portfolio totals **2,093 MW** of nameplate capacity across 10 contracts and four projects. - **UNION ISLAND PIPELINE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K675/597675451.PDF?ref=calregulatory.com) dismissing without prejudice California Resources Production Corporation's application seeking a Certificate of Public Convenience and Necessity to operate the Union Island natural gas pipeline as a public utility. - **CRUDE OIL TRANSPORTATION:** [Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673435.PDF?ref=calregulatory.com), which approves San Pablo Bay Pipeline Company and Crimson California Pipeline’s request for emergency, interim rate relief on the SPB-KLM intrastate crude oil pipeline system. And separately, [Resolution O-0099](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K079/595079380.PDF?ref=calregulatory.com) which approves Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations. --- ### [January 15, 2026](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) - **WILDFIRE MITIGATION**: An SDG&E General Rate Case Track 2 [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K094/595094639.pdf?ref=calregulatory.com) that disallows **$206.1 million** in O&M costs and **$242.5 million** in capital expenditures, while approving **$77.9 million** in O&M and **$945.5 million** in capital as reasonable and necessary wildfire mitigation investments. - **PROVIDER of LAST RESORT:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K952/594952727.pdf?ref=calregulatory.com) establishing a procedural framework for how non–investor-owned utilities may seek designation as a Provider of Last Resort (POLR) under Senate Bill 520, while declining to resolve hypothetical policy questions in the absence of a concrete applicant. - **SCE ERRA COMPLIANCE:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K913/594913852.pdf?ref=calregulatory.com) authorizing recovery of **$51.442 million** in undercollected balances across five accounts, mainly driven by Emergency Load Reduction Program costs. - **DATA CENTERS**: [Resolution E-5439](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K932/594932206.pdf?ref=calregulatory.com) approves PG&E’s request to facilitate transmission upgrades needed to energize a new 90-MW Microsoft data center in San Jose. - **MID-TERM RELIABILITY:** [Resolution E-5432](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K908/594908500.pdf?ref=calregulatory.com) authorizes PG&E to execute a third amendment to its existing 300-MW lithium-ion battery contract with [Nighthawk Energy Storage](https://www.nighthawkenergystorage.com/?ref=calregulatory.com), a subsidiary of [Arevon Energy](https://arevonenergy.com/?ref=calregulatory.com). Separately, [Resolution E-5437](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K136/594136007.pdf?ref=calregulatory.com) approves PG&E's execution of a new Mid-Term Reliability contract with Balsam Project, LLC, a subsidiary of [Aypa Power Development](https://www.aypa.com/?ref=calregulatory.com), for the 225-MW Dirac Battery Energy Storage System. - **NATURAL GAS RESEARCH**: [Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K045/595045490.pdf?ref=calregulatory.com) denies PG&E’s proposed Gas RD&D investment plans for 2024 and 2025, rejecting **$16.4 million** in requested funding and disallowing **$7.2 million** in cost recovery for RD&D expenses incurred in 2023–2024. - **PURPA:** [Resolution E-5425](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K021/594021941.pdf?ref=calregulatory.com) approves requests of PG&E and SDG&E to establish [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant export tariffs for customer-generation facilities that lose access to [Net Energy Metering or Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) due to prevailing wage violations under the Public Utilities Code. - **UTILITY SITE ACCESS:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K929/594929112.pdf?ref=calregulatory.com) allows SCE to outsource and monetize telecommunications site access on utility property under [General Order 69-C](https://www.cpuc.ca.gov/industries-and-topics/internet-and-phone/carrier-reporting-requirements/go-69-c-staff-data-request?ref=calregulatory.com) without filing a formal [Section 851](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-4/article-6/section-851/?ref=calregulatory.com) application. - **CRUDE OIL TRANSPORTATION:** [Resolution O-0100](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K523/594523250.pdf?ref=calregulatory.com) authorizes San Pablo Bay Pipeline Company, LLC to recover **$894,683** in retroactive charges for under-collected crude oil transportation rates from March 1, 2023 through February 28, 2024, consistent with a 2025 Decision ([D.25-06-044](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K971/571971447.PDF?ref=calregulatory.com)). - **ENERGY EFFICIENCY**: [Resolution E-5442](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K550/594550778.pdf?ref=calregulatory.com) certifies Peninsula Clean Energy Authority's request to renew and administer its Energy Efficiency [FLEXmarket program](https://www.peninsulacleanenergy.com/business/rebates-offers-business/flexmarket-program/?ref=calregulatory.com) for a new three-year term, from August 1, 2025 through **July 31, 2028**, under the "elect to administer" pathway. - **HYDRO SALE:** A decision approving SCE's application to sell the Lytle Creek and Fontana hydroelectric plants (3.45 MW combined) to Fontana Union Water Company. - **SDG&E MISCELLANEOUS COSTS**: [Resolution E-5405](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K543/594543939.pdf?ref=calregulatory.com) approves SDG&E’s request to recover non-officer compensation costs tied to the company's Vice President, People and Culture role, but reduces the request to **$282,983** in O&M expenses for Test Year 2024 after cutting employee food service costs and disallowing professional membership expenses --- ### [December 18, 2025](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/) - **COST of CAPITAL**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com) setting the authorized test-year 2026 cost of capital for PG&E, SoCalGas, SCE, and SDG&E, largely maintaining continuity with prior authorizations while rejecting utility requests for higher equity layers or structural adjustments. - **LONG-TERM GAS PLANNING**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234578.pdf?ref=calregulatory.com) designating California’s initial set of priority neighborhood decarbonization zones pursuant to [Senate Bill 1221](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/SB-1221-implementation?ref=calregulatory.com), satisfying the statutory requirement to act by **January 1, 2026**. The decision identifies 151 census tracts across multiple counties as initial zones, focusing primarily on areas where there is demonstrated local government or community support and a concentration of foreseeable gas distribution replacement projects. - **AFFORDABILITY:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K383/591383570.PDF?ref=calregulatory.com) updating and finalizing the CPUC’s affordability framework, narrowing mandatory affordability filings to General Rate Cases with revenue increases above one percent and closing the proceeding. - **WOOLSEY FIRE:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894945.pdf?ref=calregulatory.com) adopting a comprehensive settlement resolving SCE's request to recover costs associated with the November 2018 Woolsey Fire, which burned roughly 97,000 acres, destroyed or damaged more than 2,000 structures, and led to thousands of claims against the utility. - **2006 ERRA FORECASTS**: For PG&E, the Commission [adopts](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K260/591260654.PDF?ref=calregulatory.com) a 2026 gross ERRA-related revenue requirement of **$4.51 billion**, about 6% higher than 2025, while authorizing amortization of a sizable ERRA overcollection carried into year-end 2025\. For SCE, the Commission [approves](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234566.pdf?ref=calregulatory.com) a 2026 ERRA forecast revenue requirement of **$4.69 billion**, a 5% increase over 2025, reflecting updated fuel and purchased power costs, balancing account true-ups, greenhouse gas compliance costs, and revised portfolio assumptions. - **PG&E TRANSMISSION**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K266/591266530.pdf?ref=calregulatory.com) approving PG&E’s request to recover **$337.9 million** in recorded balances from its Transmission Revenue Requirement Reclassification Memorandum Account, which reflect the transfer of certain costs from FERC to CPUC jurisdiction following FERC Opinion No. 572 and the Transmission Owner 18 settlement. - **PG&E ADVANCED METERING INFRASTRUCTURE:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K833/584833313.PDF?ref=calregulatory.com) approving a [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) between PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates that resolves PG&E’s request to recover costs for its large-scale replacement of failing Gas Advanced Metering Infrastructure modules. - **DISTRIBUTION PLANNING:** Resolutions [E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234617.pdf?ref=calregulatory.com) and [E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K380/591380244.pdf?ref=calregulatory.com), establishing a coordinated upgrade to the investor-owned utilities' distribution planning framework by pairing a standardized pending loads construct with a formal scenario-planning methodology. - **RPS PROGRAM**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K248/591248385.pdf?ref=calregulatory.com) approving, with modifications, the 2025 Renewables Portfolio Standard procurement plans filed by investor-owned utilities, small and multi-jurisdictional utilities, community choice aggregators, and electric service providers. - **SELF-GENERATION INCENTIVE PROGRAM**: [Resolution E-5430](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894944.pdf?ref=calregulatory.com), approving with modifications updates to the SGIP that are intended to strengthen third-party ownership consumer protections and revise how federal tax credits are accounted for after recent federal law changes. - **SOCALGAS FINANCES**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K552/590552447.pdf?ref=calregulatory.com) authorizing SoCalGas to issue up to **$3.3 billion** in new debt, allowing a mix of secured and unsecured instruments and the use of standard hedging and derivative tools to manage interest-rate risk and financing costs. - **ON-BILL FINANCING:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K260/591260630.PDF?ref=calregulatory.com) authorizing a modified Tariff On-Bill Financing Pilot proposed by SCE and rejecting Tariff On-Bill proposals submitted by SDG&E, SoCalGas, and Silicon Valley Clean Energy. The decision finds that SCE’s pilot is sufficiently narrow, implementable, and protective of customers to justify a limited test of tariff-based, meter-tied cost recovery for residential energy efficiency and electrification upgrades --- ### [December 4, 2025](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/) - **UNDERGROUNDING**: [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) ,updating the CPUC’s [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). The resolution expands and tightens the review, cost-justification, and audit requirements established under [Resolution SPD-15](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com). - **IVANPAH SOLAR THERMAL FACILITY**: [Resolution E-5429](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K132/586132670.PDF?ref=calregulatory.com), rejecting PG&E’s proposal to buy out and terminate its Power Purchase Agreements with Solar Partners II and VIII (the owners of the [Ivanpah solar-thermal facility](https://en.wikipedia.org/wiki/Ivanpah%5FSolar%5FPower%5FFacility?ref=calregulatory.com)). - **DIABLO CANYON 2026 REVENUE REQUIREMENT**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K634/589634749.PDF?ref=calregulatory.com) approving PG&E’s 2026 revenue requirement to support the continued operation of Diablo Canyon under Senate Bill 846, authorizing **$382.233 million** in net costs after accounting for market revenues. Costs are allocated among PG&E, SCE, and SDG&E customers through a non-bypassable charge. - **SELF-GENERATION INCENTIVE PROGRAM**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K802/589802455.PDF?ref=calregulatory.com) establishing the full framework for shutting down the ratepayer-funded portion of the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) while implementing/defining the closeout process for the Greenhouse Gas Reduction Fund–supported SGIP. - **SDG&E PROCUREMENT COSTS:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K050/590050370.PDF?ref=calregulatory.com) approving SDG&E’s 2026 electric procurement revenue requirement, sales forecast, and greenhouse-gas related forecasts, adopting an updated total revenue requirement of **$824.1 million**, which is a major increase from the current $122.3 million authorization. This increase is driven by higher above-market portfolio costs reflected in SDG&E's Portfolio Allocation Balancing Account and updated market price benchmarks. - **WILDFIRE FUND NON-BYPASSABLE CHARGE**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K941/588941005.PDF?ref=calregulatory.com) setting the 2026 Wildfire Fund Non-Bypassable Charge at **$0.00591/kWh**, which enables collection of **$908.9 million** over the 2026 calendar year. - **TRANSPORTATION ELECTRIFICATION REPORTING**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K929/588929933.PDF?ref=calregulatory.com) revising how Transportation Electrification data is gathered and reported, streamlining numerous legacy reporting obligations into a single annual compliance report that will consolidate Senate Bill 350, Vehicle Grid Integration, electric vehicle cost/load, and other data. - **CLEAN ENERGY GRANTS**: [Resolution M-4881](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K706/585706309.pdf?ref=calregulatory.com), approving **$581,824** in Clean Energy Access: LA County TECH ([CEA-LAT](https://www.grants.ca.gov/grants/clean-energy-access-la-county-tech-grant/?ref=calregulatory.com)) grants for three community organizations: [Climate Resolve](https://climateresolve.org/?ref=calregulatory.com); [El Sol](https://www.elsolnec.org/?ref=calregulatory.com); and the [International Institute of Los Angeles](https://iilosangeles.org/?ref=calregulatory.com). --- ### [**November 20, 2025**](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/) - **ZONAL ELECTRIFICATION**: [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K799/587799131.PDF?ref=calregulatory.com) dismissing PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M496/K451/496451495.PDF?ref=calregulatory.com) for [a zonal electrification pilot at CSU Monterey Bay](https://csumb.edu/news/news-listing/east-campus-may-become-californias-largest-electrification-project/?ref=calregulatory.com) - **MOBILEHOME ELECTRIFICATION:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K925/587925783.PDF?ref=calregulatory.com) establishing a joint CPUC–California Energy Commission Mobilehome Park Electrification Initiative - **ENERGY EFFICIENCY:** Decision approving the [California Market Administrator](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K575/586575760.PDF?ref=calregulatory.com)'s first two statewide EE market-transformation initiatives: full approval for a [room heat-pump initiative](https://calmta.org/room-heat-pumps/?ref=calregulatory.com) and conditional approval for an [induction-cooking initiative](https://calmta.org/resourcereport/induction-cooking-mti-plan/?ref=calregulatory.com) - **AVOIDED COST CALCULATOR:** Decision revising the CPUC’s biennial [Avoided Cost Calculator](https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight?ref=calregulatory.com) update process - **DISTRIBUTED ENERGY RESOURCES:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K924/587924964.PDF?ref=calregulatory.com) denying the [California Efficiency + Demand Management Council](https://cedmc.org/?ref=calregulatory.com)’s [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M563/K203/563203670.PDF?ref=calregulatory.com) to modify a 2019 decision, which established the Total Resource Cost test as the Commission’s primary cost-effectiveness tool for DERs - **MID-TERM RELIABILITY:** Resolution E-5428, approving eight mid-term reliability contracts and one amendment submitted by SCE under its 2025 procurement plan. The portfolio includes solar-plus-storage projects in Kern and Riverside Counties and a solar project in Arizona, totaling about 498 megawatts, plus a 75-MW amendment to the [Gateway battery facility in San Diego](https://www.powermag.com/worlds-largest-for-now-battery-storage-project-online-in-california/?ref=calregulatory.com) - **CRUDE OIL TRANSPORTATION:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K610/584610997.PDF?ref=calregulatory.com) authorizing Crimson California Pipeline, LP to raise crude-oil transportation rates on its Southern System by 26.35%, retroactive to August 1, 2024, with interest. --- ### [**October 30, 2025**](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/) - **DATA CENTERS**: [Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K393/585393718.pdf?ref=calregulatory.com), approving (with modifications) PG&E’s request to construct and energize new transmission facilities (including a 115-kilovolt Ringwood substation) to serve [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com)’s 90-megawatt data center in San Jose - **NATURAL GAS CURTAILMENT PROCEDURES:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K107/582107583.PDF?ref=calregulatory.com) authorizing PG&E’s application to revise its natural gas curtailment procedures, which brings the company into alignment with procedures used by other major gas utilities. - **MID-TERM RELIABILITY:** [Resolution E-5419](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K971/584971007.pdf?ref=calregulatory.com), approving two offsetting bridge swap contracts between SCE and the [Clean Power Alliance](https://cleanpoweralliance.org/?ref=calregulatory.com) involving bundled [Portfolio Content Category 1](https://www.lawinsider.com/dictionary/portfolio-content-category-1?ref=calregulatory.com) (PCC-1) Renewable Energy Credits and associated energy. - **CONDEMNATION of PG&E ASSETS:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K350/585350481.PDF?ref=calregulatory.com) pausing a long-running dispute between PG&E and the [South San Joaquin Irrigation District](https://www.ssjid.gov/?ref=calregulatory.com) over who should control local power lines in that area. - **PROPERTY VALUATION of PG&E:** [Decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K484/585484645.pdf?ref=calregulatory.com) establishing the standards, appraisal methods, and filing requirements the CPUC will use to determine just compensation under California's eminent-domain process if the City and County of San Francisco condemns portions of PG&E’s electric system that serve San Francisco. - **ENERGIZATION:** [Decision](http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K484/585484420.pdf?ref=calregulatory.com) authorizing SDG&E to establish a new Electric Energization Memorandum Account to track incremental capital costs for customer energization projects under Senate Bill 410 (the [Powering Up Californians Act](https://www.nrdc.org/bio/max-baumhefner/powering-californians-act-signed-law?ref=calregulatory.com)). - **NATURAL GAS LEAK ABATEMENT:** [Resolution G-3606](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K066/585066732.pdf?ref=calregulatory.com), approving in part and denying in part SDG&E’s 2024 Natural Gas Leak Abatement Compliance Plan. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/09/lucid-origin_Begin_with_a_sparse_field_of_fine_parallel_lines_on_warm_white_paper._Let_the_li-0-1.jpg) ### What is CRI? URL: https://www.calregulatory.com/what-is-cri/ Last updated: 2026-05-11T19:44:00.000Z A single [CPUC](https://en.wikipedia.org/wiki/California%5FPublic%5FUtilities%5FCommission?ref=calregulatory.com) decision can move billions of dollars. But spotting relevant and actionable language in CPUC materials requires procedural fluency and the patience to sift through thousands of filings each year. **California Regulatory Intelligence (CRI)** is an independent regulatory intelligence service focused on near-real-time analysis of California energy regulation. We monitor, decode, and contextualize CPUC activity as it unfolds, translating dense filings and decisions into actionable insight for market participants and institutions. Launched in October 2025, CRI is already read by developers, investors, consultants, IOUs, Community Choice Aggregators, and leading California energy counsel. ### Coverage Focus CRI’s coverage centers on high-impact areas including: - Resource Adequacy; - Integrated Resource Planning; - Demand response and demand-side programs; - Distributed energy resources; - Long-term gas planning; - Electricity/natural gas rates; and - Cost of capital and utility finances We also provide selective coverage of related agencies and forums (including CAISO, CEC, CARB, and FERC) where developments intersect with California’s regulatory and market structure. ### Background & Approach CRI is built on nearly two decades representing Fortune 500 energy companies and major coalitions in contested CPUC proceedings. Our work emphasizes interpretive judgment – understanding how language, timing, and procedural posture shape real-world outcomes. We deliver curated intelligence, with speed and context. As California’s energy transition accelerates, regulatory complexity is increasing — not decreasing. CRI helps readers maintain situational awareness in an environment where missed signals carry significant economic and strategic consequences. *Proof of Value available* [*here*](https://www.calregulatory.com/proof-of-value/)*.* —[**Michael Cade**](https://www.linkedin.com/in/mikecade/?ref=calregulatory.com)**, Principal Analyst, CRI** ### December 18, 2025 CPUC Voting Meeting: Commissioner Remarks on Senate Bill 1221 Decarbonization Decision URL: https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-commissioner-remarks-on-senate-bill-1221-decarbonization-decision/ Last updated: 2025-12-19T00:02:33.000Z ### [Decision Designating Initial Priority Neighborhood Decarbonization Zones](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234578.pdf?ref=calregulatory.com) **(carried 5-0)** ### ### President Alice Reynolds - "A notable aspect of this program is the link between cost avoidance and investment, and this is what we and stakeholders have been discussing more on a theoretical level. But here we aim to achieve that goal, which has been really elusive in the past, and so I really appreciate that direct connection." - "Another area that we'll be exploring is how community partners can contribute to neighborhood acceptance and successful implementation. This decision does rely on an expression of local support as well as other factors in identifying initial neighborhood decarbonization zones, and that local support will be really essential as the pilots move forward, especially in disadvantaged communities." ### Commissioner John Reynolds - "Electrification and decarbonization projects are complex undertakings that require balancing the needs of many stakeholders, and we have a lot of work ahead to unlock a higher degree of electrification and decarbonization." - "These pilots are an essential step toward addressing a looming problem with the gas system. As customers electrify and stop paying for shared gas infrastructure, fixed costs can be shifted onto remaining customers, who may tend to be lower income, driving their rates up." - "This proposal also sets out a strategy for engagement with the disadvantaged and low-income communities that are part of the 30 projects identified in [SB 1221](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/SB-1221-implementation?ref=calregulatory.com). The proposal specifically directed utilities to solicit feedback from community partners and members of the public...including feedback on SB 1221: diversity and equity consideration, local environmental hazards, and community barriers to accessing decarbonization. These are laudable requirements. They promote electrification and decarbonization efforts that partner with communities instead of dictating to them." ### Commissioner Darcie Houck - "There are several other factors involved in determining the outcomes of these projects, other than gas pipelines and appliances to be replaced. For example, recently, we saw that [PG&E withdrew from its proposal for a zonal decarbonization project at CSU Monterey Bay](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/), so we want to make sure that we have the right information here to make sure that these projects are successful going forward." - "In addition, many low-income customers in rural areas and on tribal lands may have unreliable electric service being located on some of the state's worst performing electrical circuits. And these customers may lack resources to individually deal with the consequences of outages, and they regularly face longer outages than other customers, and that's the kind of information we're going to want to receive." - "Given the complexity of these projects and the high stakes for communities, it's critical that the decision designate zones that can result in real-world implementation of projects. I'm very supportive of the PD's direction to the utilities to conduct further community outreach, and the proposed decision's commitment to then update the initial list of decarbonization zones. This will be especially important so that we can meet the statutory requirement to consider the presence of disadvantaged or low-income communities and high (or low) temperature climate zones that disproportionately lack cooling or heating through this, and the requirement to consider the presence of environmental and social justice communities. I'm hoping that many of the projects will benefit communities that have historically experienced under-investment." - "Last, I want to note that this work complements other commission work being done in regards to community engagement and outreach, including through [energy efficiency](https://www.cpuc.ca.gov/energyefficiency/?ref=calregulatory.com), [Building Decarbonization](https://www.cpuc.ca.gov/about-cpuc/divisions/energy-division/building-decrbonization?ref=calregulatory.com), grid planning, and I hope that the utilities will be able to integrate what they learn here into these other complementary areas. " ### Commissioner Matthew Baker - "...this is only the first step, it's not the last step. And the retail natural gas system remains a critical energy source. You know, it does have a carbon problem – which we do have to deal with – but the implementation, implementation details really, really matter." ### December 18, 2025 CPUC Voting Meeting: Commissioner Remarks on Cost of Capital Decision URL: https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-commissioner-remarks-on-cost-of-capital-decision/ Last updated: 2025-12-19T03:37:44.000Z ### [Decision Addressing Test-Year 2026 Cost of Capital for PG&E, SoCalGas, SCE, and SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com) **(carried 4-1, Commissioner Houck dissents)** --- ### Commissioner John Reynolds - "Energy service is capital-intensive. The wires and poles, generators of transformers, pipelines and compressors of the labor and equipment required to put that capital into service are expensive. Customers don't pay for the cost of everything upfront, because many grid assets have a lifespan of 40 to 50 years. They can be financed. Utility companies can obtain and deploy capital to build these assets and recover the costs over time for customers. For customers, this financing means the cost of our universal service is spread out over time, but that time also adds an additional cost: the cost of the capital of the debt and equity used to fund the infrastructure built out up front, and that additional cost is the subject of this proposed decision." - "Specifically, this proposal sets the rate of return for California's large investor-owned utilities, which has been used as an important financial input across the PUC ratesetting proceedings. In setting the rate of return, the Commission works within a longstanding framework. Our decisions must follow legal requirements, and in making these determinations, we are bound by the law as defined by the Supreme Court, including decisions requiring that utilities' financial integrity requires enough revenue – not only for operating expenses – but also for the capital costs of the business." - "These capital costs include service on the debt and dividends on stock. The stockholders' return should be roughly equal with returns on investment in other businesses with corresponding risks. The return should also be sufficient to assure confidence in the financial integrity of the business so as to maintain its credit and attract capital." - "Utilities' maintaining credit ratings and attracting capital has a positive impact on customers. Lower costs to borrow money translates to lower ratepayer costs to pay for the long-lived assets that make up our energy infrastructure. Of the components that make up the rate of return, the return on equity is where much of the debate among parties lie. - "...the return on equity requires the Commission to determine what return is sufficient to attract equity investment, given the risks involved. The return on equity can get technical, including debates over proxy groups and financial models. I want to focus briefly on the balance this proposal strikes." - "The Commission has a duty to set just and reasonable rates. Every cost we authorize flows through to customers, and we must be disciplined in what we approve. At the same time, we must authorize returns sufficient to maintain financial integrity and attract the capital necessary for the utility to meet the service obligations – obligations that include substantial infrastructure investment in the coming years, and critical wildfire mitigation work, all of which will benefit customers. - "Some parties in this proceeding argue for significantly higher returns into the 11% range and above. Those parties that note that while California has real risks, we've also built substantial risk mitigation that other jurisdictions lack. Financial Risk mitigation – like the wildfire fund established under AB 1054 and expanded by SB 254 – represent over $20 billion in ratepayer backstop protection, a backstop that simply doesn't exist in other states where utilities face catastrophic event risk. - "We've authorized ratepayer-backed securitization that credit agencies consistently describe as credit-supportive, and utilities are investing billions in physical and operational mitigation: undergrounding, enhanced powerline safety settings...that they themselves have indicated have reduced their ignition risk by over 90%. And the regulatory environment supports those investments and continues to support the utilities advancing their safety cultures and maturing their safety management systems, efforts that will continue to expand our physical risk management beyond the considerable efforts to date. This isn't to minimize California's risk. It's to recognize that we've built risk management infrastructure in ways that should be reflected in this decision." - "Even with this decision, I would further note that the Cost of Capital mechanism allows for adjustments to the rate of return between rate cases if market conditions shift significantly, the kind of regulatory predictability that credit ratings agencies recognize as supportive." - "Some parties argued for returns on equity well below the national average, some below 7%. I think the proposed decision is correct to decline this advocacy as well. We need returns commensurate with risk and sufficient to attract capital. Setting returns too low doesn't just affect utility shareholders – it affects whether these companies can finance the great investment and wildfire mitigation work that customers depend on that impacts the grid service customers receive and impact the borrowing costs that customers pay." - "The mitigations I described are real and meaningful, but so is the risk, and so is the capital of these utilities need to attract, and that's the tension at the heart of this proceeding. Utilities have invested billions of dollars in mitigation and reduced the ignition risk by over 90% and yet devastating fires remind us that much work remains. Both of these things are true. The question for this commission is how to set a return on equity that reflects both of these realities, the progress made, and the risk that persists. This proposal reduces the authorized return on equity by 30 basis points from the current level. That's a meaningful reduction. It signals that California's risk mitigation is ensuring the wildfire fund is operational." - "Utilities have made real investments in hardening the systems and improving their operational risk mitigation. These aren't just theoretical protection. They're part of how California continues to manage utility risk. At the same time, this reduction reflects that the progress is incomplete. We're not yet at a place where California can be treated as equivalent to utilities in states without wildfire exposure. The reduction is calibrated, recognizing improvement without declaring victory." - "I think the decision gets it right, reducing the authorized return while maintaining the financial integrity required by law that recognizes both the real mitigation progress California has made and the real risks that remain – that the balance our duty requires and the balance our decision strikes." ### **Commissioner Matthew Baker** - "One of the most important investment market decisions made from the CPUC this year is today's decision on Cost of Capital. Approaching this decision, I found it helpful to think back to the words of [**Scott Hempling**](https://scotthemplinglaw.com/?ref=calregulatory.com), one of my mentors, and to really think like a simple-minded regulator – whose job it is to filter out the noise and focus on the fundamental mechanics of utility regulation – and at its core, that really just needs two things: make sure that the lights stay on and the people can afford to pay them. - "To achieve this, we rely on the foundational [*Hope and Bluefield* ](https://scholarworks.law.ubalt.edu/cgi/viewcontent.cgi?article=1274&context=lf&ref=calregulatory.com)standards...which ensure that utilities have to have an opportunity to earn a fair return comparable to similar risk investments at a just and reasonable rate. The proposed decision recommends a lower return on equity than what is now currently authorized. - "But I want to note that this decision is not made in isolation. Rather, it is the result of incorporating all the relevant perspectives and evidence from the record to ensure that the return is commensurate with today's market realities and risk profile. With that context, I looked at this through four contextual areas. - First, what constitutes a reasonable ROE to attract capital investment here in California? In other words, what is the opportunity cost of equity capital sufficient to motivate investors to fund necessary infrastructure for safe and reliable service? - The second is risk-based. Returns should be commensurate with the risk compared to other investments, whether it's a government bond or high-tech stock. And higher risk utilities should receive a higher ROE. - Third: ratepayer protection. Rates must not be excessive and must adhere to the just and reasonable standard while maintaining affordability for customers. - And finally, the financial viability. The utility must sustain its credit worthiness in order to support capital. - "All of these things make it in the public interest. And in many ways, California's electric utility future is very bright. The state's economy has grown to become the world's fourth largest economy. Our electric demand is forecasted to grow multiple times over over the next two decades. We remain a leader in clean-energy initiatives and infrastructure in deployment. These tailwinds create substantial growth opportunities in the utility sector, but they only provide half the picture. - "The other side is the electric system, and utilities that finance and operate the system face substantial wildfire-driven headwinds that increase cost, necessitate significant investments in wildfire risk mitigation, have led to higher borrowing and capital costs because these are associated with very California-specific facts and California specific wildfires. And these wildfires have led to very devastating events. They've led to higher insurance costs and billions in insurance liability and infrastructure costs that are borne by ratepayers. - "They also threatened by the viability of public utilities throughout the state. The presence of extensive overhead power lines and excessive fuel lines, combined with increasingly hot, dry conditions and strong winds creates ideal conditions for major wildfires. And...we've aggressively moved to mitigate the risk from these wildfires. Our utilities are fundamentally better prepared for catastrophic conditions today than they were in 2019. - "The commission has authorized historic levels of ratepayer funding specifically to prevent utility equipment from sparking fires, and because of this focus on safety and hardening, California now possesses what is arguably the most wildfire resilient grid in the world. - "But given the conditions that we're facing right now, this is still not enough. We have a lot more we need to do. And it is within this context of massive investment in safety balanced against a growing burden on ratepayers, that I want to return for a minute to the specifics of the decision. - "This proceeding has an extensive record, which the assigned judge used to determine a reasonable ROE range for each utility based on its specific risk profile. Using proxy groups, the proposed decisions weigh the evidence to determine the risk profile of the California IOUs compared to similar IOUs, and this decision falls within the established range, and I am supporting the provisions of the proposed decision to adopt a lower ROE than is currently authorized, but still remains well within the reasonable range, and are still higher than the national averages going back to at least 2014. - "I will support this decision as it balances the need to attract capital for safe, reliable utility service with the imperative to protect ratepayers from higher costs, and it accomplishes this by setting a fair rate of return that I believe can help maintain affordability. - "I want to note that in setting the ROE, we are making a prediction that the number we set will adequately compensate the investors for the risk they are willing to take. However, the Commission cannot know how the investment community will evaluate future risks and opportunities. Consequently, we must rely on the Commission's collective best judgment to balance the short-term cost consideration with investor reactions to perceived risks. If we are wrong, that could lead to an increase in the cost of borrowing. If we are correct, this decision will not adversely affect the utilities' ability to attract people to invest in California's future. - "But there are no simple, cost-free solutions to reducing wildfire risk. Our utilities and ratepayers are uniquely exposed to climate-driven catastrophic wildfires. Though progress has been made, continuous planning and resilience remain essential efforts to prevent future devastating fires. - "Wildfire-related costs constitute nearly 30% of PG&E's revenue requirement. Since 2019, approximately **$40 billio**n in wildfire-related expenditures has been added to rates or ratebase of the three largest utilities. We have one utility that is currently working to have an investment grade credit rating, while others can face potential down downgrades due to investor concerns about wildfire risk. This situation could increase the borrowing cost and hamper utilities' ability to raise the necessary equity for the system investments that that are required. - "And I want to emphasize...the legislature established the **$21 billion** wildfire fund by ratepayers and shareholders. This first time in the country that shareholders have paid for part of the insurance of wildfire insurance in 2019\. This was initially expected to last 10 years. However, this summer, the legislature thought it was prudent to replenish the fund amid concerns about the Southern California fires earlier this year. - "While this is a positive step, it does not eliminate the risk of investing in California utilities, nor guarantees that ratepayers will be not left paying for damages. The ratepayers continue to bear the burden of insuring against catastrophic wildfires. Achieving lower rates will be challenging, and utilities operating in high fire-threat districts – whether they be publicly owned or investor owned – may face significant financial viability also leading to increased rate pressure. And these risks cannot be mitigated solely through ROE. - "We hear we will need additional reforms to strengthen the wildfire fund and modify liability rules in a way to protect the electric system and ratepayers. Solving downstream affordability and reliability issues depends on a fair solution to the wildfire crisis. Yet, even without Utility Reform, the CPUC will maintain a sound regulatory stance and continue to ameliorate a great a large amount of that risk. We will continue monitoring efforts to reduce the risk of utility-caused wildfires. We have to address utility applications in timely and consistent manner. We will continue to track the risk factors, the cash flow and other financial metrics that investors and lenders also track, and we will act decisively to address exigencies that will impact the cost of borrowing and the financial viability of utilities. - "Within this context and acting on the best available information, I believe this decision will help utilities secure the capital needed for a resilient, safe grid without overburdening families and business." ### Commissioner Darcie Houck - "The issues presented in this proceeding are difficult issues to work through. We're grappling with both an affordability crisis and the need to ensure investor-owned utilities can access capital to maintain safe and reliable services for California ratepayers. The timelines are tight, the record is voluminous, and the stakes are high. So I do not take these comments lightly. - "The application before us – the request of the electric and gas utilities to set their rate of return – is a challenging one. Setting a rate of return consists of three major decisions: - Setting a capital structure; - Setting a cost of debt; and - Setting a return on equity. - In the case before us, the issue that was most contested by the parties was the return on equity. Setting a return on equity is a topic that has challenged regulators and jurists for over a century. And while the cost of debt is relatively easily calculable and the capital structures can be set generally within a small range of reasonable outcomes, the cost of equity is not something that can be easily measured or agreed upon." - "In this case, we have disagreements about the cost of equity ranging from a high of 11.75% to a low of 6.11%, a difference of over 560 basis points. In 1912, **Justice Holmes** wrote on adjusting rates of return in [*Cedar Rapids Gaslight Co. v. Cedar Rapids*](https://supreme.justia.com/cases/federal/us/223/655/?ref=calregulatory.com) that an adjustment of this sort under a power to regulate rates has to 'steer [between **Scylla** and **Charybdis**](https://en.wikipedia.org/wiki/Between%5FScylla%5Fand%5FCharybdis?ref=calregulatory.com).' On one side, if the franchise is taken to mean that the most profitable return that could be got free from competition is protected by the 14th Amendment, then the power to regulate is null. - "On the other hand, if the power to regulate withdraws the protection of the amendment altogether, then the property is not. This is not a matter of economic theory, but a fair interpretation of a bargain. So neither extreme can have been met – a midway between them must be hit. - "Interpreting this text, regulatory commissions now set upper and lower rates of return that we consider a reasonable range as we try and thread the needle hitting that midway. I worry that since Justice Holmes wrote this in 1912 the metaphorical path between his monsters have only gotten narrower today. - "On the one hand, the investor-owned utilities raised concerns, stating that with too low a rate of return, they will have trouble attracting investment, investment they need, in large part to invest heavily in critical wildfire safety. This is essential work, but it is costly for investor-owned utilities to do this work. They must be able to access capital markets, and to do so, they need to have a sufficiently attractive return. - "The difficulties the utilities are facing in California are unprecedented. The investor-owned utilities currently operate in an environment with extremely high wildfire risk, and are unique in that California has a doctrine of inverse condemnation, combined with some of the highest property values in the country. California's investor-owned utilities have made great strides in addressing wildfire risk through vegetation management, strategic undergrounding and other investments such as covered conductor, but the threat of wildfire still remains. - "This combination means that, for the investor-owned utilities to maintain investment-grade ratings, the state must maintain a wildfire liability fund. Recently, the legislature passed SB 254, which created a wildfire fund continuation account, adding $**18 billion** to the wildfire fund. However, we have seen commentary from rating agencies raising concerns regarding the need for future increases in the amount available in the fund beyond the additional $18 billion, and the incorporation of replenishment mechanisms or other enhancements following the state's most recent wildfires. - "This commentary from the rating agencies show that our actions here cannot fully guarantee the investor-owned utilities' credit ratings, no matter what number within that reasonable range we land on for the return on equity...On the other hand, we have rising costs and a crisis of affordability affecting people across California and across the country. - "The affordability crisis is not limited to electric rates. It's not lost on me that the unemployment rate nationwide just hit its highest point since 2021\. Meanwhile, the rate of inflation is lower than it was in 2021 and 2022 but the cost of consumer goods have not gone down. Prices instead continue to rise, albeit at a slower rate. According to the California Legislative Analyst Office, while California's average hourly rates are up 25.3%, since 2020 – rents are up 41.8%, mid-tier home payments are up 73.9%, bottom-tier home payments are up 78.4%. - "Californians who get their health insurance through the state marketplace are facing an average of 10.3% premium increases next year. Californians on the [FAIR Plan](https://en.wikipedia.org/wiki/California%5FFAIR%5FPlan?ref=calregulatory.com) are facing a 36% home insurance rate hike. Auto loan delinquencies are the highest they've been since 2010; student-loan delinquencies increased from 0.5% last year to 9.6% this year. In this case, SCE briefed the Commission that its customer arrearages, as of December 2024, were 800% of pre- COVID levels. Cal Advocates' third quarter 2025 electric rates report show that 21.2% of electric IOU customers are in arrears, owing an average of $642 and the last three years, the average residential electric rate has increased 38% for PG&E, 41% for FTE and 9% for San Diego Gas and Electric, even though San Diego Gas and Electric average per kilowatt rate remains the highest among the investor-owned utilities in California. Every economic indicator tells us that we're living in a time of extreme precarity for working Californians. So I want to be clear, the decision before us will slightly decrease rates relative to maintaining the status quo." - "The rate of return proposed today will provide the utilities with slightly lower returns this year, totaling almost **$100 million** less than the total return across all four utilities than they would if we kept the current rates of return. On the other hand, due to the increase in ratebase authorized for the four utilities here, the returns authorized by the decision represent an **$840 million** increase in total authorized return from 2025, which will increase in future years. - "California investor-owned utilities are projected to grow ratebase at nearly a 10% compound annual growth rate. With the current rates of return and ratebase, the investor-owned utilities will earn a combined total return of **$12.2 billion** this year. So I want to be clear: roughly 1/5 of those dollars are going to go to servicing debt. Looking forward to next year and beyond, with the adoption of this PD, projected total returns will increase by about **$1 billion** each year that thereafter. Each point of ROE has a combined projected revenue requirement impact of about **$32 million** over three years. - "So the increase from the PD to the revised one that's before us today carries with it an increase in cost to rate payers of roughly **$160 million**. Before getting to how I will vote, I want to say that I do think, from a process standpoint, the Commission should revisit how these applications are processed. I'm not sure that looking at the Cost of Capital every three years makes sense anymore. I would be supportive of making this proceeding an annual application, similar to the ERRA applications. - "Issuing a Cost of Capital decision that's bound to a three-year period increases the consequences of going too high (or too low) on authorized rate of return, and makes it difficult to find the right middle ground. Second, I think we need to take a closer look at the capital structures that are authorized here. Most of the testimony in the proceeding focused on the return on equity, but capital structures are important to consider as well. We have authorized the same capital structures as initially authorized and [Decision 19-12-056](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M322/K633/322633896.PDF?ref=calregulatory.com), and this decision continues those structures. Also, I think we need to look closely at the cost of debt. Since at least 2004, our Cost of Capital decisions have cited to [Decision 90-11-057](https://docs.cpuc.ca.gov/published/Final%5Fdecision/20887-07.htm?ref=calregulatory.com) to approve forecasted cost of debt. In 1990 our cost of capital proceedings were annual applications, and in the instant proceedings, have forecasted debt cost looking years into the future. - "Yet even Decision 90-11-057 – when we had annual applications – that decision stated that, in future Cost of Capital cases, we may investigate the differential between the established cost of debt and the cost of debt actually issued. In the instant case, cost of debt was not contested and briefed. This may have been partly due to the timing of the issuance of the update to the debt exhibits, which coincided with service of rebuttal testimony. But I do think the time is right to reconsider these and other process issues, and determining Cost of Capital as we go forward. - "Last October, in discussing a decision that reduced the utilities authorized rate of return by 42 basis points, I quoted [*FPC v. Natural Gas Pipeline Co.*](https://supreme.justia.com/cases/federal/us/315/575/?ref=calregulatory.com), which stated that, once the Commission has set a rate of return that allows the company to operate successfully and attract capital, the questions of the just and reasonable are at an end, so far as the investor interest is concerned. That decision states that once we have set that rate, we have a duty to consider the consumer interest in determining what is adjusted reasonable rate. - "While I believe that this decision provides the utilities with a sufficient rate of return to attract capital, and the commission did land on a reasonable range for that return on equity, I do not think that the decision threads the needle sufficiently to consider the full impact to the customer interest. And I want to reiterate that I don't make this decision lightly. This is a very difficult decision...A lot of thought and time has gone into considering how to land with this proposed decision. - "It's not an easy decision, and there are tough decisions to make here, in determining the balance of need for the investor-owned utilities to attract capital, which they have to do, and the need to balance customer interest, particularly where customers are continuing to take on more and more risk. - "I understand my colleagues' position and why they support the decision, and there are very good reasons to support this decision, which does lower the return on equity, which is going in the right direction. - "But I don't disagree with the circumstances described by my colleagues, and I share their concerns regarding the need for the investor-owned utilities to maintain investment-grade ratings and to access capital at the lowest possible cost. That said, in my opinion, the decision does not strike the right balance up to the customer side of the pendulum, and therefore I will not be voting for it. I do. In closing, want to reiterate my ### Commissioner Karen Douglas - "We've seen it over the past years, that it costs a lot of money, and it involves a very significant obligation on the part of the utilities to raise capital to invest it in making the infrastructure safer, in undergrounding lines, where appropriate, in upgrading the infrastructure, putting in covered conductor, investing in other advanced technologies to improve public safety. - "We're also engaged in an energy transition in which we have significantly changed our system. We've got a lot of new resources online. There's a tremendous amount of opportunity and work and expansion of key infrastructure that California is going to need and benefit from for a long time, but the utilities have to be able to raise the capital to make these investments. And as has been noted, this decision reduces the return on equity from where it was set in our last decision. - "We've heard from both sides and all sides. I think in the course of this proceeding, we certainly heard from the utilities saying that they think it needs to be higher. And we've heard from a large number of speakers today wanting it to be lower, and we have established mechanisms that we have to use and establish tests that we have to look at in setting the return on equity. This has been a proceeding that developed the voluminous records that really looked at the issues, and I think the ROE you proposed in this decision is reasonable, and it's absolutely within the parameters that we need to consider. I think it is coming out in the right place, and so for that reason, I will be supporting the decision." ### Proof of Value URL: https://www.calregulatory.com/proof-of-value/ Last updated: 2026-06-24T17:41:51.000Z ## Timely Intelligence on CPUC Decisions that Move Billions in Utility Costs From 2008 to 2025, regulatory analyst and CRI founder [**Michael Cade**](https://www.linkedin.com/in/mikecade/?ref=calregulatory.com) served as the primary regulatory intelligence engine for legal teams representing California's largest energy consumers in CPUC proceedings governing billions of dollars in utility cost recovery. While at [Buchalter](https://www.buchalter.com/practice/energy-natural-resources-law/?ref=calregulatory.com) and [Alcantar & Kahl](https://web.archive.org/web/20090831065855/http://www.a-klaw.com/expertise.htm), his monitoring and analysis informed work that: - Reduced utilities' authorized Cost of Capital adjustments ([D.24-10-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K150/544150643.PDF?ref=calregulatory.com)); - Successfully contested wildfire mitigation cost-recovery requests to ensure reasonableness and ratepayer protection ([D.25-12-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K453/592453458.PDF?ref=calregulatory.com)); - Contributed to development of the CPUC's Safety Model Assessment Proceeding (S-MAP) framework for identifying and prioritizing utility safety risks ([D.14-12-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M143/K549/143549328.PDF?ref=calregulatory.com)); - Supported continued use of the Aliso Canyon natural gas storage facility at levels necessary for system reliability and affordability ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)); and - Shaped favorable rate-design outcomes in General Rate Case litigation involving PG&E, SoCalGas, and SCE. **CRI eliminates regulatory shock**. We translate thousands of pages of CPUC filings into the specific financial and operational levers that impact your bottom line, delivered with the speed required to act before the market moves. This intelligence is now available through [direct subscriptions or enterprise retainers](https://www.calregulatory.com/pricing/) at a fraction of traditional consulting costs. ## Clients Served Through Law-Firm Engagement - [**Energy Producers and Users Coalition**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M348/K579/348579516.PDF?ref=calregulatory.com) (EPUC) and the [**Indicated Shippers** ](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/indicated-shippers-comments-on-i1702002-phase-3-workshop-20201204.pdf?ref=calregulatory.com)(coalitions representing Aera, BP, California Resources Corporation, ConocoPhillips, ExxonMobil, Marathon Petroleum, PBF Energy, Phillips 66, Shell) - [**California Community Choice Association**](https://cal-cca.org/?ref=calregulatory.com)(CalCCA) - [**California Large Energy Consumers Association**](https://cleca.org/?ref=calregulatory.com)(CLECA) - [**Clean Energy**](https://www.cleanenergyfuels.com/?ref=calregulatory.com) - [**Cogeneration Association of California**](https://www.caiso.com/Documents/CAC%5FEPUCCommentsonSCPIIStrawProposal.pdf?ref=calregulatory.com) (CAC) - [**Electrochaea**](https://www.electrochaea.com/?ref=calregulatory.com) - [**Olivine**](https://olivineinc.com/?ref=calregulatory.com) ## Recent Examples Where CRI's Analysis Provided Unique Advantage The following examples demonstrate how CRI's analysis provides operational and financial advantages unavailable from general publications, law-firm updates, or episodic consulting. ### SDG&E January 2026 Rate Increase – Capital vs. Energy Cost Attribution [SDG&E Electric Rates for January 1, 2026SDG&E filed AL 4757-E to consolidate all CPUC- and FERC-authorized rate changes into a single filing implementing January 1 electric rates![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-6.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Sat-Jan-03-2026--23-.png)](https://www.calregulatory.com/sdg-e-electric-rates-for-january-1-2026-10-bundled-increase-but-procurement-isnt-the-driver/) - **What general language in the filing said:** SDG&E rates would increase 10% effective January 1. - **What CRI delivered:** The increase wasn't driven by energy procurement (SDG&E's ERRA revenue requirement actually dropped $67 million). The real drivers were capital recovery mechanics invisible in any shallow reading: a **$172 million** TACBAA transmission true-up (past cost reconciliation, not new investment), **$616 million** in PABA undercollection signaling bundled/departed load tension, and GRC base margin increases. Most critically, residential delivery rates rose **19.4%.** - **Why it mattered:** CRI readers could distinguish between temporary procurement volatility and cost-recovery pressure, and industrial customers could see the distributional politics building around residential subsidization. --- ### SoCalGas CAP Filing – "Normalized" Rate Presentation Didn't Tell the Full Story [CPUC issues PD approving SDG&E’s Forecast 2026 ERRA submissionToday’s briefing blends macro-policy (Rule 21) with infrastructure accountability (gas AMI, the Sempra Utilities’ Cost Allocation Proceeding).![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-7.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Nov-12-2025--2--1.png)](https://www.calregulatory.com/wednesday-aggregate/?ref=california-regulatory-intelligence-newsletter) - **What general coverage reported:** SoCalGas filed its Cost Allocation Proceeding (CAP) for 2027-2029. - **What CRI delivered:** When this filing appeared in September 2025, CRI spotted that SoCalGas was comparing its proposed rates to "normalized" September 2025 baselines rather than actual rates, which created an illusion of rate decreases. This realization was also noted by the Southern California Generation Coalition (SCGC), whose analysis showed electric-generation transmission service would actually increase **23%** under the proposal. CRI surfaced SCGC's [protest](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K015/587015946.PDF?ref=calregulatory.com), which argued that SoCalGas was replacing the storage/balancing regime from a 2024 Cost Allocation Proceeding settlement without sufficient justification, with reductions in injection/withdrawal capacity that would hit noncore industrial users hardest. - **Why it mattered:** Sophisticated energy buyers could see past SoCalGas's normalized baseline presentation to understand actual rate impacts. CRI's curation of SCGC's protest surfaced critical analysis that would have been missed in standard regulatory feeds. --- ### Aliso Canyon Biennial Assessment – Storage Reduction Impact on Unbundled Storage Program [IRP Cycle 2024-2026 Changes; Woolsey Fire Financing OrderCovers: IRP; Woolsey Fire; Aliso Canyon; 2026 ERRA Forecasts of PG&E and SCE![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-8.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/photo-1688040637388-d2c0aa7b9907)](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/?ref=california-regulatory-intelligence-newsletter) - **What general coverage reported:** The CPUC's Energy Division recommends a 10 Bcf reduction at Aliso Canyon. - **What CRI delivered:** CRI connected the inventory reduction to a [2024 CPUC decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M536/K491/536491449.PDF?ref=calregulatory.com)'s cascading impact on the Unbundled Storage program (a 10 Bcf cut would automatically shrink UBS capacity from 25 Bcf to 15 Bcf, significantly reducing seasonal flexibility for noncore shippers). And pursuant to a SoCalGas [compliance filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=clregulatory.com), CRI caught that CPUC Staff's own analysis showed 550 MMcfd withdrawals needed on 1-in-10 winter peak days, contradicting the reduction logic. Additionally, CRI identified Staff hedging their own recommendation ("a smaller incremental or no reduction may be appropriate") due to LNG export pressures and Energía Costa Azul startup. - **Why it mattered:** By mining useful knowledge from an obscure, 11-page compliance filing, CRI gave refiners and generators an opportunity to quantify their operational risk and price exposure from reduced storage optionality (not just abstract "reliability concerns"). ### Warned Large Gas Transportation Customers of a 54.6% Backbone Transportation Service Increase Embedded in SoCalGas’s 2026 Rate Consolidation [SoCalGas BTS Rates to Rise 54.6% on January 1, 2026SoCalGas filed Advice Letter 6578-G to implement its consolidated gas transportation rate update effective January 1, 2026.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-34.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Sat-Dec-27-2025--9-.png)](https://www.calregulatory.com/socalgas-rates-for-january-1-2026-include-a-massive-54-6-backbone-transportation-service-increase/) - **What executive summaries said**: SoCalGas’s January 1, 2026 consolidated rate update produced a modest net systemwide revenue *decrease*. - **What CRI delivered**: CRI identified that the filing masked a massive cost reallocation, with Backbone Transportation Service absorbing a **$224.3 million** increase (a 54.6% rate jump) driven by layered regulatory account amortizations, integration adjustments, and CAP allocations. In deciphering the January 1 filing, CRI explained that BTS was functioning as the residual allocator of system-level transmission costs even as overall revenues declined. This means that non-volumetric risk was shifted onto backbone transportation customers rather than distribution classes. - **Why it mattered:** CRI forecasted the BTS increase months in advance, allowing traders and industrial customers to adjust hedging strategies, renegotiate contracts, and model exposure before implementation. By identifying the cost-shift mechanism in a routine rate consolidation filing, CRI provided early warning of a major transmission cost risk affecting dispatch economics and pricing. ### Identified that a PG&E Interest Adjustment Increased Carrying Costs on Regulatory Balances [PG&E’s Yield Spread Adjustment; SDG&E TIMPBA SettlementTopics covered: PG&E’s implementation of a Yield Spread Adjustment and a settlement resolving SDG&E’s application to recover TIMPBA costs.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-35.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--9-.png)](https://www.calregulatory.com/wednesday-aggregate-8/) - **What general coverage reported:** PG&E filed a non-descript advice letter to implement the CPUC’s Yield Spread Adjustment for regulatory account interest calculations. - **What CRI delivered:** CRI identified that the newly established 125-basis-point spread increases financing costs on major balancing and memorandum accounts across PG&E’s gas and electric portfolios, thereby raising the cost of carrying wildfire, procurement, and other large balances over time despite no immediate rate change. - **Why it mattered:** This analysis warned stakeholders that procedural delays and unresolved balances now carry a higher embedded financing cost that will surface in future rates, affecting long-term exposure for customers, counterparties, and market participants. --- ## Representative Areas of CPUC Proceedings (2008-2025) ***Illustrative scope of work; not a comprehensive list*** CRI's analytical work spans hundreds of CPUC proceedings and select FERC matters, including: - Risk-based decision-making frameworks and utility safety oversight (S-MAP); - De-energization and Public Safety Power Shutoff (PSPS) planning; - Biomethane and renewable gas policy; - Natural gas safety, storage, and price investigations; - Pipeline Safety Enhancement Plans; - Zonal electrification and decarbonization pilots; - Building electrification initiatives; - Hydrogen demonstration and blending proposals; and - Demand response and load flexibility programs Pricing options available [here](https://www.calregulatory.com/pricing/). If you operate in California’s energy markets, you cannot afford to be surprised by CPUC decisions. CRI ensures you never are. ### Pricing URL: https://www.calregulatory.com/pricing-2/ Last updated: 2026-05-12T15:42:00.000Z **California Regulatory Intelligence (CRI)** provides curated analysis of consequential developments in California energy regulation for utilities, large energy users, market participants, consultants, and legal professionals. Coverage focuses primarily on the California Public Utilities Commission (CPUC), with select monitoring of the California Energy Commission (CEC), the California Independent System Operator (CAISO), the California Air Resources Board (CARB) and Federal Energy Regulatory Commission (FERC). ### **Subscription:** [**$75/month**](https://www.calregulatory.com/cri-operations-update-2/#/portal/signup/6a023109c799620001352e52/monthly) Subscribers receive focused coverage of developments that matter, including: - Major rate changes affecting core and noncore customers; - General Rate Case filings and cost-allocation proceedings; - Significant proposed decisions and draft resolutions; - Final decisions with major operational or financial implications; - Framework proceedings involving Resource Adequacy, Integrated Resource Planning, Demand Response, and Long-Term Gas Planning; and - Regulatory developments that move markets. **Fewer emails. Greater focus. Consequential developments only.** ### For firm or group access, please contact [**info@calregulatory.com**](mailto:info@calregulatory.com) ### Flexible Service Connections: CPUC Proposal Would Make Controlled Load a Standing Alternative to Distribution Upgrades URL: https://www.calregulatory.com/flexible-service-connections-cpuc-proposal-would-make-controlled-load-a-standing-alternative-to-distribution-upgrades/ Last updated: 2026-07-08T05:14:06.000Z On July 7, **Commissioner Darcie Houck** issued a [proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M610/K354/610354105.PDF?ref=calregulatory.com) in the CPUC's High DER Future docket (R.21-06-017) that would make flexible service connections a standing distribution-planning tool for the large investor-owned utilities, not just a stopgap for energization delays. _This page is for paying subscribers only._ ### CPUC Decision Inventory URL: https://www.calregulatory.com/cpuc-decision-inventory/ Last updated: 2026-07-21T01:22:14.000Z _This page is for paying subscribers only._ ### Other Media URL: https://www.calregulatory.com/other-media/ Last updated: 2026-09-07T20:58:31.000Z Selected work by CRI writers and contributors published or cited elsewhere. ## Michael Cade ### Alberta/AESO (RTO Insider) - [**AUC Rejects 1.4-GW Gas Plant for Alberta Data Center**](https://www.rtoinsider.com/142478-auc-rejects-gas-plant-for-alberta-data-center/?ref=calregulatory.com) - [**Market Surveillance Administrator Faults AESO Frequency-response Compliance Monitoring**](https://www.rtoinsider.com/142164-market-surveillance-admin-faults-aeso-frequency-response-compliance-monitoring/?ref=calregulatory.com) - [**Alberta Market Surveillance Administrator Briefs**](https://www.rtoinsider.com/139460-alberta-market-surveillance-administrator-briefs/?ref=calregulatory.com) - [**AESO Rethinks Proposed Limits on Inflexible Energy Offers**](https://www.rtoinsider.com/138251-aeso-rethinks-proposed-limits-inflexible-energy-offers/?ref=calregulatory.com) - [**AESO to Update Supply Adequacy Metrics to Reflect Changing Resource Mix**](https://www.rtoinsider.com/137937-aeso-update-supply-adequacy-metrics-reflect-changing-resource-mix/?ref=calregulatory.com) ### Ontario/IESO (RTO Insider) - [**OEB Recommends DER Net Billing, Storage Rate Changes in Report to Minister**](https://www.rtoinsider.com/142335-oeb-recommends-der-net-billing-storage-rate-changes/?ref=calregulatory.com) - [**Ontario Bulk Plans Pair Near-term Builds with Future Transmission Options**](https://www.rtoinsider.com/142026-ontario-bulk-plans-pair-near-term-builds-future-tx-options/?ref=calregulatory.com) - [**Toronto Third Line Developer Could Bear More Cost Risk Under IESO Framework**](https://www.rtoinsider.com/141351-toronto-third-line-developers-could-bear-more-risk-ieso-framework/?ref=calregulatory.com) - [**IESO Weighs Capacity Treatment of Storage, Gas in LT2**](https://www.rtoinsider.com/141223-ieso-weighs-capacity-treatment-storage-gas-in-lt2/?ref=calregulatory.com) - [**Demand Response Shortfalls Shape IESO 2027 Capacity Auction Changes**](https://www.rtoinsider.com/140945-demand-response-shortfalls-drive-ieso-2027-capacity-auction-changes/?ref=calregulatory.com) - [**IESO Proposes Fix for Combined-cycle Make-whole Overpayments**](https://www.rtoinsider.com/140805-ieso-proposes-fix-combined-cycle-make-whole-overpayments/?ref=calregulatory.com) - [**Traders Challenge IESO Plan to Restrict Import Guarantees**](https://www.rtoinsider.com/139876-traders-warn-ieso-import-guarantee-changes-could-harm-reliability/?ref=calregulatory.com) - [**Ontario Market Monitor Reviews 1st Year of Locational Pricing**](https://www.rtoinsider.com/139590-ontario-market-monitor-reviews-first-year-locational-pricing/?ref=calregulatory.com) - [**IESO DER Plan Raises Data, Control Disputes**](https://www.rtoinsider.com/139054-ieso-der-plan-raises-data-control-disputes/?ref=calregulatory.com) - [**Ontario Embraces Data Centers but Proposes Guardrails**](https://www.rtoinsider.com/139119-ontario-embraces-data-centers-but-proposes-guardrails/?ref=calregulatory.com) - [**IESO Plans Higher Connection Deposits, Earlier Invoicing**](https://www.rtoinsider.com/138470-ieso-plans-higher-connection-deposits-earlier-invoicing/?ref=calregulatory.com) - [**IESO Applying Data Center Standards Ahead of Market Rule Changes**](https://www.rtoinsider.com/137749-ieso-applying-data-center-standards-ahead-market-rule-changes/?ref=calregulatory.com) - [**Battery Ramp Limit Raises Market-Governance Questions in Ontario**](https://www.rtoinsider.com/137639-battery-ramp-limit-raises-market-governance-questions-ontario/?ref=calregulatory.com) - [**Ontario DER Coordination Plan Takes Shape**](https://www.rtoinsider.com/137289-ontario-der-coordination-plan-takes-shape/?ref=calregulatory.com) - [**Combined-cycle Scheduling Flaws Prompt IESO Market Rule Changes**](https://www.rtoinsider.com/137131-combined-cycle-scheduling-flaws-prompt-ieso-market-rule-changes/?ref=calregulatory.com) - [**IESO Weighs Whether Niagara’s Power Gateway Can Accommodate Forecast Load**](https://www.rtoinsider.com/136746-ieso-weighs-whether-niagaras-power-gateway-can-accommodate-forecast-load/?ref=calregulatory.com) - [**Ontario Market Participants Escalate Concerns About IESO Enforcement Structure**](https://www.rtoinsider.com/136502-ontario-market-participants-proposed-enforcement-overhaul-expand-ieso-power/?ref=calregulatory.com) - [**IESO Names Jason Fitzsimmons CEO**](https://www.rtoinsider.com/136435-ieso-names-jason-fitzsimmons-president-and-ceo/?ref=calregulatory.com) - [**Hamilton Demand Forecast Points to Major Wires Buildout, IESO Says**](https://www.rtoinsider.com/136270-hamilton-demand-forecast-points-to-major-wires-buildout-ieso/?ref=calregulatory.com) - [**Developers Warn IESO Contract Change Could Raise Bid Prices, Hurt Financing**](https://www.rtoinsider.com/135955-developers-warn-ieso-contract-change-could-raise-bid-prices/?ref=calregulatory.com) - [**Unsigned Contract Spurs Proposed Changes to IESO’s Long Lead-Time Procurement Rules**](https://www.rtoinsider.com/135469-unsigned-contract-spurs-proposed-changes-ieso-long-lead-time-procurement-rules/?ref=calregulatory.com) - [**Hourly Demand Response Trigger to Rise in IESO Capacity Auction**](https://www.rtoinsider.com/135229-demand-response-trigger-hdr-to-rise-ieso-capacity-auction/?ref=calregulatory.com) - [**IESO Revises Market Parameter Proposal Following Oversight Concerns**](https://www.rtoinsider.com/135116-ieso-revises-market-parameter-proposal-following-oversight-concerns/?ref=calregulatory.com) - [**IESO Updating Demand-side Calculations for Storage, Load Shifting**](https://www.rtoinsider.com/135016-ieso-updates-demand-side-calculations-storage-load-shifting/?ref=calregulatory.com) - [**Battery Storage Sweeps Ontario’s 1st Long-Term 2 Capacity Window**](https://www.rtoinsider.com/134591-battery-storage-sweeps-first-ontario-long-term-2-capacity-window/?ref=calregulatory.com) - [**Mining Loads Shape IESO’s Northwest Ontario Forecast**](https://www.rtoinsider.com/134466-mining-loads-shape-ieso-northwest-ontario-forecast/?ref=calregulatory.com) - [**Kitchener-Waterloo Growth Pushes IESO Regional Plan Into Bulk-System Territory**](https://www.rtoinsider.com/134215-kitchener-waterloo-growth-ieso-regional-plan-bulk-system-territory/?ref=calregulatory.com) - [**Dispatchable Generation Eyed for Sault Ste. Marie as East Lake Superior Demand Surges**](https://www.rtoinsider.com/134008-dispatchable-generation-eyed-for-sault-ste-marie-as-east-lake-superior-demand-surges/?ref=calregulatory.com) - [**Ottawa Constraints Drive IESO Tx Proposal, but Stakeholders Question Planning Record**](https://www.rtoinsider.com/133750-ottawa-constraints-drive-ieso-tx-proposal-stakeholders-question-record/?ref=calregulatory.com) - [**Stakeholders Discuss 2026 Capacity Auction Rule Changes with IESO**](https://www.rtoinsider.com/133622-stakeholders-discuss-2026-capacity-auction-rule-changes-ieso/?ref=calregulatory.com) - [**IESO Proposes $3.2B Transmission Expansion North of Sudbury**](https://www.rtoinsider.com/132823-ieso-proposes-transmission-expansion-north-sudbury/?ref=calregulatory.com) ### Energy Central - [**New Rulemakings at the CPUC: An Electric Rates Reset + a Risk Successor Docket**](https://www.energycentral.com/energy-biz/post/new-rulemakings-at-the-cpuc-an-electric-rates-reset-a-risk-successor-xW1AnFLR0J67ElH?ref=calregulatory.com) - [**Transmission Infrastructure Gets Top Billing at March 19 CPUC Voting Meeting**](https://www.energycentral.com/energy-biz/post/transmission-infrastructure-gets-top-billing-at-march-19-cpuc-voting-898Ru0W9l4o90G9?ref=calregulatory.com) - [**CPUC Roundup: Week of 02/09/26 - 02/13/26**](https://www.energycentral.com/energy-biz/post/cpuc-roundup-week-of-02-09-26---02-13-26-BksPAPtdRbDgAMb?ref=calregulatory.com) - [**California PUC Update: Cost of Capital Changes, Gas Utility Ratemaking Disputes, REC Valuation, and Provider of Last Resort Rules**](https://www.energycentral.com/energy-biz/post/california-puc-update-cost-of-capital-changes-gas-utility-ratemaking-gbSzafiSHv2Fp0X?ref=calregulatory.com) - [**California IOUs' January 1, 2026 Rate Filings: Different Headlines, Same Basic Story**](https://www.energycentral.com/energy-biz/post/california-ious-january-1-2026-rate-filings-different-headlines-same-ZtatkYlFvVDRRSq?ref=calregulatory.com) - [**Preview of the California Public Utilities Commission's December 18, 2025 Voting Meeting**](https://www.energycentral.com/energy-biz/post/preview-of-the-california-public-utilities-commission-s-december-18-2025-FwhCQYpmFIVWyVi?ref=calregulatory.com) - [**CPUC December 4, 2025 Voting Meeting Results**](https://www.energycentral.com/energy-biz/post/cpuc-december-4-2025-voting-meeting-results-9JAffkDmuoeLRv5?ref=calregulatory.com) - [**December 4, 2025 CPUC Voting Meeting Preview**](https://www.energycentral.com/energy-biz/post/december-4-2025-cpuc-voting-meeting-preview-GihzE3wgVGRC2E7?ref=calregulatory.com) - [**California IOU Rate Roundup**](https://www.energycentral.com/energy-biz/post/california-iou-rate-roundup-Ml3y38jwwlfyHKD?ref=calregulatory.com) - [**November 20, 2025 CPUC Voting Meeting Results**](https://www.energycentral.com/energy-biz/post/november-20-2025-cpuc-voting-meeting-results-H7Bcb4Tpap2K0V9?ref=calregulatory.com) - [**November 20, 2025 CPUC Voting Meeting Preview**](https://www.energycentral.com/energy-biz/post/november-20-2025-cpuc-voting-meeting-preview-94huaLgFiqznASJ?ref=calregulatory.com) - [**CPUC Voting Meeting Results from October 30, 2025**](https://www.energycentral.com/energy-biz/post/cpuc-voting-meeting-results-from-october-30-2025-5l5qkhre4DAy7V8?ref=calregulatory.com) - [**CPUC October 30, 2025 Voting Meeting Preview**](https://www.energycentral.com/energy-biz/post/cpuc-october-30-2025-voting-meeting-preview-Sm1UvIFc2UiUpZH?ref=calregulatory.com) ### Commentary/Interviews in Other Media - [**CAISO’s Load-Balancing EDAM Math Doesn’t Add Up, Says CPUC Staff**](https://www.utilitydive.com/news/caiso-load-balancing-edam-cpuc-staff-powerex/828142/?ref=calregulatory.com)(Utility Dive) ### Substack - [**Palms & Pines**](https://michaelcade.substack.com/)(personal blog) ### LinkedIn - **CRI Newsletter** [Subscribe on LinkedIn](https://www.linkedin.com/build-relation/newsletter-follow?entityUrn=7387263139450613760&ref=calregulatory.com) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/08/iterograph_Tue-Jul-28-2026--8-.png) ## Posts ### NEWS CODEX: SMR Development; Senate Bill 492; BC2BC ZEV Corridor URL: https://www.calregulatory.com/news-codex-smr-development-senate-bill-492-bc2bc-zev-corridor/ Last updated: 2026-09-08T17:10:15.000Z - **"Backyard Nukes" an Answer to California's Future Energy Questions:** "California should be at the leading edge of SMR development. No state needs as much electricity as California and in no state [outside of Hawaii does retail power cost more](https://nam10.safelinks.protection.outlook.com/?url=https%3A%2F%2Fwww.eia.gov%2Felectricity%2Fmonthly%2Fepm%5Ftable%5Fgrapher.php%3Ft%3Depmt%5F5%5F6%5Fa&data=05%7C02%7Cmfleming%40pacificresearch.org%7C879327a9c3bd4690277908df07743d8c%7C56c2f5bedd274fdaa829995353b3b27a%7C0%7C0%7C639237872312096327%7CUnknown%7CTWFpbGZsb3d8eyJFbXB0eU1hcGkiOnRydWUsIlYiOiIwLjAuMDAwMCIsIlAiOiJXaW4zMiIsIkFOIjoiTWFpbCIsIldUIjoyfQ%3D%3D%7C60000%7C%7C%7C&sdata=K53o1DTbsD8pmOEVPn57fRh8R8Z4Ydnb3H6v0GNE7ks%3D&reserved=0&ref=calregulatory.com). Policymakers and activists publicly assure us that solar and wind will meet future energy demands, but privately they likely know better. The activists don’t care and while the policymakers do, they’re afraid to cross the green line the eco-zealots and the media have put down. If the game doesn’t change soon, California is going to find itself with an energy problem that it can neither tax nor regulate its way out of."[ **PACIFIC RESEARCH INSTITUTE**](https://www.pacificresearch.org/back-yard-nukes-an-answer-to-californias-future-energy-questions/?ref=calregulatory.com) - **Bluecore Energy Developing Nuclear Power Barge at Port of Long Beach:** "Bluecore's initial 10-MWe system is designed to generate enough electricity to power the equivalent of approximately 15,000 homes. The company said individual reactor units could be combined to provide additional generating capacity and would be fueled for several years of operation." [**WORKBOAT**](https://www.workboat.com/bluecore-energy-developing-nuclear-power-barge-at-port-of-long-beach?ref=calregulatory.com) - **California's New Regulation Adds Hundreds to the Cost of a Set of New Tires:** "The California Energy Commission recently approved new rules to phase out the sale of replacement tires that do not meet the state’s energy-efficiency standards. The Replacement Tire Efficiency Program [would mandate that](https://www.independentwomen.com/2026/08/20/new-ca-tire-tax/?ref=calregulatory.com) 'replacement tires are at least as energy efficient, on average, as tires sold on new vehicles' and help 'promote driver safety by setting a minimum wet grip standard.' The rules target a tire’s 'rolling resistance,' or how much energy it takes to keep a tire moving down the road. Lower resistance means cars use less gas or electricity for better mileage, which state officials claimed will help affordability. The first phase of the rule begins in 2029, when replacement tires must meet a maximum rolling-resistance level of [9.1 newtons per kilonewton — ](https://nypost.com/2026/08/18/us-news/california-business-owners-drivers-fume-at-new-tire-rules/?ref=calregulatory.com)a threshold that drops to 7.2 in 2033." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/regulation/californias-new-regulation-adds-hundreds-to-the-cost-of-a-set-of-new-tires/?ref=calregulatory.com) - **I Did a Deep Dive into California's "Tire Ban" – Here's the Truth About What's Happening:** "The scope of enforcement is at the retailer, manufacturer, and test laboratory level." [**THE AUTOPIAN**](https://www.theautopian.com/i-did-a-deep-dive-into-californias-tire-ban-heres-what-i-learned/?ref=calregulatory.com) - **California Let a Utility Wildfire Liability Cap Die Without a Vote, and the Cost Did Not Go Anywhere:** "The California Legislature adjourned its session without advancing Senate Bill 492, Governor **Gavin Newsom**’s proposal to cap utility wildfire liability. The equity market priced the result within a day. PG&E stock dropped 20 percent. Edison International fell 23 percent, its largest single-day decline in more than 25 years. A 23 percent single-session repricing of a regulated utility is not a statement about the current quarter’s earnings. It is a statement about who carries a liability that nobody disputes exists." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/california-let-a-utility-wildfire-liability-cap-die-without-/?ref=calregulatory.com) - **Gov. Newsom Failed to Rewrite California's Wildfire Liability System:** "Opponents of Newsom’s plan called it a utility bailout that would shift costs onto homeowners via higher premiums and insurers. The plan would reduce compensation for victims." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/gov-newsom-failed-to-rewrite-californias-wildfire-liability-system/?ref=calregulatory.com) - **California Pays EV Owners Up to $3,200 a Year to Export Power, and PG&E Has 51 Cars Connected:** "Pacific Gas and Electric added dcbel and Wallbox chargers to its residential vehicle-to-everything pilot in August 2026\. The move widens a California program that pays EV owners to send power back to the grid. Drivers enrolled in the state’s REDWDS grant program earn up to $3,200 per vehicle each year by exporting stored energy, according to dcbel. The California Energy Commission covers up to $13,000 of the hardware and installation cost. PG&E takes $2,500 off installation, or $3,000 in disadvantaged communities. It adds a $1,500 early-adopter payment for the first 250 customers. Massachusetts goes further and installs the equipment free. Yet PG&E reported just 51 interconnected V2X customers as of July 2026."[**MGRID**](https://mgrid.org/2026/08/28/california-pays-ev-owners-export-power-pge-51-cars-connected/?ref=calregulatory.com) - **California Politicians Promised White Gold in "Lithium Valley" – but Are Those Dreams Fading?** "The Hell's Kitchen project by Controlled Thermal Resources has been delayed by lawsuits arguing that the company neglected to address its environmental impacts. Last month an appeals court sent the environmental review back to Imperial County to correct deficiencies regarding water and air quality effects." [**LAIST** ](https://laist.com/news/climate-environment/california-politicians-promised-white-gold-in-lithium-valley-but-are-those-dreams-fading?ref=calregulatory.com) - **CEC Ponders Fate of Proposed 300-MW Battery Storage Project:** "The project under question is the 300-MW Corby Energy Storage project in Vacaville, which would be installed on about 40 acres and store enough power to meet the electricity demand of about 225,000 houses." [**RTO INSIDER**](https://www.rtoinsider.com/142040-cec-ponders-fate-corby-battery-energy-storage-system/?ref=calregulatory.com) - **Five West Coast Governments Back a 20-Station Electric Truck Corridor on I-%, with No New Money Attached:** "California, Oregon, Washington, British Columbia and Baja California launched the BC2BC ZEV Corridor on August 26, 2026\. The ceremony took place at the Port of Long Beach. The plan places 20 electric truck charging stations along Interstate 5\. The route runs from Vancouver to the Mexican border. Three hydrogen fueling stations go in beside them. About 10,000 trucks drive that route every day. The five governments signed a statement of principles, not a construction contract. They attached no new money to it. The buildout leans on a $102 million federal grant instead. California, Oregon and Washington transportation departments won that money in 2024." [**MGRID**](https://mgrid.org/2026/09/08/west-coast-governments-back-20-station-electric-truck-corridor-i-5/?ref=calregulatory.com) - **For BPA, the Biggest Electricity Market May Not be the Best Market:** "We are looking at a future scenario in which BPA cedes dispatch of the nation’s most affordable federal power system to institutions of its most expensive state (California)." [**RTO INSIDER**](https://www.rtoinsider.com/142160-for-bpa-biggest-electricity-market-may-not-be-the-best-market/?ref=calregulatory.com) - **How Clean Energy Fared in the California Legislature:** "...AB 1156 cuts costs and red tape for farmers who want to put solar panels on their land. AB 2493 takes aim at transmission upgrade delays that are preventing new clean power projects from coming online. AB 550 smooths out a permitting wrinkle related to species that are candidates for protection under the California Endangered Species Act. But on Wednesday, a day after the Legislature adjourned without addressing California utilities’ unlimited exposure to wildfire liability costs, PG&E [announced](https://s21.q4cdn.com/673114418/files/content%5Ffiles/PG-E-Post-Legislative-Session-Update-2026.pdf?ref=cleanpowercalifornia.org) it will delay or defer $2 billion worth of critical work in 2027, including prepping the grid for new clean energy projects and providing power to new housing developments." [**THE CURRENT**](https://www.cleanpowercalifornia.org/how-clean-energy-fared-in-the-california-legislature/?ref=calregulatory.com) - **OPAL Fuels Upgrades California Fueling Station:** "The enhanced facility is expected to dispense approximately 14 million gasoline gallon equivalents of RNG and CNG over the next decade, including 1.7 million GGE of additional capacity made possible through this upgrade. The project enables Premier Ag Transportation Inc. to fuel its fleet at the station while continuing to serve Western Milling and ten other commercial and regional customers." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/opal-fuels-upgrades-california-fueling-station?ref=calregulatory.com) - **PG&E and Rewiring America Announce Google-Funded Virtual Power Plant Program:** "The initiative, designed to test the locational value of customer-sited resources, will deploy flexible capacity from thousands of existing home batteries and smart devices across the Bay Area, while subsidizing the purchase and installation of new battery-enabled Carrier heat pumps." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/09/04/pge-and-rewiring-america-announce-google-funded-virtual-power-plant-program/?ref=calregulatory.com) - **PG&E Sees Rising Interest in "Customer-Driven" Flexible Interconnection Pilot:** "Active [Flex Connect](https://www.pge.com/assets/pge/docs/clean-energy/electric-vehicles/flexible-service-connection-pilot-overview.pdf?ref=calregulatory.com) participants have seen operational loads impacted less than 1% of the time during 'the rare confluence of events' when the local grid is constrained and their demand remains high, **Alex Collins**, PG&E’s manager of execution operations and distributed energy resource management systems, said in an interview." [**UTILITY DIVE**](https://www.utilitydive.com/news/pge-sees-rising-interest-in-customer-driven-flexible-interconnection-pil/829447/?ref=calregulatory.com) - **Santa Monica Puts 130 DC Fast Ports Behind Big Blue Bus, with Eaton Supplying the Medium-Voltage Side:** "Santa Monica will install 130 DC fast-charging ports to electrify its Big Blue Bus fleet by 2032\. ChargePoint and Eaton announced the partnership with the Santa Monica Department of Transportation on August 27, 2026\. The work sits inside a $56 million investment in electric transit infrastructure. California’s Transit and Intercity Rail Capital Program supplies $53.3 million of that total. The plan covers 195 buses on a system that carries more than 10 million rides a year. ChargePoint supplies the charging hardware from its Express Plus line, plus fleet software. Eaton supplies the part that decides whether the depot works at all: medium-voltage switchgear, switchboards, panelboards and engineering support. Earlier design work described overhead gantry charging rather than floor-mounted dispensers." [**MGRID**](https://mgrid.org/2026/09/01/santa-monica-puts-130-dc-fast-ports-behind-big-blue-bus-with-eaton-supplying-the-medium-voltage-side/?ref=calregulatory.com) ### September 3, 2026 CPUC Voting Meeting Results: GRC Overhaul; Fire-Threat Maps; and IOU Financing URL: https://www.calregulatory.com/september-3-2026-cpuc-voting-meeting-results-grc-overhaul-fire-threat-maps-and-iou-financing/ Last updated: 2026-09-04T12:30:30.000Z At its September 3 voting meeting, the CPUC launched its first comprehensive overhaul of the General Rate Case Plan since 2007 by opening a rulemaking that could reshape utility forecasting, attrition-year ratemaking, wildfire-cost review and the use of standalone applications. The Commission also adopted decisions addressing: - PG&E’s capital structure; - The Avoided Cost Calculator; - High-DER grid-modernization reporting; - SCE’s fire-threat map; - SDG&E’s borrowing authority; - Oil-pipeline rates; and - The Clean Miles Standard. One major item remained unresolved. The CPUC again postponed [Draft Resolution E-5455](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K718/607718746.PDF?ref=calregulatory.com), which would approve PG&E's agreement to energize Google's 250-MW San Jose data center. This item is now scheduled for consideration at the Commission's **September 17** meeting. _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: IOU Research Spending and a Changing Crude Pipeline Market URL: https://www.calregulatory.com/wednesday-aggregate-34/ Last updated: 2026-09-02T12:30:00.000Z Today's aggregate covers more than **$1 billion** in proposed EPIC research spending and SoCalGas’ updated safety and risk-mitigation spending, alongside two significant crude-pipeline matters. Crimson California Pipeline is seeking a **10%** rate increase as crude volumes decline, while California Resources Corporation is challenging Pacific Pipeline over curtailments that it says have cut Line 63 shipments by approximately half. The timing is notable. CRC, California’s largest oil producer, has completed its acquisition of Crimson Pipeline, giving it a larger role in the infrastructure that moves California-produced crude to market. ### WEDNESDAY LINKS - **California Declines to Fund its Biggest Virtual Power Plant:** "State budget language finalized last week does not authorize additional money for the [Demand Side Grid Support program](https://www.energy.ca.gov/programs-and-topics/programs/demand-side-grid-support-program?ref=calregulatory.com), one of [the biggest VPPs in the country](https://www.linkedin.com/pulse/california-built-worlds-largest-virtual-power-plant-could-jigar-shah-5rbpc/?ref=calregulatory.com). Friday was the last day for bills to be published before being voted on by the Aug. 31 deadline for this year’s legislative session. But that budget language also excluded a plan from \[**Gavin**\] **Newsom**, a Democrat, to shift control of the program from the California Energy Commission to the California Public Utilities Commission, which DSGS supporters [feared could lead to it being dismantled entirely](https://www.canarymedia.com/articles/virtual-power-plants/california-fund-or-kill-vpp-program?ref=calregulatory.com)." [**CANARY MEDIA**](https://www.canarymedia.com/articles/virtual-power-plants/california-guts-biggest-virtual-power-plant?ref=calregulatory.com) - **California's Draft Building Performance Standard Covers Buildings Above 50,000 Square Feet, While its New Remote-Inspection Right Stops Short of Commercial:** "Wood Mackenzie recorded 97.7 MW of US commercial and industrial storage installed in the first quarter of 2026, roughly 75 MW of it in California. Whatever rule the state writes for large buildings applies to the majority of the segment by volume." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/californias-draft-building-performance-standard-covers-build/?ref=calregulatory.com) - **California Resources Corporation Completes Acquisition of Crimson:** "The transaction was approved by the California Public Utilities Commission on August 13, 2026." [**YAHOO FINANCE**](https://ca.finance.yahoo.com/news/california-resources-corporation-completes-acquisition-203000933.html?ref=calregulatory.com) - **California VPP Bills Await Governor Newsom Signature, Octopus Energy Closes Investment in DERs Flex Platform Uplight:** "[Senate Bill 905 (SB 905) and SB 913](https://www.energy-storage.news/california-advances-two-bills-to-expand-virtual-power-plants-reduce-energy-rates/?ref=calregulatory.com), both authored by State Senator **Josh Becker**, cleared their final legislative hurdles and are expected to receive gubernatorial approval despite Newsom vetoing three VPP-related measures last year...**Nick Chaset**, CEO of Octopus Energy US, will also hold the role of CEO as Uplight. The two companies will introduce two of Octopus Energy’s products into Uplight’s solution suite." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/california-vpp-bills-await-governor-newsom-signature-octopus-energy-closes-investment-in-ders-flex-platform-uplight/?ref=calregulatory.com) - **Is Covering California's Aqueducts and Canals with Solar Panels Economical?** "A lot of the economic analysis that investors have to evaluate involves subsidies and tax incentives. But ultimately, the economic cost doesn’t change. It’s either fully supported by the investors or it is socialized. One way or another, we all pay." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/the-delusional-premises-of-woke-greens/?ref=calregulatory.com) - **Legislature Passes Plug-in Solar Bill:** "The California Legislature passed [SB 868](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB868&ref=calregulatory.com), which would allow customers to use small plug-in solar devices without obtaining utility approval, signing an interconnection agreement, or paying interconnection fees." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergyjournal.com/p/cej-alert-legislature-passes-plug?ref=calregulatory.com) - **Wildfire Costs Loom Over California Legislative Session That Passed Solar, Data Center Bills**: "California lawmakers passed a number of notable energy bills during the legislative session that ended Monday, including proposals to legalize balcony solar and remote inspections for some home energy projects. But they rejected an attempt by Gov. Gavin Newsom, D, to limit utilities’ wildfire liability, and are expected to pass a bill allowing insurers to pursue utilities for wildfire losses in a special session Tuesday." [**UTILITY DIVE**](https://www.utilitydive.com/news/wildfire-costs-california-legislature-solar/829295/?ref=calregulatory.com) --- _This post is for paying subscribers only._ ### TUESDAY BRIEFING: CPUC Weighs Higher GHG Targets & Offshore Wind Exit From TPP Base Case URL: https://www.calregulatory.com/tuesday-briefing-cpuc-weighs-higher-ghg-targets-offshore-wind-exit-from-tpp-base-case/ Last updated: 2026-09-01T12:30:33.000Z September at the CPUC kicks off with major questions on power-system planning. The Commission is considering higher interim greenhouse-gas targets for transmission planning, dropping offshore wind from the CAISO base case and procuring thousands of megawatts of storage in West Los Angeles as an alternative to transmission. On the gas side, the Commission is seeking comment on the next phase of Senate Bill 1221, including when neighborhood decarbonization projects are established, how utility shareholder incentives would work and when gas service could be retired. Also in Tuesday’s briefing: - PG&E reports a $225 million ERRA overcollection; - The electric IOUs oppose standardizing reverse-power-flow treatment in Integration Capacity Analysis; and - A draft resolution would impose new transparency and review requirements on meter-socket-adapter fees. ### TUESDAY LINKS - **CAISO Board Lifts Hold on Silicon Valley Transmission Projects**: "Two transmission projects in Silicon Valley can move forward to serve large loads and other increasing demand in the area, the [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) Board of Governors decided. CAISO originally included the projects — the South Bay Reinforcement Project and the 115-kV De Anza substation — in the ISO’s draft 2025-2026 [transmission plan](https://stakeholdercenter.caiso.com/InitiativeDocuments/Revised-Draft-2025-2026-Transmission-Plan.pdf?ref=calregulatory.com)." [**RTO INSIDER**](https://www.rtoinsider.com/140375-caiso-board-lifts-hold-silicon-valley-transmission-projects/?ref=calregulatory.com) - **California Legislature Passes Balcony Solar Bill:** "On Wednesday, state lawmakers passed the [Plug and Play Solar Act](https://leginfo.legislature.ca.gov/faces/billCompareClient.xhtml?bill%5Fid=202520260SB868&showamends=false&ref=calregulatory.com) (Senate Bill 868) to legalize [balcony solar](https://www.canarymedia.com/articles/solar/what-to-know-balcony-solar?ref=calregulatory.com), a form of DIY clean energy that’s taken off [in Germany](https://www.canarymedia.com/articles/solar/balcony-panels-germany-utah?ref=calregulatory.com). The bill, which garnered bipartisan support, now heads to the desk of Democratic Gov. **Gavin Newsom**. His office declined to say if he’ll sign or veto it within the 30-day deadline; if he does neither, it would still become law and take effect Jan. 1, 2027." [**CANARY MEDIA**](https://www.canarymedia.com/articles/balcony-solar/california-lawmakers-pass-bill-oking-balcony-solar?ref=calregulatory.com) - **Diablo Canyon's Fate – California's Nuclear Fight, Grid Reliability, and China's Energy Strategy** [**THE NEMETH REPORT**](https://www.youtube.com/watch?v=Dqc8EoLwzJQ&ref=calregulatory.com) - **Legislature Passes Data-Center Energy Reporting Bill:** "The California Legislature passed [AB 1577](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1577&ref=calregulatory.com), which would require large data centers to report electricity consumption and other operating information to the California Energy Commission and provide projected energy-demand information when applying for certain local permits." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergyjournal.com/p/cej-alert-legislature-passes-data?ref=calregulatory.com) - **Legislature Passes Virtual Power Plant Reliability Bill:** "The California Legislature passed [SB 913](https://leginfo.legislature.ca.gov/faces/billStatusClient.xhtml?bill%5Fid=202520260SB913&ref=calregulatory.com), which would create new pathways for networks of residential batteries and other customer-owned energy resources to receive compensation for supplying capacity needed to maintain grid reliability." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergyjournal.com/p/cej-alert-legislature-passes-virtual?ref=calregulatory.com) - **The Utility Nobody's Watching:** "PG&E installed a large package of AMI gas meters back in its Smart Meter rollout, 2006 to 2012, they were battery-powered. Now those batteries are failing, and when they die, the meter defaults to a prerecorded reading. Customers have received estimated bills running into the thousands of dollars because of failing meter batteries — one reported case hit $6,000\. In response, PG&E has filed a $498 million rate case to replace all those failing modules, the ones customers already paid for once, now pushing fifteen to twenty years old." [**KILOVAR**](https://kilovar1959.substack.com/p/the-utility-nobodys-watching) --- _This post is for paying subscribers only._ ### NEWS CODEX: Biomass Boost; Inverse Condemnation; Containerized Batteries vs. Building-Based Designs URL: https://www.calregulatory.com/news-codex-biomass-boost-inverse-condemnation-containerized-batteries-vs-building-based-designs/ Last updated: 2026-08-28T17:12:03.000Z - **California's Costly, Energy-Islanding Regulation – Why Big Oil Wants to Keep It:** "If gasoline sellers in California had access to an abundant, affordable supply, the state would be more resilient, and consumers would pay less." [**UNION OF CONCERNED SCIENTISTS**](https://blog.ucs.org/daniel-barad/californias-costly-energy-islanding-regulation-why-big-oil-wants-to-keep-it/?ref=calregulatory.com) - **California's Emissions Authority is Cracking:** "Without the power to set its own emissions standards, California’s ambitious climate goals will realistically be out of reach. That also means California can’t meet air quality standards for pollutants like nitrogen oxides — a main component of smog — required under federal law, and could face penalties." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/26/the-cra-that-broke-californias-back-01051912?ref=calregulatory.com) - **California's Neglected Infrastructure is Harming America:** "Abundance, California style, is a fraud. And it’s not just punishing California’s people and industry. In an appearance on *News Nation* last week, sparsely populated Wyoming’s lone member of the House of Representatives, [Rep. **Harriet Hageman**](https://ballotpedia.org/Harriet%5FHageman?ref=calregulatory.com), [took California to task](https://www.facebook.com/reel/974278695631323) for what she correctly identified as negligent water policies. As an attorney who worked on interstate water agreements in the Western United States prior to entering politics, Hageman knows what she’s talking about. 'California has failed its people, and it has failed the interior West in terms of its refusal to actually develop water for its citizens,' she said. 'California has essentially the same water infrastructure in place today, with 40 million people, that they had in the 1960s with 16 million people.'" [**MAVEN'S NOTEBOOK**](https://mavensnotebook.com/2026/08/21/edward-ring-californias-neglected-infrastructure-is-harming-america/?ref=calregulatory.com) - **California's Storage Trade Association Says Containerized Batteries are Safer Than Building-Based Designs:** "Four. That is the number of cases **Scott Murtishaw**, executive director of the California Energy Storage Alliance, said he could find in which fire spread from one battery container to a second, across more than 1,000 utility-scale containerized projects worldwide. In none of them, he said, did fire reach a third container. Murtishaw made the claim in an August 24 interview with Energy-Storage.News, in which he described containerized battery energy storage designs as significantly safer than indoor, building-based configurations. He named safety concerns and local opposition as the industry’s single largest barrier. He also set out the scale California has reached: a storage fleet of roughly 21,000 MW, against under 1,000 MW before 2020, and no Flex Alerts since capacity passed 4,000 MW in 2022." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/californias-storage-trade-association-says-containerized-bat/?ref=calregulatory.com) - **California County Locks in 20 Years of Cheaper Power with 7.7-MW System:** "The project will cover six parking lots at the Ventura County Government Center and generate nearly 9 million kilowatt-hours of renewable electricity annually." [**INTERESTING ENGINEERING**](https://interestingengineering.com/energy/california-county-locks-in-20-years-of-cheaper-power-with-7-7-mw-system?ref=calregulatory.com) - **California Passes Bill Allowing Customer-Owned Clean Energy to Compete with Traditional Power Sources for Grid Reliability:** "State Senate Bill 913 directs utility regulators to update Resource Adequacy rules, expanding Virtual Power Plant access to residential batteries, bi-directional electric vehicle charging, and smart home tech." [**PV MAGAZINE**](http://pv-magazine-usa.com/2026/08/28/california-passes-bill-allowing-customer-owned-clean-energy-to-compete-with-traditional-power-sources-for-grid-reliability/?ref=calregulatory.com) - **California Senate Passes Bill to Boost Biomass Power Generation:** "The California Senate on Aug. 26 unanimously voted to pass the Forest Organic Residue, Energy and Safety Transformation (FOREST) and Wildfire Prevention Act, which authorizes the establishment of a new program to maintain and expand biomass power generation within the state." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/california-senate-passes-bill-to-boost-biomass-power-generation?ref=calregulatory.com) - **Newsom's Climate Whisperer Gets Some Political Cover:** "**Lauren Sanchez** cleared a major political hurdle on Tuesday, winning approval from the Senate Rules Committee for her appointment as California Air Resources Board chair after a confirmation hearing that doubled as a referendum on California’s shifting climate strategy." [**POLITICO** ](https://www.politico.com/newsletters/california-currents/2026/08/25/newsoms-climate-whisperer-gets-some-political-cover-01050195?ref=calregulatory.com) - **PacifiCorp to Suspend California Energy Efficiency Programs Under Proposed Settlement:** "The programs have 'historically not provided cost-effectiveness benefits to ratepayers and, indeed, show a decline in performance in recent years,' said the state public advocates office." [**UTILITY DIVE**](https://www.utilitydive.com/news/pacificorp-suspend-california-energy-efficiency-programs/828721/?ref=calregulatory.com) - **PG&E's Flexible Interconnection Program Has Seven Sites Operating After Two Years:** "Seven projects are operating under PG&E’s Flex Connect program two years after launch, and two of them have since converted to firm interconnections because the distribution upgrades they were waiting on caught up, Latitude Media reported. The first flexible data center site, 5 MW in the Bay Area, is scheduled for this fall." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/pges-flexible-interconnection-program-has-seven-sites-operat/?ref=calregulatory.com) - **The Limits of Newsom's Abundance:** "Gov. **Gavin Newsom** is finding a limit to his efforts to waive some environmental rules in order to build big. On Tuesday night, the Solano County Board of Supervisors voted not to endorse legislation that the governor’s team had helped negotiate to facilitate developer California Forever’s shipbuilding operations in the county, vastly dimming the legislation’s chances of advancing this year. The controversial developer, led by founder and CEO **Jan Sramek** and backed by tech luminaries, has spent years attempting to convince the county to let them build a dense new city in the hayfields southwest of Sacramento, and solve what they argue [are entrenched housing and economic challenges](https://subscriber.politicopro.com/article/2026/07/california-forever-takes-its-case-to-the-legislature-01013228?ref=calregulatory.com)." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/27/the-limits-of-newsoms-abundance-01053701?ref=calregulatory.com) - **We Make Cheap Clean Power – Why Do Our Factories Pay So Much For It?** "High demand charges layered with other fixed charges apply to every kilowatt used, no matter when, so a factory running on cheap midday solar pays the same as one running during expensive peak hours. There’s no reward for using power when it actually helps the grid. SB 943 fixes this disconnect by ensuring manufacturers pay for electricity in a way that better reflects when they use it, rather than discouraging electrification. The bill authorizes the Public Utilities Commission to cap add-on electricity charges for manufacturers switching equipment off gas. That way, companies investing in clean industrial equipment can actually benefit from California’s low-cost clean energy. It also directs the CPUC to recommend transmission pricing reforms to the state’s grid operator, aligning costs with grid strain and rewarding factories for shifting usage to cheaper, cleaner off-peak hours." [**CAPITOL WEEKLY** ](https://capitolweekly.net/from-fines-to-fixes-a-better-way-to-clean-up-industry/?ref=calregulatory.com) - **Who Should Pay for Utility-Ignited Wildfires?** "[California’s liability framework is stricter than in other states.](https://drive.google.com/file/d/1NJghS1g3Y4LlZ1QpDx7cWfq26ogMbDl3/view?ref=calregulatory.com) Elsewhere, wildfire plaintiffs generally have to prove that a utility was negligent to recover damages. In California, a doctrine called 'inverse condemnation' allows property owners to recover property damages and legal fees whether or not the utility is found negligent. Whether the utility absorbs those costs or passes them to their customers is decided separately, by regulators." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/08/24/who-should-pay-for-utility-ignited-wildfires/?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: Scoping Memos Set Terms on Billions in IOU Spending URL: https://www.calregulatory.com/wednesday-aggregate-33/ Last updated: 2026-08-26T15:39:50.000Z Today’s aggregate is heavy on CPUC scoping memos, with the Commission setting the terms for several major proceedings involving: - Resource Adequacy; - The Sempra Utilities' 2028 General Rate Cases; - Smart-meter replacement; and - The Sempra IOUs' SAP migration. Each of the IOU cases involves heightened scrutiny of cost allocation and whether proposed investments are truly necessary before billions of dollars are added to rates. The RA proceeding, meanwhile, moves from UCAP adoption to implementation questions that will determine how the RA framework functions in 2028. _This post is for paying subscribers only._ ### September 3, 2026 CPUC Voting Meeting Preview: GRC Overhaul, PG&E Capital Structure URL: https://www.calregulatory.com/september-3-2026-cpuc-voting-meeting-preview-grc-overhaul-pg-e-capital-structure/ Last updated: 2026-08-25T12:30:14.000Z At [next week's CPUC voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M615/K890/615890323.pdf?ref=calregulatory.com), the Commission is expected to launch a new rulemaking that would rewrite the General Rate Case framework. The proceeding would standardize utility filings, expand review of actual-versus-forecast spending, and bring more major cost requests into the GRC process. Also before the Commission: - Competing decisions on PG&E’s capital structure; - Nearly **$4 billion** in new SDG&E debt authority; - Approval of Google’s 250-MW San Jose data center interconnection; - Changes to the Integration Capacity Analysis; - Updates to the Avoided Cost Calculator; - An expansion of SCE’s High-Fire-Threat District; - A crude-pipeline rate increase, and - A Clean Miles Standard decision that would continue to withhold penalties from Uber and Lyft for missing state emissions targets. **ODDS & ENDS:** For those interested in my work elsewhere, I've created a [page](https://www.calregulatory.com/other-media/) with links to my contributions at RTO Insider, Energy Central, LinkedIn and my personal Substack blog. And, slightly off-topic, having recently driven through Los Angeles en route to Arizona, past Mulholland Drive and environs, **Jean Baudrillard**'s [*America*](https://www.amazon.com/dp/B0FNJML61X?lv=shuf&channelId=500&plpRedirect=mhFallback&ref=calregulatory.com) sprang to mind. I recommend the book, particularly its description of L.A. --- _This post is for paying subscribers only._ ### SATURDAY BRIEFING: PCIA Reform, Data Center Forecasts, and Aliso Canyon URL: https://www.calregulatory.com/saturday-briefing-pcia-reform-data-center-forecasts-and-aliso-canyon/ Last updated: 2026-08-22T17:30:17.000Z In today's briefing: - The CPUC is reopening the structure of the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) even while acknowledging it already satisfies the legal indifference standard; - The Commission is forcing PG&E to show how much of its data-center forecast rests on actual commitments rather than earlier-stage interest; and - SoCalGas and the Indicated Shippers are asking the Commission to delay the next assessment in the Aliso Canyon Biennial Assessment proceeding long enough to incorporate a still-evolving methodology. --- _This post is for paying subscribers only._ ### NEWS CODEX: CAISO Forecasting Challenge; Offshore Fracking; Iron Air Batteries URL: https://www.calregulatory.com/news-codex-caiso-forecasting-challenge-offshore-fracking-iron-air-batteries/ Last updated: 2026-08-22T23:55:15.000Z - **CAISO's Load-Balancing EDAM Math Doesn't Add Up, Says CPUC Staff:** "'I think the strongest element of Energy Division’s comments is that currently available public data don’t allow stakeholders to reproduce the calculations behind some of the CAISO’s key results,' energy and regulatory analyst **Michael Cade** wrote in comments to Utility Dive. 'That discrepancy alone doesn’t show that the adjustments were wrong. CAISO uses a separate, higher uncertainty benchmark to calculate them.'" [**UTILITY DIVE**](https://www.utilitydive.com/news/caiso-load-balancing-edam-cpuc-staff-powerex/828142/?ref=calregulatory.com) - **California's New Tire Efficiency Rules Could Save Drivers $1B a Year:** "On Monday, the California Energy Commission unanimously approved a rule that would phase in the nation’s first standards for tire efficiency. [The rule](https://www.energy.ca.gov/publications/2026/californias-proposed-replacement-tire-efficiency-program?ref=calregulatory.com) is 'designed to ensure that replacement tires sold in the state are at least as energy efficient, on average, as tires sold in the state as original equipment.' It would also establish a labeling system that gives tires a 'leaf' rating, to make it easier for consumers to find the best options. In addition to saving drivers money, the state projects that the changes could reduce carbon dioxide emissions by 2 million tons annually, which it says is equivalent to taking around 400,000 cars off the road." [**GRIST**](https://grist.org/transportation/californias-new-tire-efficiency-rules-could-save-drivers-1b-a-year/?ref=calregulatory.com) - **California Passes Restrictive Replacement Tire Law in the Name of Efficiency:** "**Bret Gladfelty**, on behalf of Goodyear, told the commission that this will increase costs for consumers and said the commission had yet to resolve technical and legal issues with the rules. In a letter to the CEC, Gladfelty had questioned the data the CEC released to the public about the cost of new tires, noting that while the commission says the price increases average about $6.50 per tire in phase 2, Gladfelty warned \[increased\] costs could actually end up being in the several hundreds of dollars." [**JALOPNIK**](https://www.jalopnik.com/2240366/regulators-pass-new-rules-for-efficient-california-tires/?ref=calregulatory.com) - **CAISO Warns of Forecasting Challenges from Large Loads:** "To address potential forecasting problems, CAISO is working on four potential solutions: - Load growth information: obtain better visibility into projected new load additions. - Effective operating profiles: obtain typical large loads’ demand characteristics, such as median daily demand profiles, which will inform CAISO’s baseline forecasting assumptions. - Load movement and variability: obtain schedules and actual metered demand for large loads, which will improve intraday and day-ahead tracking. - Operating limits and constraints: obtain information about minimum and maximum consumption levels, ramping characteristics, and flexibility or curtailment capabilities." [**RTO INSIDER**](https://www.rtoinsider.com/139257-caiso-warns-forecasting-challenges-large-loads/?ref=calregulatory.com) - **California Coastal Commission Objects to Offshore Fracking Proposal:** "The California Coastal Commission unanimously [objected](https://www.coastal.ca.gov/meetings/agenda/?ref=calregulatory.com#/2026/8) on August 13, 2026 to DCOR LLC’s proposal for hydraulic fracturing, known as fracking, at 16 wells on Platform Gilda in federal waters off Ventura, California. The proposal would have been the first fracking off California’s coast in more than a decade. The vote comes after the commission released [two staff reports](https://www.californiaenergyjournal.com/p/coastal-commission-staff-reports?ref=calregulatory.com) on the project in July." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergyjournal.com/p/california-coastal-commission-objects?ref=calregulatory.com) - **California Shows its Love/Hate Relationship with Nuclear Energy:** "The ongoing political conflict puts California out of step with a national turn of opinion towards nuclear energy. The Los Angeles Times recently reported that at a public meeting in San Luis Obispo County, where the plant is located, half the public comments favored the plant’s continued operation and half were opposed. Nationally, [one recent poll](https://www.bisconti.com/blog/public-opinion-2026?ref=calregulatory.com) found that 77 percent favor nuclear energy." [**NUCLEAR NOTES**](https://www.nuclearnotes.org/p/california-show-its-lovehate-relationship?ref=calregulatory.com) - **Eight-Hour Energy Storage Gains Ground in California Ahead of 2030:** "Long-duration energy storage is gaining ground in California’s power system. A [new analysis](https://auroraer.com/resources/aurora-insights/market-reports/beyond-four-hours-assessing-the-pathway-for-ldes-in-caiso?utm%5Fsource=chatgpt.com) by Aurora Energy Research identifies the early 2030s as an entry window for eight-hour storage systems, as the cost gap with four-hour batteries narrows and the state’s regulatory framework evolves. The report, Beyond four hours: assessing the pathway for LDES in CAISO, examines the economic and regulatory outlook for long-duration energy storage in the market operated by the [**California Independent System Operator**](https://www.review-energy.com/solar/california-leaves-gas-behind-as-solar-energy-leads-electricity-generation-in-2026?ref=calregulatory.com). Aurora follows the California Public Utilities Commission’s definition of long-duration energy storage as resources capable of discharging at full power for eight hours or more." [**REVIEW ENERGY**](https://www.review-energy.com/almacenamiento/eight-hour-energy-storage-gains-ground-in-california-ahead-of-2030?ref=calregulatory.com) - **Iron Air Batteries – Niche, or Next Big Thing?** "With a discharge [cycle of up to 100 hours](https://sunlithenergy.com/what-is-iron-air-battery/?ref=calregulatory.com) and a [capacity of 3 megawatts per acre](https://cleantechnica.com/2021/07/24/form-energy-reveals-iron-air-100-hour-storage-battery/?ref=calregulatory.com), iron air batteries can store 300 megawatt-hours per acre. That’s more than twice the storage density of lithium ion batteries, which at a capacity of [30 megawatts per acre](https://terraprosolutions.com/battery-storage-land-requirements-what-developers-and-landowners-must-know/?ref=calregulatory.com) but only 4 hours of discharge capacity, only store 120 megawatt-hours per acre." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-iron-air-batteries-niche-or-next-big-thing/?ref=calregulatory.com) - **Major Data Center Bills Advance in California Despite Industry Pushback:** "Two major data center bills passed a key committee last week as California’s legislative session nears its close at the end of this month. Senate Bill 886 aims to prevent data centers from raising utility costs for other consumers, while SB 887 would incentivize developers to invest in clean energy and nearby communities."[**CANARY MEDIA**](https://www.canarymedia.com/articles/data-centers/major-data-center-bills-advance-california?ref=calregulatory.com) - **Panelists: Better Tools Needed for Coordinating Multiple Western Markets:** "CAISO and SPP face a Sept. 30 deadline to submit a report to [FERC](https://www.rtoinsider.com/category/rto/rto-public-policy/rto-ferc-federal/?ref=calregulatory.com) on seams issues." [**RTO INSIDER**](https://www.rtoinsider.com/140055-panelists-better-tools-needed-coordinating-multiple-western-markets/?ref=calregulatory.com) - **ROWE Should Keep "Robust" CAISO Market Functions, Pathways Says:** "Representatives of the West-Wide Governance Pathways Initiative are recommending that the board of the Regional Organization for Western Energy keep in place [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com)’s market monitoring functions while ensuring there is a robust data-sharing framework after the ROWE assumes governance over the ISO’s energy markets. CAISO has one of the 'most robust market monitoring frameworks of any RTO in the country,' and the ROWE’s future board should transition those functions to the ROWE, Pathways Launch Committee Co-chair **Pam Sporborg**, of Portland General Electric, said at an Aug. 14 stakeholder meeting." [**RTO INSIDER**](https://www.rtoinsider.com/139233-rowe-should-keep-robust-caiso-market-functions-pathways-says/?ref=calregulatory.com) - **Three Ideas for Using More EVs and Flexible Resources to Support California's Grid – Report:** "A number of studies predict the vast potential of flexible resources–including a $6.7 to $9.9 billion distribution savings estimate from Kevala – which provides grid analytics. Investor-owned utilities such as Pacific Gas & Electric suggest that the value varies by time and location and is limited by customer adoption constraints, the report said. This poses a risk of exaggerating the potential and overpaying participants. In addition, California's demand flexibility programs differ from utility to utility, which means customers grappling with fragmented options are less likely to participate. The state’s net energy metering and net billing tariff are subsidized by customers who don’t participate in such programs and have sparked controversy over ratepayer equity, said **Pete Skala**, vice president of professional and advisory services at Kevala Analytics and a former California Public Utilities Commission energy division director." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/vehicle-to-grid/article/55398625/three-ideas-for-using-more-evs-and-flexible-resources-to-support-californias-grid-report?ref=calregulatory.com) - **Unlocking California's Flexible Load – a Durable Blueprint for Affordability and Reliability:** "The potential for electric loads to operate flexibly has already grown dramatically and will continue to grow. EV adoption continues to grow year over year in the state, despite the current federal headwinds. The California Energy Commission’s 2025 Integrated Energy Policy Report projects 8.4 million light-duty EVs in California by 2035.1 All-electric buildings, which represent an increasing portion of the state’s building stock and a large majority of new construction, provide significant load flexibility opportunities, primarily for electrified HVAC loads but also for smart appliances. Distributed storage is rapidly accelerating across residential and commercial sectors." [**GRIDLAB**](https://gridlab.org/portfolio-item/ca-flex-blueprint/?ref=calregulatory.com) - **Western Gateway Pipeline to Move Forward, Creating New Fuel Route into California:** "Phillips 66, Kinder Morgan and HF Sinclair have made a final investment decision to proceed with the $5 billion Western Gateway Pipeline, a 1,300-mile refined-products system designed to transport fuel from the Midwest and Gulf Coast to Arizona and California. The companies [announced](https://investor.phillips66.com/financial-information/news-releases/news-release-details/2026/Phillips-66-Kinder-Morgan-and-HF-Sinclair-Announce-Final-Investment-Decision-for-Western-Gateway-Pipeline/default.aspx?ref=calregulatory.com) August 11 that they had finalized a joint venture agreement for the project. Phillips 66 will own 49.9% of the system, Kinder Morgan 35.1% and HF Sinclair 15%." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergyjournal.com/p/western-gateway-pipeline-to-move?ref=calregulatory.com) - **Why Diablo Canyon Never Became a Load-Following Plant:** "When people ask why Diablo Canyon never became a load-following plant, the answer is not that the reactor was incapable of changing power. We changed power when necessary, and we knew how to do it safely. The answer is that Diablo Canyon was a baseload plant by design, by analysis, by operating philosophy and ultimately by licensing basis. Routine daily cycling would have represented a fundamental change in how the station was expected to operate." [**KENNETH KAMINSKI**](https://kennethkaminski.substack.com/p/why-diablo-canyon-never-became-a) - **Not Today, Diablo:** "If the Legislature does take up the issue next year, there’s an early ray of sunshine for Diablo’s boosters. When asked during a May debate whether the nuclear power plant should be extended beyond 2030, gubernatorial candidates **Xavier Becerra** and **Steve Hilton** both gave affirmative replies. 'Yes, extend it and build new ones,' said Hilton. 'Yes, but safety first, 'Becerra said." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/18/not-today-diablo-01041210?ref=calregulatory.com) - **Wildfire Liability for Dummies (and Smarties):** " Gov. **Gavin Newsom** has chosen one of the wonkiest, most complex topics in California politics as the focus of his final legislative push: Who pays for damages after a power company sparks a wildfire?" [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/20/wildfire-liability-for-dummies-and-smarties-01044992?ref=calregulatory.com) - **The Political Enemies United Against Newsom's Wildfire Plan**: "**Jamie Court** of the advocacy group Consumer Watchdog and California’s property insurance lobby have spent decades finding new and creative ways to make each other miserable. Now, they’re suddenly allies, thanks to the Newsom administration’s wildfire liability proposal." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/17/the-political-enemies-uniting-against-newsoms-wildfire-plan-01039716?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: Competing 2028 LOLE Studies Find CAISO Long on Capacity URL: https://www.calregulatory.com/wednesday-aggregate-32/ Last updated: 2026-08-22T23:56:27.000Z Today’s roundup looks at a 2028 CAISO portfolio so well supplied that neither Energy Division nor SCE could produce reliability events without first adding load or removing capacity. Today's briefing also examines the CPUC’s first major rewrite of electric utility procurement rules since 2015 and a SoCalGas filing that anticipates decreases for most customer classes on September 1, except BTS customers, whose rates will rise **1.1%**. _This post is for paying subscribers only._ ### TUESDAY BRIEFING: CPUC PD Would Deny Additional PCIA Credit for Pre-2019 RECs URL: https://www.calregulatory.com/wednesday-aggregate-31/ Last updated: 2026-08-22T23:59:03.000Z Today's roundup looks at a proposed decision that, if adopted, would reject CalCCA's effort to secure an additional credit for renewable energy credits generated before 2019\. The PD finds that their value was already allocated under the former PCIA methodology. Separately, another CPUC ruling sets detailed requirements for California Climate Credit reform proposals, emphasizing implementable designs and transparent customer-impact analyses. Additionally, Commissioner **Darcie Houck** has a new PD that revises the CPUC's Tribal Consultation Policy and Tribal Land Transfer Policy to expand tribal participation in CPUC matters and utility property sales. **BONUS MATERIAL:** For those who are interested in the CAISO's Extended Day-Ahead Market, I spoke to Utility Dive [for a piece that was published today](https://www.utilitydive.com/news/caiso-load-balancing-edam-cpuc-staff-powerex/828142/?ref=calregulatory.com). Also, over at RTO Insider, I have some news on [Ontario's developing approach to data centers](https://www.rtoinsider.com/139119-ontario-embraces-data-centers-but-proposes-guardrails/?ref=calregulatory.com). And for something completely different – I visited **Frank Lloyd Wright**'s Taliesin West last week. Some photos are available [here](https://www.linkedin.com/posts/mikecade%5Ffranklloydwright-activity-7493033989637746688-w7vO?utm%5Fsource=share&utm%5Fmedium=member%5Fdesktop&rcm=ACoAAAFZHzYBDlxMddOXs2LpUeAjlm7-LEe6hAo). \-- MC ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/08/1786478514887.jpeg) --- _This post is for paying subscribers only._ ### August 13, 2026 CPUC Voting Meeting Results URL: https://www.calregulatory.com/august-13-2026-cpuc-voting-meeting-results/ Last updated: 2026-08-22T23:57:11.000Z At its August 13 voting meeting, the CPUC approved a broad slate of utility measures, including a **$22 million** PG&E wildfire settlement, a **$1 billion** increase in PG&E's borrowing authority and new customer-level reliability reporting requirements for PG&E, SCE, and SDG&E. The Commission also allowed PG&E to withdraw its application for a **$93.5 million** Hinkley Compressor Station project, revised SoCalGas procurement rules, and streamlined oversight of Low Carbon Fuel Standard programs. But it once again delayed action on: - PG&E’s attempt to exclude approximately **$2.6 billion** in wildfire liabilities and state borrowing from its capital-structure calculation (which now involves competing PDs); and - PG&E's agreement to energize Google’s 250-MW San Jose data center. Those PG&E items are now tentatively scheduled for consideration on **September 3**. --- _This post is for paying subscribers only._ ### NEWS CODEX: Free Power Hour; New EDAM Member; 330 MW California Solar Project URL: https://www.calregulatory.com/news-codex-11/ Last updated: 2026-08-13T16:36:10.000Z - **3 Ways to Fix California's Utility Spending Problem – If Lawmakers Act:** "PG&E is seeking state regulator permission to spend [$73 billion through 2030](https://www.reuters.com/business/energy/pge-unveils-73-billion-spending-plan-meet-surging-data-center-energy-demand-2025-09-29/?ref=calregulatory.com), and Southern California Edison has told investors it plans to spend from [$38 billion to $41 billion through 2030](https://www.theglobeandmail.com/investing/markets/stocks/EIX/pressreleases/3592347/edison-international-highlights-massive-grid-modernization-plan/?ref=calregulatory.com)." [**CANARY MEDIA**](https://www.canarymedia.com/articles/utilities/3-ways-fix-california-utility-spending?ref=calregulatory.com) - **Becerra's Free Power Happy Hour:** "...the Democrat [announced an initiative](https://www.politico.com/news/2026/08/11/xavier-becerra-wants-to-give-californians-a-free-electricity-power-hour-01034803?ref=calregulatory.com) he called his 'power hour' that would give lower-income families two hours of free electricity per day...**Andrew Campbell**, executive director of the UC Berkeley Energy Institute at Haas, was also intrigued by the concept. 'It’s not a crazy idea,' he said. 'There’s free electricity on the grid at certain times, and having a mechanism to share that with consumers makes sense.'" [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/12/becerras-free-power-happy-hour-01035735?ref=calregulatory.com) - **BHE Montana Commits to Join EDAM in 2028:** "BHE Montana said it will join [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com)’s Extended Day-Ahead Market in 2028, increasing the number of participants committed to the new market to eight. BHE Montana (also known as PowerWatch) is a generation-only balancing authority and will add to EDAM more than 370 MW of wind power, 75 MW of battery storage capacity, and other resources in development. Controlled by Berkshire Hathaway Energy, the BA launched in 2022 with its headquarters in Great Falls, Mont." [**RTO INSIDER**](https://www.rtoinsider.com/138800-bhe-montana-commits-to-join-edam-in-2028/?ref=calregulatory.com) - **California's Gas Crisis is a Policy Failure at Every Level:** "California [passed](https://calmatters.org/environment/2026/03/california-iran-oil-profit-spike/?ref=calregulatory.com) a refinery profit margin cap under a 2023 statute, [AB X2-1](https://www.leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202320242AB1&ref=calregulatory.com), but regulators delayed implementation for five years, leaving the mechanism dormant at precisely the moment for which it was designed. The conflict in Iran shows no sign of resolution: As recently as June 1, the U.S. and Iran [exchanged](http://www.cnn.com/2026/05/31/politics/trump-iran-deal-changes?ref=calregulatory.com) fire in the Strait, and Iran asserted sovereignty over the waterway, [proposing](https://www.cbsnews.com/news/iran-war-oil-gas-prices-strait-of-hormuz/?ref=calregulatory.com) tolls of approximately $1 per barrel as a condition of any long-term reopening. The direct price impact of such a toll [is](https://www.eia.gov/todayinenergy/detail.php?id=47357&ref=calregulatory.com) modest, roughly two cents per gallon, but legitimizing Iranian control of the world’s most critical energy chokepoint carries geopolitical risks that markets are pricing far more seriously." [**REGULATORY REVIEW**](https://www.theregreview.org/2026/08/11/briggs-californias-gas-crisis-is-a-policy-failure-at-every-level/?ref=calregulatory.com) - **California Energy Regulator Says He's Open to Working with Trump on Oil Refineries:** "California is 'very focused' on maintaining refinery capacity, said California Energy Commission chair **David Hochschild**...signaling rare alignment with the Trump administration on energy policy." [**POLITICO**](https://www.politico.com/news/2026/08/11/california-energy-regulator-trump-oil-refineries-01033796?ref=calregulatory.com) - **California Reopened Non-Residential Rate Design, and Utility Billing Systems Will Set the Timeline:** "Whatever the Commission approves, the date it reaches a customer bill is set by infrastructure that rate proceedings rarely discuss. Writing in Utility Dive on August 7, GridX Chief Commercial Officer **Scott Engstrom** argued that legacy customer information systems built for analog meters, not regulatory appetite, are what actually gate rate design. The number of approved US electricity rates has grown roughly an order of magnitude in five years to more than 50,000\. Moving a complex rate into production routinely takes 18 to 36 months." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/california-reopened-nonresidential-rate-design-and-utility-b/?ref=calregulatory.com) - **California Surpasses 21,000 Megawatts of Battery Resources Supporting the State's Electric Grid:** "When Governor **Gavin Newsom** took office in 2019, less than 700 MW of battery storage served the grid. Today, total battery storage capacity is 21,112 MW, an increase of more than 2,500% in just seven and a half years. That’s equivalent to roughly one-third of the statewide peak demand, which exceeded 63,000 MW during the September 2022 heat wave." [**CEC**](https://www.energy.ca.gov/news/2026-08/california-surpasses-21000-megawatts-battery-resources-supporting-states?ref=calregulatory.com) - **FERC Approves CASO Start-Up Funding Plan for ROWE:** "FERC's approval of CAISO's funding plan for the ROWE allows the latter to obtain the financing it will need to prepare to assume governance of the EDAM and WEIM in 2028." [**RTO INSIDER**](https://www.rtoinsider.com/138878-ferc-approves-caiso-start-up-funding-plan-for-rowe/?ref=calregulatory.com) - **FERC OKs CAISO Interconnection Payment and Schedule Revisions:** "CAISO is tweaking its generator interconnection procedures and processes after years of being inundated with interconnection applications." [**RTO INSIDER**](https://www.rtoinsider.com/138532-ferc-oks-caiso-interconnection-payment-schedule-revisions/?ref=calregulatory.com) - **Fewer Pipelines, Mo Problems:** "Gov. **Gavin Newsom** signed a high-profile bill last year to increase drilling in oil-rich Kern County. Now, two things — a pipeline problem and an offshore oil operation — are throwing a wrench into that plan. Though it’s become easier to score a permit to drill in oil-rich parts of the state, it’s become more difficult for producers to secure space for their oil in one of the shared pipelines that transport product to the coastal refineries." [**POLITICO** ](https://www.politico.com/newsletters/california-currents/2026/08/06/fewer-pipelines-mo-problems-01028211?ref=calregulatory.com) - **Recurrent Energy Closes $695 Million Financing for 330 MW California Solar Project:** "The Cobalt Solar facility in Riverside County is under construction and is scheduled to reach commercial operation by late 2027." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/08/13/recurrent-energy-closes-695-million-financing-for-330-mw-california-solar-project/?ref=calregulatory.com) - **Steve Hilton's Populist Energy Message:** "The conservative commentator wants California to 'break up \[Pacific Gas & Electric’s\] monopoly,' according to a [policy proposal on his website](https://stevehiltonforgovernor.com/policy/ending-the-pge-nightmare?ref=calregulatory.com) titled 'Ending the PG&E nightmare.' The bold proposal, which would upend the state’s electricity system, evokes immediate comparison to \[**Tom**\] **Steyer**, who launched his campaign for governor by promising to 'break up the monopolistic power of utilities,' and turned the power companies [into one of his main foils](https://www.politico.com/news/2026/05/19/california-trump-utilities-power-companies-governors-race-00927196?ref=calregulatory.com)." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/05/steve-hilton-energy-populist-message-01026596?ref=calregulatory.com) - **The Wildfire Fight Newsom Can't Quit:** "**Gavin Newsom** has picked one of the wonkiest, most contentious issues to be his legislative capstone this month: a proposal protecting utilities like Pacific Gas & Electric from catastrophic wildfire liability. Wildfire victims and counties are calling the developing deal to reform the state’s existing back-up fund for utilities that spark wildfires a utility and corporate 'bailout.' Insurance companies are spending tens of thousands of dollars on advertisements attacking it, starting Monday. And environmental groups are [urging lawmakers](https://www.affordableenergycampaign.org/wp-content/uploads/2026/08/AEC-RequestforPublicProcesstoAdvanceWildfirePolicy-842026.pdf?ref=calregulatory.com) to reject any 'last minute, closed door deal.'" [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/10/the-wildfire-fight-newsom-cant-quit-01031974?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: FERC Large-Load Order Enters PG&E Tariff Case as CPUC Delays Google Vote URL: https://www.calregulatory.com/wednesday-aggregate-30/ Last updated: 2026-08-22T23:59:36.000Z Large loads lead Wednesday’s aggregate. FERC has landed squarely in PG&E’s transmission-level tariff case, forcing the CPUC to consider how its rules for data centers and other enormous customers would fit within a CAISO-wide regime. Also Wednesday: a draft resolution would put the CPUC’s Energy Division in charge of distribution-equity modeling, and a proposed decision would reject SCE’s bid to remove 61 areas from the state’s fire-threat map. Elsewhere, PG&E rate talks accelerate, and the major gas utilities move to widen eligibility for biomethane procurement. Two voting-meeting updates: - The Commission has [delayed action](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K701/614701903.PDF?ref=calregulatory.com) on Draft Resolution E-5455, which addresses PG&E’s agreement to energize Google’s 250 MW San Jose data center. The item moves from the CPUC’s **August 13** voting meeting to **September 3**; and - The CPUC has also [delayed action](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M614/K701/614701903.PDF?ref=calregulatory.com) on two competing PDs that address PG&E’s request to exclude Kincade- and Dixie-related financing from its regulatory capital structure. More information on those items is available [here](https://www.calregulatory.com/august-13-2026-cpuc-voting-meeting-preview-competing-capital-structure-pds-lead-pg-e-heavy-agenda/). Like Draft Resolution E-5455, both PDs tentatively move to the September 3 agenda. --- _This post is for paying subscribers only._ ### NEWS CODEX: Cap-and-Invest Auction Proceeds; Clean Imports; DER Wholesale Market Participation URL: https://www.calregulatory.com/news-codex-10/ Last updated: 2026-08-07T15:01:25.000Z - **A Fact-Based Appraisal of California's "Net Zero" Strategy:** "...if worldwide photovoltaic output increased by another two orders of magnitude, because it would take that much to even begin to make a replacement level contribution to global energy production, we would also have to increase our electricity storage capacity by at least four orders of magnitude from what it is today (current worldwide storage capacity times ten-thousand still only equals 45 exajoules). Notice those battery farms going in all over? Imagine 10,000 of them where one of them now stands. That’s what it will take, at a minimum, if the world’s energy economy electrifies, and does so while relying on intermittent energy sources. Does the earth have the resources to sustain such growth, and what would be the environmental impact?" [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-a-fact-based-appraisal-of-californias-net-zero-strategy/?ref=calregulatory.com) - **California's Carbon-Pricing Program Generated $36.2B for Climate Initiatives:** "California’s Cap-and-Invest program — a carbon-pricing mechanism that places a firm cap on major sources of greenhouse gas emissions throughout the state — has [generated $36.2 billion for climate investments](https://ww2.arb.ca.gov/news/report-shows-how-billions-cap-and-invest-dollars-continue-benefit-california-communities-0?ref=calregulatory.com) since its inception in 2013, according to a [new report from the California Air Resources Board](https://ww2.arb.ca.gov/sites/default/files/auction-proceeds/cci%5Fannual%5Freport%5F2026.pdf?ref=calregulatory.com)." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-carbon-pricing-program-generated-362b-for-climate-initiatives-carb/826598/?ref=calregulatory.com) - **Annual Report to the Legislature on California Investments Using Cap-and-Invest Auction Proceeds:** "In May 2026, the CARB board adopted amendments to the program following the Legislature’s enactment of new laws extending it to 2045\. The Cap-and-Invest program was updated to achieve its primary goals: reduce pollution cost-effectively, protect ratepayers, and keep businesses operating in California. Altogether, the updates are estimated to provide $10 billion in direct relief to electricity customers through bill credits and generate an estimated $8 billion for the GGRF through 2030." [**CARB**](https://ww2.arb.ca.gov/sites/default/files/auction-proceeds/cci%5Fannual%5Freport%5F2026.pdf?ref=calregulatory.com) - **California's Electricity Imports are Much Cleaner – How Much of it is Real?** "In [a new working paper](https://escholarship.org/uc/item/9zk9p6t8?ref=calregulatory.com), **Kevin Novan** and I have now done the forensic accounting of how much of California’s greening of imported electricity can be traced to west-wide emissions reductions and how much of it is reshuffling. The answer is about half. This can be seen as a glass is half-empty or half-full result, depending on your expectations." [**ENERGY at HAAS**](https://energyathaas.wordpress.com/2026/08/03/californias-electricity-imports-are-much-cleaner-how-much-of-it-is-real/?ref=calregulatory.com) - **California's Main Non-Residential Battery Storage Rebate Category Has Closed, with One Narrow Carve-Out Still Open:** "One pathway remains open. The San Joaquin Valley non-residential carve-out is active in Southern California Edison and Pacific Gas and Electric territory only, at a $1.00 per watt-hour incentive rate against $0.85 per watt-hour for the general non-residential step. It is a geographically bounded exception rather than a substitute for the statewide category." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/californias-main-nonresidential-battery-storage-rebate-categ/?ref=calregulatory.com) - **California DER Wholesale Market Participation Could Grow 2+ GW from CAISO "Accounting Change":** "A [revised demand response framework](https://stakeholdercenter.caiso.com/StakeholderInitiatives/Demand-Distributed-Energy-Market-Integration?ref=calregulatory.com) expected from the California Independent System Operator on Aug. 19 could incentivize upwards of 2 GW of behind-the-meter energy resources to participate in the ISO’s wholesale power market, according to Advanced Energy United’s lead regulatory official for the western United States. A draft proposal CAISO released last month would treat distributed energy resource aggregators as discrete resources, allowing them to export power within CAISO load zones until their net load hits zero." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-der-wholesale-market-participation-could-grow-2-gw-from-caiso/827122/?ref=calregulatory.com) - **California Was Mostly Solar-Powered in May – a Global First:** "Solar’s rise has helped California cut polluting energy sources out of its power mix. Natural gas is the only fossil fuel that California power plants burn at appreciable levels, and solar is steadily squeezing it out of the system. Case in point: Solar outproduced gas not only during its record month of May but throughout [every month](https://www.canarymedia.com/articles/solar/california-solar-ahead-of-gas?ref=calregulatory.com) in 2026 leading up to it, too." [**CANARY MEDIA**](https://www.canarymedia.com/articles/solar/california-solar-power-record-may?ref=calregulatory.com) - **Deadly Eaton Fire Sparked by SCE Tx Line, Officials Say:** "The California Public Utilities Commission is looking to include 47 new high-fire-threat areas in SCE’s territory. The CPUC’s [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M613/K135/613135536.PDF?ref=calregulatory.com) addresses a November 2024 [petition](https://www.sce.com/sites/default/files/AEM/Supporting%20Documents/SCE%E2%80%99s%20Petition%20for%20Modification%20of%20Decision%2017-12-024.pdf?ref=calregulatory.com) from SCE to revise certain fire-threat areas in its region based on updated fuel maps. Approval of the 47 new high-fire-threat areas would 'enhance public safety because stricter fire safety regulations would apply to these areas, in which SCE’s analysis indicates an elevated or extreme wildfire risk,' the CPUC said in the proposed decision." [**RTO INSIDER**](https://www.rtoinsider.com/138295-deadly-eaton-fire-sparked-by-sce-line/?ref=calregulatory.com) - **Debunking the Allegedly Prohibitive Cost of Desalination:** "The current electricity requirement for desalination to produce fresh water is 3,500 kilowatt-hours per acre foot. The electricity requirement will drop further as new desalination technologies mature. But at that rate, and priced at California’s commercial rate for electricity of [$0.26 per kilowatt-hour](https://commercialenergyadvisors.com/resources/commercial-electricity-rates-by-state-2026/?ref=calregulatory.com), electricity costs add another $910 per acre foot. If Californians paid the national average commercial price for electricity of $0.13 per kilowatt-hour, the electricity cost would drop to $455 per acre foot." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/debunking-the-allegedly-prohibitive-cost-of-desalination/?ref=calregulatory.com) - **Edison CEO – California Utilities Face Credit Downgrades Without Wildfire Reforms:** "California’s investor-owned utilities could see credit rating downgrades if state lawmakers fail to act before the end of the legislative session on Aug. 31, Edison International President and CEO **Pedro Pizarro** told analysts on Thursday’s second-quarter earnings call. He warned that the utility company hasn’t seen any draft legislation that would address the state’s soaring wildfire costs." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-utilities-credit-downgrades-wildfire-liability-edison/826678/?ref=calregulatory.com) - **Equipment Manufacturers Meeting on CARB Engine Emissions Regulatory Landscape – the Need for Regulatory Certainty:** "The manufacturers really just want CARB to recognize a realistic real world emission standard. CARB sets and enforces emission standards for new off-road engines sold or used in California, often exceeding federal EPA rules. making equipment manufacturers jump through ridiculous hoops, or make two sets of everything – one for California and one for the rest of the country." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/equipment-manufacturers-meeting-on-carb-engine-emissions-regulatory-landscape-the-need-for-regulatory-certainty/?ref=calregulatory.com) - **Experts Weigh in On Eastern Lessons as CAISO Launches Market Seams Effort:** "Western electricity industry stakeholders must pick and choose what lessons they draw from Eastern markets as they grapple with how to manage the seams between [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com)’s Extended Day-Ahead Market and [SPP](https://www.rtoinsider.com/category/rto/rto-spp/?ref=calregulatory.com)’s Markets+. And those stakeholders should be selective about what to include in a seams agreement between the two markets while also ensuring any agreement remains flexible enough to respond to changing market conditions. Those were among the top takeaways from a [market seams workshop](https://www.caiso.com/documents/presentation-market-seams-workshop-jul-31-2026.pdf?ref=calregulatory.com) CAISO held in Seattle on July 31, the first in a series of four monthly workshops it will host across the West." [**RTO INSIDER**](https://www.rtoinsider.com/138124-caiso-market-seams-workshop-pt-1/?ref=calregulatory.com) - **"Governance" Looking for the Mary Poppins Solution:** "As a senior staff member at FERC, I irritated my management about governance reform at the RTOs generally and worried about the governance of the California ISO and its inability at that time to meet the needs of a regional market." [**WESTERN POWER TRADING FORUM**](https://www.wptf.org/governance-looking-for-the-mary-poppins-solution/?ref=calregulatory.com) - **LA Fire Survivors Say Newsom is Trying to Help Utilities Reduce Their Wildfire Costs Again:** "'Californians deserve a government that works in the open, not behind closed doors,' said **Joy Chen**, leader of the Every Fire Survivor’s Network, in a press conference last week. She urged the governor to “choose democracy over corporate special interests.” [**CAL MATTERS**](https://calmatters.org/economy/2026/07/wildfire-liability-battle/?ref=calregulatory.com) - **The Election-Year Gamble Behind California's Wildfire Talks:** "State lawmakers’ negotiations over how to divide the costs of catastrophic wildfires are running into a problem: No one knows for sure who will be sitting across the table next year. That uncertainty is shaping not only the substance of the debate, but its timing. Utilities, insurers and lawmakers must decide whether to strike a deal under Gov. **Gavin Newsom**, who has repeatedly intervened to shore up electric utilities facing huge wildfire costs, or gamble that the next governor and insurance commissioner will offer them better terms. The talks have intensified in recent weeks**,** even though there is still no actual proposal on the table." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/03/the-election-year-gamble-behind-californias-wildfire-talks-01023212?ref=calregulatory.com) - **What We're Watching This End-of-Session:** "[AB 1156](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1156&ref=cleanpowercalifornia.org) would make it easier and cheaper to build clean energy on fallowed Central Valley agricultural lands. It’s an elegant solution to two hard problems for California: There’s not enough groundwater to support continued farming at today’s levels, and California needs to build a lot more solar power to keep up with rising energy demand and its clean energy goals." [**THE CURRENT**](https://www.cleanpowercalifornia.org/what-were-watching-this-end-of-session/?ref=calregulatory.com) - **The High-Voltage End of Session:** "**Christine Aurre**, Newsom’s legislative affairs secretary, and **Ann Patterson**, a former senior Newsom adviser and current Stanford scholar, briefed the Assembly Democratic caucus on the governor’s priorities on Tuesday. Their focus was on sustaining the wildfire fund, backstopping utilities that owe huge sums of money after their equipment sparked wildfires, constraining litigation costs after fires and holding utilities more accountable, according to Assemblymember **Gregg Hart**." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/08/04/the-high-voltage-end-of-session-01024787?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: New ACC Values Could Hit Electrification; SoCalGas Rates Fall URL: https://www.calregulatory.com/wednesday-aggregate-29/ Last updated: 2026-08-23T00:03:34.000Z Wednesday’s CPUC aggregate leads with a new Avoided Cost Calculator update, which could trim the calculated benefits of building electrification by applying the electric sector’s greenhouse-gas value to both electric and gas measures. The PD also updates how the CPUC values generation capacity and transmission benefits as California’s grid becomes more electrified and renewable-heavy. Elsewhere, California’s four large IOUs are making their case against a risk-neutral approach to catastrophic events, while new spending data show SoCalGas capital expenditures running **25% above** an imputed CPUC benchmark. Meanwhile, SoCalGas is removing **$300.5 million** from rates as recovery tied to its delayed 2024 General Rate Case ends. And a new PD would make PG&E’s eventual 2027 GRC revenue requirement effective **January 1**, even though a decision is not expected until May. SoCalGas’ filing includes a **0.5%** BTS rate decrease, effective August 1. --- _This post is for paying subscribers only._ ### August 13, 2026 CPUC Voting Meeting Preview: Competing Capital-Structure PDs Lead PG&E-Heavy Agenda URL: https://www.calregulatory.com/august-13-2026-cpuc-voting-meeting-preview-competing-capital-structure-pds-lead-pg-e-heavy-agenda/ Last updated: 2026-08-23T00:04:20.000Z The CPUC’s **August 13** [voting meeting agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M613/K284/613284278.pdf?ref=calregulatory.com) is dominated by PG&E-related items spanning company finances, wildfire enforcement, large-load interconnection and gas infrastructure. The headline story involves competing proposed decisions that address PG&E’s request to exclude Kincade- and Dixie-related financing from its regulatory capital structure. Elsewhere on the agenda, a $22 million settlement would end the CPUC’s Mosquito Fire investigation. Google’s 250-MW San Jose data center would receive approval for its interconnection agreement. PG&E would gain another **$1 billion** in short-term borrowing authority (half of what it requested). And another PD would let PG&E withdraw its Hinkley compressor-station application after it began construction under an emergency exemption. The Commission will also consider: - Establishing an annual approval cycle for utility programs funded with Low Carbon Fuel Standard proceeds; - Extending utility arrearage-management plans; - Overhauling electric-reliability reporting; - Revising SoCalGas procurement rules; - Approving SCE’s sale of a shuttered hydroelectric plant; and - Allowing Sempra to reorganize its California utility holdings. --- _This post is for paying subscribers only._ ### DER Update: CPUC Moves Toward Flexible Connections, Statewide DER Rules URL: https://www.calregulatory.com/der-update-cpuc-moves-toward-flexible-connections-statewide-der-rules/ Last updated: 2026-08-23T00:04:57.000Z The CPUC’s High DER Future docket produced three significant developments this week, all aimed at making better use of the distribution grid as electrification increases demand for new connections. A July 28 proposed decision would reduce Integration Capacity Analysis workshops while requiring standardized biennial reports on utility grid-modernization spending and results. Comments filed the previous day revealed disagreements over two emerging policies. Flexible service connections let customers energize under operating limits instead of waiting for upgrades. DER orchestration would compensate or direct distributed resources to relieve grid constraints. Parties broadly support both concepts. The dispute is over how quickly to scale them, whether utilities or third parties should control the necessary platforms, and whether the CPUC should permit three utility-specific systems or establish a common statewide framework. --- _This post is for paying subscribers only._ ### NEWS CODEX: RAAIM Changes; EV Rebate; Land Use & Solar Permitting Timelines URL: https://www.calregulatory.com/news-codex-9/ Last updated: 2026-07-29T00:41:20.000Z - **CAISO Tees Up Changes to RA Incentive Program:** "[CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) proposed revisions to its monthly Resource Adequacy Availability Incentive Mechanism structure to include a more targeted, event-based availability process. RAAIM is the primary mechanism for CAISO to entice resources counted toward resource adequacy obligations to be available during stressed grid conditions." [**RTO INSIDER**](https://www.rtoinsider.com/137135-caiso-tees-up-changes-ra-incentive-program-availability/?ref=calregulatory.com) - **California to Offer a Novel $3,500 Rebate for First-Time EV Buyers:** "The program is funded with $270 million. Half of that will come from the state budget, and the other half — in a rare arrangement — will come from participating automakers, including Ford, General Motors, Honda, Hyundai, Kia, Lucid, Mitsubishi, Nissan, Rivian, Subaru, Tesla, Toyota, and Volvo." [**CANARY MEDIA**](https://www.canarymedia.com/articles/electric-vehicles/california-rebate-ev-buyers?ref=calregulatory.com) - **New Study Reveals How Land Use Affects Solar Permitting Timelines in California:** "While a complex mix of interconnection, permitting, land use and workforce training are often cited as [major bottlenecks](https://pv-magazine-usa.com/2023/03/17/the-four-main-bottlenecks-of-developing-small-scale-utility-solar-in-california/?ref=calregulatory.com), a first-of-its-kind study released by The Nature Conservancy and ECOnorthwest provides hard data on what is actually driving these delays. The report, titled [“The Pace of Solar Progress,”](https://www.scienceforconservation.org/products/the-pace-of-solar-progress?ref=calregulatory.com) contains an analysis of over 15 years of permitting data for 274 proposed utility-scale solar projects in California in various stages of the permitting process." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/07/28/new-study-reveals-how-land-use-affects-solar-permitting-timelines-in-california/?ref=calregulatory.com) - **The Pace of Solar Progress:** "Recent California Public Utilities Commission planning efforts underscore the magnitude and urgency of the solar development challenge. In the Integrated Resource Plan proceeding for the 2026-2027 Transmission Planning Process, the CPUC identified that meeting projected load growth and greenhouse gas reduction targets will require an unprecedented expansion of solar and storage capacity statewide. This reflects the increasingly important relationship between modeled resource needs and the permitting, interconnection, and land-use realities that shape large-scale solar deployment." [**SCIENCE FOR CONSERVATION**](https://www.scienceforconservation.org/assets/downloads/TNC%5FThe%5FPace%5Fof%5FSolar%5FProgress%5FFinal%5FReport.pdf?ref=calregulatory.com) - **PG&E Says it Has 12.7 GW in Data Center Pipeline as it Courts Smaller Loads:** "Pacific Gas and Electric now counts 12.7 GW in its data center pipeline, of which 490 MW of projects have executed interconnection agreements and another 3.9 GW are in final engineering, company officials said Thursday during a second-quarter earnings call." [**UTILITY DIVE**](https://www.utilitydive.com/news/pge-claims-127-gw-in-data-center-pipeline-as-utility-courts-smaller-loads/826099/?ref=calregulatory.com) - **Why California is Using Significantly Less Natural Gas for Producing Electricity:** "Because regional resource optimization now occurs at the day-ahead level rather than just in real-time (as was the case with the Western Energy Imbalance Market, or EIM), CAISO is using its fleet of gas-fired power plants at a significantly lower level. In fact, California gas-fired generation has fallen to historic lows during mid-day hours and much lower during the evening ramp. This dramatic shift is due in part because of the new market for imbalance reserves that the CAISO has implemented through DAME." [**GRIDLAB**](https://gridlab.org/why-california-is-using-significantly-less-natural-gas-for-producing-electricity/?ref=calregulatory.com) - **Why Do Californians Pay More at the Pump?** "Californians bought over 13 billion gallons of gasoline last year (down about 16% from the all-time high), spending nearly $60 billion. If our price premium only reflected higher taxes and environmental costs, California consumers would have paid about $70 billion less since 2015\. It seems well worth finding some answers." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/07/27/why-do-californians-pay-more-at-the-pump/?ref=calregulatory.com) - **Wildfire's Risky Business:** "This year’s wildfire liability rethink has its own set of stakeholders, including California’s power companies, insurers, disaster attorneys and wildfire survivors. The final shape of any bill will have massive implications for each of those groups. Last year’s Los Angeles area fires illustrated that the state’s conflagrations [can cause tens](https://www.nytimes.com/2026/05/31/climate/2025-wildfire-damage.html?ref=calregulatory.com), or even hundreds, of billions of dollars in damages." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/07/27/wildfires-risky-business-01013166?ref=calregulatory.com) - **Your Favorite EV is Out of Stock:** "**Gil Tal**, director of the University of California, Davis’ EV Research Center, said that while car sales data shows California drivers rushed to buy electric models in April and May, there was a steep drop-off in June. He argued the shift wasn’t linked to a change in shopping habits but rather a shortage of options available for purchase." [**POLITICO** ](https://www.politico.com/newsletters/california-currents/2026/07/28/your-favorite-ev-is-out-of-stock-01014319?ref=calregulatory.com) ### TUESDAY BRIEFING: SoCalGas’s $348M Tech Ask and the CPUC’s Clean Miles Retreat URL: https://www.calregulatory.com/tuesday-briefing-socalgass-348m-tech-ask-and-the-cpucs-clean-miles-retreat/ Last updated: 2026-08-23T00:05:59.000Z Tuesday's briefing examines four recent CPUC applications that SoCalGas filed outside its General Rate Case. The largest is a **$348.1 million** joint request with SDG&E to move a shared SAP platform off software that loses vendor support at the end of 2027\. The other three cover shareholder rewards under the Gas Cost Incentive Mechanism, allowances for seven gas-line connections, and a memorandum account for anticipated Olympics costs. Elsewhere, Commissioner **Christine Harada** issued a proposed decision that would close the second phase of the CPUC's Clean Miles Standard without penalties for transportation network companies that miss the state's greenhouse gas and electric-vehicle mileage targets. The PD calls enforcement premature and defers the question to a later record. Last, PG&E and Modesto Irrigation District are seeking CPUC approval of a 25-year agreement continuing the electric service-territory pact that governed the utilities from 2001 through 2025\. --- _This post is for paying subscribers only._ ### SATURDAY BRIEFING: SoCalGas Seeks 14.8% BTS Rate Increase as Southern System Faces Supply Deficit URL: https://www.calregulatory.com/saturday-briefing-socalgas-seeks-14-8-bts-rate-increase-as-southern-system-faces-supply-deficit/ Last updated: 2026-07-25T14:00:26.000Z Good morning. SoCalGas is proposing a **14.8% increase** in Backbone Transportation Service rates, by far the largest percentage increase among the customer categories in its 2028 General Rate Case. The request comes as the Southern System faces a more immediate strain: incoming supplies have fallen below minimum operating requirements, prompting a warning that noncore customers could face curtailment. Meanwhile, the CPUC is considering loosening some of SoCalGas’s gas-purchasing rules in response to declining supplier participation and thin market liquidity. Also: the CPUC has reopened its Building Decarbonization proceeding to consider whether Tribal lands should be exempt from the end of electric line-extension subsidies for mixed-fuel construction. ***If CRI has been useful for your organization,*** [***please consider becoming a paid subscriber today***](https://www.calregulatory.com/pricing-2/). --- _This post is for paying subscribers only._ ### Intervenors Zero In on SoCalGas's Gas-Transition Bet in 2028 Rate Case URL: https://www.calregulatory.com/intervenors-zero-in-on-socalgass-gas-transition-bet-in-2028-rate-case/ Last updated: 2026-07-22T12:30:31.000Z SoCalGas/SDG&E's Test Year 2028 rate cases drew 11 protests and six responses on July 20, hitting SoCalGas on two levels: - Whether its year-to-year spending and recovery mechanisms are justified; and - How much long-lived gas infrastructure customers should finance as gas use declines. SoCalGas seeks **$5.1 billion** for 2028, up **$485 million**, or **10.5%**, from what it expects to collect in 2027, with further increases through 2031\. SDG&E seeks **$3.8** billion, up **8.1%**. Those single-digit figures rest on a friendly baseline. Measured against 2024 (the last rates the Commission actually set) SoCalGas's request runs about **34%** higher and SDG&E's about **41%**. The Indicated Shippers reach the same point another way: against the **$4.232 billion** first authorized for 2027, SoCalGas's ask is up **20.5%**. By CRI's math, the four-year jump from 2024 comes to approximately **$1.3 billion** for SoCalGas. Its percentage trails SDG&E's, but it asks for more dollars, and it is gas-only, with no electric business to gain load as customers electrify. Cal Advocates [wants to make the case bigger](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M611/K588/611588384.PDF?ref=calregulatory.com). It asks the Commission to fold three separate proceedings into the General Rate Case: - SoCalGas's **$3.76 billion** advanced-metering project; - SDG&E's **$825 million** Smart Meter 2.0 proposal; and - The utilities' **$348.1 million** SAP software migration. Metering, billing and core software are basic utility functions, it argues, so those items belong in the budget review, and one combined case would show customers the full bill instead of splitting it across four dockets. --- _This post is for paying subscribers only._ ### TUESDAY BRIEFING: A Safety Spending Test, a $1 Billion Wildfire Fund, and the End of Rule 21's Flat Fee? URL: https://www.calregulatory.com/tuesday-briefing-a-safety-spending-test-a-1-billion-wildfire-fund-and-the-end-of-rule-21s-flat-fee/ Last updated: 2026-07-21T12:30:29.000Z Today's briefing examines three CPUC proceedings that could reshape how utilities justify spending and recover costs. - Commissioner **Christine Harada** issued a scoping memo for the latest incarnation of the CPUC’s Risk-Based Decision-Making Framework. - PG&E is seeking to extend a wildfire self-insurance program it says has saved customers **$1.8 billion** while accumulating more than **$1 billion** for claims and program expenses. - And the CPUC is assembling the cost and workload data needed to replace [Rule 21’](https://www.cpuc.ca.gov/Rule21/?ref=calregulatory.com)s flat **$800** interconnection application fee with a potentially tiered structure. --- _This post is for paying subscribers only._ ### NEWS CODEX: CAISO Moves; California OTC Plants; CPUC Heat Protections URL: https://www.calregulatory.com/news-codex-8/ Last updated: 2026-07-20T23:36:22.000Z - **CAISO Adjusts Return-to-Service Timelines for Offline Generators:** "[CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) will require offline generation facilities to either permanently retire or return to service within a 'reasonable amount of time' to ensure accurate transmission study results and interconnection service capacity and deliverability." [**RTO INSIDER**](https://www.rtoinsider.com/136722-caiso-adjusts-return-to-service-timelines-for-offline-generators/?ref=calregulatory.com) - **CAISO Ponders Need for Multiple Seams Agreements as 1st Workshop Nears:** "[CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) is considering whether a collective agreement or several bilateral agreements among stakeholders are necessary to solve looming seams issues stemming from the emergence of the ISO’s Extended Day-Ahead Market and [SPP](https://www.rtoinsider.com/category/rto/rto-spp/?ref=calregulatory.com)’s Markets+. CAISO and SPP want to institute an operating agreement between themselves for certain seams issues by the time Markets+ goes live in 2027, CAISO CEO **Elliot Mainzer** said at a Western Energy Markets Governing Body general session July 14\. However, such an agreement might not capture many other seams issues that involve EDAM, Markets+, transmission operators and other stakeholders, he said." [**RTO INSIDER**](https://www.rtoinsider.com/136640-caiso-ponders-need-for-multiple-seams-agreements-as-1st-workshop-nears/?ref=calregulatory.com) - **California's Data Center Dance:** "In the past 10 months, the CPUC has [green-lighted the grid hookup](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K970/595970063.PDF?ref=calregulatory.com) of three data center projects in the Bay Area. It’s requiring developers to pay the up-front costs to connect to the grid, and then receive a refund later from the utility, to prevent other customers from footing the bill if the projects fall apart. And CPUC staff proposed [approving a Google facility](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K718/607718746.PDF?ref=calregulatory.com) — which the agency describes as a data center but the company told POLITICO is actually a different type of digital infrastructure called a computing lab — which will have an electricity demand rivaling all of Marin County, according to the CPUC. Agency leadership is scheduled to vote on that proposal next month." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/07/15/californias-data-center-dance-01000207?ref=calregulatory.com) - **Californians Sour on Newsom's Push to Ban Gas-Powered Cars:** "Among likely voters, 65% oppose the termed-out governor’s edict and just 34% support it. The opposition among infrequent or nonvoters is even stronger. Negative attitudes are especially stiff in inland California — particularly the Central Valley — and among middle-class people with incomes between $40,000 and $100,000, those over age 55 and Republicans." [**LA TIMES**](https://www.latimes.com/california/newsletter/2026-07-20/skelton-monday-politics-newsletter-newsom-ev?ref=calregulatory.com#:~:text=Newsom%20issued%20an%20executive%20order,market%20nine%20years%20from%20now.&text=But%20roughly%20two%2Dthirds%20of,Public%20Policy%20Institute%20of%20California) - **California Reliability Program Taps OTC Gas Plants Rather Than Imports:** "A California reliability program could call upon natural gas plants this summer to reduce stressed grid conditions as the state tries to move away from backup diesel and imported power. Despite California's push to eliminate once-through cooling gas-fired plants, the state still relies on a handful of them to be on standby in case of extreme heat or other grid emergencies. The Electricity Supply Strategic Reliability Reserve Program, operated by the California Department of Water Resources, acts as an insurance policy and safeguards the state’s grid during extreme weather and compound events (overlapping heat waves, droughts and wildfires) driven by climate change, DWR Staff Services Manager **Mindy Graybill** said at a California Energy Commission business meeting July 9." [**RTO INSIDER**](https://www.rtoinsider.com/136368-calif-reliability-program-taps-natural-gas-rather-than-imports/?ref=calregulatory.com) - **California Resources Corporation Files for California Pipeline System Acquisition:** "California Resources Corporation filed an application with the California Public Utilities Commission seeking approval to acquire control of the San Pablo Bay Pipeline and Crimson California Pipeline, two major crude oil pipeline systems serving California refineries."[ **iMONZA**](https://www.linkedin.com/pulse/california-resources-corporation-files-pipeline-system-acquisition-6bqse/?trackingId=ftiQSCtZTm6EZfIknd4tog%3D%3D&ref=calregulatory.com) - **California Restricts Utility Shutoffs as Dangerous Heat Ripples Across State:** "As another stretch of dangerous heat [gripped the state](https://www.weather.gov/lox/?ref=calregulatory.com), the California Public Utilities Commission wrote stronger rules itself. In a 4-0 vote, the commission [lowered](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M610/K649/610649527.PDF?ref=calregulatory.com) the temperature at which utilities must stop shutting off power to delinquent customers, from 100 to 90 degrees, and ordered utilities to adopt a more protective, region-specific heat standard within six months." [**CAL MATTERS** ](https://calmatters.org/environment/2026/07/california-utility-heat-shutoff-rules-cpuc/?ref=calregulatory.com) - **FERC Orders CAISO, SPP to Deliver Report on Market Seams:** "[FERC](https://www.rtoinsider.com/category/rto/rto-public-policy/rto-ferc-federal/?ref=calregulatory.com) ordered [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) and [SPP](https://www.rtoinsider.com/category/rto/rto-spp/?ref=calregulatory.com) to submit a report on their joint efforts to resolve the seams expected to arise between the ISO’s Extended Day-Ahead Market and SPP’s Markets+, saying an agreement between the two operators could improve the economic performance of their respective markets. The July 16 order requires CAISO and SPP to detail how they are engaging with one another, identify specific seams and market coordination issues caused by regionalization, submit a plan on how to address those issues and identify areas in which the operators are not yet aligned. The deadline for submitting the report is Sept. 30, 2026." [**RTO INSIDER**](https://www.rtoinsider.com/136815-ferc-orders-caiso-spp-to-deliver-report-on-seams/?ref=calregulatory.com) - **Retail Electric Rate Increases Outpace Inflation with Prices Set to Rise Higher:** "LBNL flagged transmission and distribution system spending, much of it related to wildfire mitigation, as a significant driver of rate inflation in California. Reductions in retail sales magnified price increases for customers there and in New York and New England, LBNL said. All three regions have seen significant increases in behind-the-meter solar and battery capacity since 2019\. California has about [20.5 GW of distributed solar capacity](https://www.californiadgstats.ca.gov/?ref=calregulatory.com), according to the state public utilities commission — more than 40% of the California Independent System Operator’s [anticipated peak load](https://www.caiso.com/documents/2026-summer-loads-and-resources-assessment.pdf?ref=calregulatory.com) this summer." [**UTILITY DIVE**](https://www.utilitydive.com/news/retail-electric-rate-increases-outpace-inflation-with-prices-set-to-rise-hi/825391/?ref=calregulatory.com) - **San Francisco Completes Major Step as it Explores Public Power Expansion:** "San Francisco took a major step today as it explores public power expansion, with the Planning Commission voting unanimously to certify the final Environmental Impact Report for the City’s proposed acquisition of PG&E’s electric assets that serve San Francisco...The report evaluates the [PG&E Power Asset Acquisition Project](https://sfplanning.org/environmental-review-documents?title=PG%26E+Power+Assets+Acquisition+Project&field%5Fenvironmental%5Freview%5Fcateg%5Ftarget%5Fid=All&items%5Fper%5Fpage=10&ref=calregulatory.com). If San Francisco policymakers decide to proceed with a purchase, the SFPUC would need to physically separate the portion of PG&E’s existing electric system that serves San Francisco. This work – generally along the San Francisco-San Mateo County border – would create two systems to be safely, reliably, and independently operated." [**SAN FRANCISCO PUC**](https://www.sfpuc.gov/about-us/news/san-francisco-completes-major-step-it-explores-public-power-expansion?ref=calregulatory.com) - **Santa Barbara County Grants Sable Air Pollution Variance:** "On July 17, 2026, the hearing board of the Santa Barbara County Air Pollution Control District unanimously [voted](https://www.ourair.org/apcd-hearing-board-90-day-variance-rehearing-july-17-2026/?ref=calregulatory.com) to allow Sable Offshore Corp. a 90-day variance for exceeding air pollution limits for its Platform Heritage, which restarted oil production in March 2026." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/santa-barbara-county-grants-sable?ref=calregulatory.com) - **Sunrun, FranklinWH Expand BESS Virtual Power Plant Capacity in California, Texas:** "US residential solar installer Sunrun will expand its virtual power plant capacity in California, US to 425MW. Announced 14 July, Sunrun claimed that its California distributed power plant has more than 80,000 households enrolled this year, representing more than 110,000 residential battery energy storage systems. The power plant launched in 2024 with 16,000 Sunrun customers enrolled. The current enrollment marks a fivefold increase in just two years. Sunrun customers are compensated for participating." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/sunrun-franklinwh-expand-bess-virtual-power-plant-capacity-in-california-texas/?ref=calregulatory.com) - **Why Are We Sinking Billions into a Gas System We Plan to Leave Behind?** "The good news is that some states are trying to get ahead of this problem. Here in California, the PUC recently [authorized](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M610/K760/610760591.PDF?ref=calregulatory.com) a process for natural gas utilities to pilot neighborhood retire-and-electrify projects if this option appears cost effective and 67 percent of property owners sign on. Whether utilities will volunteer to make less money is the question regulators are now confronting in a [long-term gas planning proceeding](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/long-term-gas-planning-rulemaking?ref=calregulatory.com). None of this will make retire-and-electrify an easy choice. But it could give this option a fighting chance. Right now, it doesn’t have one." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/07/20/why-are-we-sinking-billions-into-a-gas-system-we-plan-to-leave-behind/?ref=calregulatory.com) ### July 16, 2026 CPUC Voting Meeting Results: Heat Protections Expanded and Major PG&E Decisions Delayed URL: https://www.calregulatory.com/july-16-2026-cpuc-voting-meeting-results-2/ Last updated: 2026-07-16T23:57:31.000Z The CPUC’s **July 16** voting meeting delivered immediate consequences for utility customers while postponing three of the day’s largest PG&E matters. - The CPUC lowered the extreme-heat threshold for suspending electric disconnections from 100 to **90 degrees**, authorized SoCalGas to recover **$54.4 million** in storage-integrity costs and approved a **$198.8 million** transmission project that will more than double normal load-serving capability in part of the Northern San Joaquin Valley. - The Commission also accepted a nine-month delay for 750 MW of PG&E-contracted solar paired with 450 MW of storage. Still unresolved are: - PG&E’s attempt to exclude approximately **$2.6 billion** in wildfire liabilities and state borrowing from its capital-structure calculation; - Its request for additional short-term borrowing authority; and - Its agreement to energize Google’s 250-MW San Jose data center. All three of those items were held until August 13. Below, CRI provides details on every significant energy item that carried, including any redlined changes and associated final stakes. --- _This post is for paying subscribers only._ ### NEWS CODEX: Plug-In Solar Kits; EV Rebates; Sodium-Ion BESS Factory URL: https://www.calregulatory.com/news-codex-7/ Last updated: 2026-07-15T03:02:44.000Z - **Avantus Signs 20-Year-Solar-Plus-Storage PPA with Clean Power Alliance:** "The deal covers the Rexford 2 project in Tulare County, California, which will pair 200 MW of solar capacity with 800 MWh of battery energy storage." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/07/14/avantus-signs-20-year-solar-plus-storage-ppa-with-clean-power-alliance/?ref=calregulatory.com) - **California-Based Nonprofit Now Accepting Pre-Orders for Plug-In Solar Kits:** "Bright Saver says the solar kits cost exactly what it pays to buy, ship and support them. The wholesale model is supported by a new membership program designed to grow help the group continue to deliver progress on legislative and economic priorities." [**PV MAGAZINE** ](https://www.pv-magazine.com/2026/07/14/bright-saver-begins-offering-plug-in-solar-kits-at-wholesale-costs-to-customers-nationwide/?ref=calregulatory.com) - **California Enacts $3,500 Rebates on Some EVs:** "California Gov. [**Gavin Newsom**](https://thehill.com/people/gavin-newsom/?ref=calregulatory.com) (D) on Monday signed new legislation establishing a $270 million rebate program for California residents called MyFirstEV. It will provide a point-of-sale rebate for eligible Californians purchasing their first zero-emission vehicle." [**THE HILL** ](https://thehill.com/policy/technology/5967919-california-ev-rebate-program/?ref=calregulatory.com) - **California School District Using Solar, Storage, V2G and a Microgrid to Power More Sustainable Future:** "The 1,171-kW microgrid will integrate solar, energy storage and electric vehicle chargers to support both the district’s operations and the broader grid. ForeFront Power, a San Francisco-based commercial and industrial-scale renewable energy solutions provider, will integrate a 408-kW/1632-kWh battery energy storage system with a 763 kW solar array on existing shade structures at two of the district’s parking lots." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/microgrids/campus/news/55390801/california-school-district-using-solar-storage-v2g-and-a-microgrid-to-power-more-sustainable-future?ref=calregulatory.com) - **How Newsom's Complex History with the Oil Industry Could Affect a Presidential Run:** "This year the California Air Resources Board [overhauled its cap-and-trade auctions](https://calmatters.org/environment/climate-change/2026/05/cap-and-invest-amendment-affordability/?ref=calregulatory.com), where refiners and other businesses purchase rights to emit greenhouse gases. The program was renamed cap-and-invest and refiners were given free emission rights as an inducement to remain in the state. Newsom hailed the changes, but environmental groups are incensed at the turnabout. This month the nonprofit [Communities for Better Environment filed suit](https://www.latimes.com/environment/story/2026-07-07/environmental-justice-group-sues-california-over-carbon-market-overhaul?ref=calregulatory.com) in Los Angeles, alleging the changes violated the California Environmental Quality Act." [**CAL MATTERS**](https://calmatters.org/commentary/2026/07/newsom-oil-industry-presidential-campaign/?ref=calregulatory.com) - **Lowering California's High Utility Costs Takes More Than Flashy Slogans – It Needs These Reforms:** "Government funding and public-private partnerships can keep some spending off utility books altogether. Californians would still pay for these investments, but through more cost-effective, transparent and equitable means than electricity bills." [**CAL MATTERS**](https://calmatters.org/commentary/2026/07/electric-costs-utility-budget-california/?ref=calregulatory.com) - **Peak Energy to Build 4 GWh Grid-Scale Sodium-Ion BESS Factory in California:** "It will cost around $71 million. The company, which is partially headquartered in the San Francisco Bay Area, said the investment will create hundreds of jobs and stimulate the local economy." [**PV MAGAZINE** ](https://pv-magazine-usa.com/2026/07/13/peak-energy-to-build-4-gwh-grid-scale-sodium-ion-bess-factory-in-california/?ref=calregulatory.com) - **PG&E Faces $22M Penalty for Mosquito Fire Under Proposed Agreement:** "The Mosquito Fire burned more than 75,000 acres and dozens of structures. A subsequent CPUC investigation of PG&E’s infrastructure found violations of state rules for the design, construction and maintenance of overhead electrical lines." [**UTILITY DIVE**](https://www.utilitydive.com/news/pge-wildfire-california-puc-penalty-mosquito-fire/825041/?ref=calregulatory.com) - **Sable Urges DOE to Consider Eminent Domain for California Petroleum Reserve:** "According to a June 2, 2026 letter first reported by [Politico](https://subscriber.politicopro.com/article/2026/07/as-trump-mulls-west-coast-oil-reserve-sable-says-doe-should-consider-eminent-domain-00986111?ref=calregulatory.com), Sable asked the DOE to assemble the property interests necessary for the project through voluntary acquisition where possible and, if necessary, through the federal government’s eminent domain authority." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/sable-urges-doe-to-consider-eminent?ref=calregulatory.com) - **Terra-Gen Starts Up Final Phase at California Solar-Storage Complex:** "The Lockhart IV solar farm is located in San Bernardino County and will supply electricity under a long-term power purchase agreement with a California load-serving entity. Terra-Gen said the new solar capacity is sufficient to power about 40,000 homes and businesses annually." [**RENEWABLES NOW**](https://renewablesnow.com/news/terra-gen-starts-up-final-phase-at-california-solar-storage-complex-1298039/?ref=calregulatory.com) - **The Escalating Energy War Between California and the White House:** "Every time California tries to move forward with plans to expand its renewable energy capacity and shift away from fossil fuels in favour of a green transition, the Trump administration seems to push back. So far, the California government has been successful in pursuing an agenda focused on clean energy and decarbonisation. Still, each federal push to quash these moves makes it harder to achieve the agenda." [**OILPRICE.COM**](https://oilprice.com/Energy/Energy-General/The-Escalating-Energy-War-Between-California-and-the-White-House.html?ref=calregulatory.com) - **The Pacific Premium:** "...California's carbon costs climbed: cap-and-trade allowance prices roughly doubled between 2021 and 2023, raising the embedded carbon cost in every gallon sold there. Oregon's Clean Fuels Program, in place since 2016, works similarly." [**INSTITUTE FOR ENERGY RESEARCH** ](https://www.instituteforenergyresearch.org/wp-content/uploads/2026/07/The-Pacific-Premium-IER.pdf?ref=calregulatory.com) ### MONDAY AGGREGATE: CPUC Hands Gas Customers a Price Argument in Aliso Canyon Proceeding URL: https://www.calregulatory.com/monday-aggregate-cpuc-hands-gas-customers-a-price-argument-in-aliso-canyon-proceeding/ Last updated: 2026-07-13T12:30:33.000Z Good morning. The CPUC has placed gas-price impacts at the center of the [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com) Aliso Canyon proceeding while foreclosing SoCalGas’ preferred outcome. - Commissioner **Karen Douglas** ruled that any increase above the facility’s current **68.6 Bcf** inventory limit is out of scope, but she also noted that reducing storage capacity would likely cause forward prices to rise. - Parties challenging a 10 Bcf reduction now have a commissioner-supplied premise on price impacts as the proceeding also considers revisions to [the framework](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K129/551129840.PDF?ref=calregulatory.com) governing future Aliso Canyon assessments. Meanwhile, a new proposed decision would allow PG&E to withdraw its **$93.5 million** Hinkley compressor CPCN application while carrying a detailed evidentiary checklist into its next cost-recovery case, including whether the station needs its current compression capacity under the 1-in-10 peak-day standard. Commissioner **Darcie Houck** also opened the comment period for a proposal requiring utilities to document how community engagement shapes climate-adaptation findings/spending. --- _This post is for paying subscribers only._ ### NEWS CODEX: Wildfire-Detection Satellites; CRC's Carbon Storage Work URL: https://www.calregulatory.com/news-codex-6/ Last updated: 2026-07-11T19:14:57.000Z - **Avantus Secures $525 Million to Support Major California Solar-Plus-Storage Project:** "The installation is currently under construction in eastern Kern County, and is expected to enter commercial operation by year-end. The financing package includes a tax equity bridge and letters of credit in addition to the construction funding." [**POWER**](https://www.powermag.com/avantus-secures-525-million-to-support-major-california-solar-plus-storage-project/?ref=calregulatory.com) - **BESS Developer Opts for California Energy Commission Fast-Track Approval After Facing Local County Ordinance Obstacles:** "Developer New Leaf Energy withdrew its application for a battery energy storage system in Santa Cruz County, California, US, choosing to seek approval through the California Energy Commission. Shortly after the developer’s decision, the Santa Cruz County Board of Supervisors voted on 30 June, unanimously to defer a local ordinance regulating BESS. New Leaf Energy initially filed an application with Santa Cruz County in late 2024 seeking permission to construct a BESS facility valued at approximately US$200 million on Minto Road, outside of Watsonville, California." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/bess-developer-opts-for-california-energy-commission-fast-track-approval-after-facing-local-county-ordinance-obstacles/?ref=calregulatory.com) - **California Built the World's Largest Community Power Network – Why Dismantle it Now?** "The program, called Demand Side Grid Support, is a cornerstone of the state’s clean-energy and affordability strategy. Weakening this successful collaboration with residents would be a multimillion dollar mistake that would hurt every single ratepayer in California, not just the families who participate. Fortunately, **Newsom** signed the state budget this week, keeping DSGS operating through the end of the year. While this is an important first step, it is only temporary. Now, lawmakers must decide whether to preserve and expand one of California’s most successful energy programs, or begin dismantling it." [**BAKERSFIELD.COM**](https://www.bakersfield.com/opinion/opinion-california-built-the-world-s-largest-community-power-network-why-dismantle-it-now/article%5Fbb776b29-d5c5-45ab-85ec-589779fdac6d.amp.html?ref=calregulatory.com) - **How Wildfires Could Give Trump and Newsom Something to Agree On**: "Gov. **Gavin Newsom** and President **Donald Trump** are both trying to own the future of fighting wildfires with technology. Newsom used the launch of three new wildfire-detection satellites from the Central Coast’s Vandenberg Space Force Base this week to draw a contrast with Trump, pillorying the president’s budget and job cuts to forest and public lands agencies. The satellites, built by California manufacturer Muon Space and launched with support from a global nonprofit coalition called Earth Fire Alliance, will feed the California Department of Forestry and Fire Protection real-time data on wildfires from space." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/07/09/how-wildfires-could-give-trump-and-newsom-something-to-agree-on-00992534?ref=calregulatory.com) - **Peak Energy to Build 4 GWh Grid-Scale Sodium-Ion BESS Factory in California:** "Sodium-ion battery startup Peak Energy says its $71 million factory will be the first facility in the United States dedicated to grid-scale sodium-ion energy storage systems. Shipments are expected to begin in the first quarter of 2027." [**ESS NEWS**](https://www.ess-news.com/2026/07/09/peak-energy-to-build-4-gwh-grid-scale-sodium-ion-bess-factory-in-california/?ref=calregulatory.com) - **The Dismal Economics of Floating Offshore Wind:** "Proponents of floating offshore wind, to be charitable, want economic growth. But for economic growth to benefit *everyone* in the economy, it has to be a financially sustainable investment. Floating offshore wind does nothing of the sort. It would rob electricity ratepayers statewide in order to profit developers who could not hope to make their projects compete in a fair market. In Humboldt Bay, the state’s other proposed staging area for floating offshore wind farms, the economy would grow if responsible logging was permitted at the scale it attained forty years ago, while adding reasonable safeguards." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/the-dismal-economics-of-floating-offshore-wind/?ref=calregulatory.com) - **The Electrification Movement is Cooking with Gas:** "The Bay Area Air District — historically one of the most progressive regional air regulators in the nation — will vote in November on the future of a regulation that would ban the sale and installation of gas-powered water heaters in 2027 and furnaces in 2029\. While 10 board members voiced support for keeping the rules in place during a May hearing, another eight said they would support suspending them entirely. That’s already a major shift from 2023, when only one board member abstained from voting to pass the rule." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/07/06/the-electrification-movement-is-cooking-with-gas-00988414?ref=calregulatory.com) - **Southern California Clean-Heat Rule Survives Key Legal Challenge:** "Southern California’s landmark rule to slash emissions from industrial heating sources just notched a major victory in court. The region has some of the worst air quality in the U.S., and the gas-fueled boilers and water heaters that serve its factories and large buildings are a key culprit." [**CANARY MEDIA**](https://www.canarymedia.com/articles/electrification/southern-california-clean-heat-rule-survives?ref=calregulatory.com) - **The Oil Company Pivoting to Carbon Storage and Data Centers:** "California Resources Corporation, an energy company with its headquarters in Long Beach, is branching out as the state pushes toward a future that uses less oil. In May, CRC began [injecting carbon dioxide underground](https://www.politico.com/newsletters/california-climate/2025/10/16/a-labor-leader-an-air-regulator-and-an-oil-exec-walk-into-a-california-oil-field-00612931?ref=calregulatory.com) in Kern County’s Elk Hills. Its goal is to store carbon dioxide emissions from its nearby natural gas power plant in a depleted oil reservoir called Carbon TerraVault One." [**POLITICO** ](https://www.politico.com/newsletters/california-currents/2026/06/26/the-oil-company-pivoting-to-carbon-storage-and-data-centers-00978733?ref=calregulatory.com) - **Trump Chips Away at CARB, Yet Again:** "The most recent hit came last week, when the Environmental Protection Agency announced that it would end a longstanding practice of allowing California to act as the de facto national regulator of aftermarket car parts. This matters because the state has long policed aftermarket parts that can inadvertently or intentionally affect emissions controls on cars and trucks, causing them to spew more pollution into the air that harms public health." [**POLITICO**](http://politico.com/newsletters/california-currents/2026/07/08/trump-chips-away-at-carb-yet-again-00991242?ref=calregulatory.com) ### SATURDAY BRIEFING: CPUC Tees Up DER Market-Design Battle; PG&E's Mosquito Fire Bill Comes In at $22M URL: https://www.calregulatory.com/saturday-briefing-cpuc-tees-up-der-market-design-battle-pg-es-mosquito-fire-bill-comes-in-at-22m/ Last updated: 2026-07-11T19:10:37.000Z Good afternoon. The CPUC is beginning to turn years of discussion about flexible distributed resources into a concrete regulatory framework. New questions in the High DER proceeding ask parties to define how utility pilots, open-access platforms and CPUC-led working groups should fit together and to quantify the ratepayer savings that DER orchestration could produce. Elsewhere, the CPUC's Safety and Enforcement Division has proposed a **$22 million** Mosquito Fire settlement with PG&E that subjects the utility’s transmission-repair review process to an independent examination. Separately, a proposed decision would create a far more granular annual record of customer outages. Last, an email ruling clears testimony and hearings from the Demand Response bridge-year funding dispute, setting up a decision on the written record. --- _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: CPUC Tests Appetite for Broader Flexible Connections URL: https://www.calregulatory.com/wednesday-aggregate-28/ Last updated: 2026-07-08T12:30:11.000Z Good morning, the most consequential item in today’s aggregate is the CPUC’s push to expand flexible service connections, with comments due **July 21**. A [new proposal](https://www.calregulatory.com/flexible-service-connections-cpuc-proposal-would-make-controlled-load-a-standing-alternative-to-distribution-upgrades/) from **Commissioner Darcie Houck** would move constrained circuits away from being automatic upgrade triggers and toward being managed service conditions. Under the proposal, customers could connect under defined operating limits while utilities, DERs and grid-edge tools manage capacity constraints. Additionally, SoCalGas and PG&E are testing the exception process left over from the CPUC's [2022 gas-line subsidy decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K987/496987290.PDF?ref=calregulatory.com), and PG&E requests a **$26.6 million** shareholder award for a natural gas procurement year the CPUC later investigated. _This post is for paying subscribers only._ ### July 16 CPUC Voting Meeting Preview: PG&E Dominates the Agenda URL: https://www.calregulatory.com/july-16-cpuc-voting-meeting-preview-pg-e-dominates-the-agenda/ Last updated: 2026-07-07T12:30:34.000Z _This post is for paying subscribers only._ ### NEWS CODEX: Home Battery Revolution; Senate Bill 253; Kern Oil Doc URL: https://www.calregulatory.com/news-codex-5/ Last updated: 2026-07-09T23:46:17.000Z - **A Home Battery Revolution is Reshaping the Power Grid:** "Last year, the amount of U.S. home battery capacity enlisted in virtual power plants grew by 153 percent. Programs in Puerto Rico and California that paid homeowners for their stored energy were a 'key driver of the growth,' according to policy and research analyst **Madeline Turner** of San Diego-based Ohm Analytics. California’s VPP program, according to [Canary Media](https://www.canarymedia.com/articles/virtual-power-plants/new-bill-vpp-california?ref=calregulatory.com), 'has shown that its fleet of home batteries can be relied on much like a traditional power plant.' During a two-hour test last July, roughly 100,000 home batteries delivered about [539 megawatts](https://www.brattle.com/wp-content/uploads/2025/12/The-Demand-Side-Grid-Support-Program-An-Assessment-of-Scale-and-Value-December-2025-Update.pdf?ref=calregulatory.com) of energy — more than the output of a large gas peaker plant." [**YALE ENVIRONMENT 360**](https://e360.yale.edu/features/home-battery-vpps?ref=calregulatory.com) - **A Missing Piece in Climate Models – Nature's Own Emissions:** "Since launching last fall, Spark’s [program](https://www.sparkclimate.org/warming-induced-emissions/home?ref=calregulatory.com) on warming-induced emissions has connected more than 20 independent modeling groups from around the world to add those emissions to models, improve measurements, and explore ways to potentially reduce those emissions...One of the first projects coordinated through Spark’s warming-induced emissions campaign is the installation, by a team at the University of California, Los Angeles, of dozens of methane sensors at wetlands in central Africa, which are known to be [major emitters](https://acp.copernicus.org/articles/26/4601/2026/?ref=calregulatory.com) of methane. " [**YALE ENVIRONMENT 360**](https://e360.yale.edu/features/warming-induced-ecosystem-emissions?ref=calregulatory.com) - **California Delays Emission Reporting Deadline by 3 Months:** "The California Air Resources Board said it will delay the compliance deadline for California’s SB 253 — the Climate Corporate Data Accountability Act — and propose 'limited changes.'" [**UTILITY DIVE**](https://www.utilitydive.com/news/california-delays-emissions-reporting-deadline-by-3-months/823988/?ref=calregulatory.com) - **Choosing the Right Infrastructure Projects Can Deliver Affordable Abundance:** "...acknowledging an ongoing role for oil and gas is not a troglodytic rejection of modernity. It is recognition that fossil fuel still contributes over 80 percent of all energy consumption, [both worldwide](https://www.energyinst.org/statistical-review?ref=calregulatory.com) and [in California](https://www.eia.gov/states/CA/overview?ref=calregulatory.com). And even if consumption of crude oil were to be phased out completely by 2045, which is probably impossibly fast, we are still going to consume at least another [5 billion barrels](https://californiapolicycenter.org/five-billion-barrels-of-crude-oil/?ref=calregulatory.com) of oil. In a great irony, drilling for oil in California would *improve* air quality, because the only way to stop [natural seeps of methane](https://californiapolicycenter.org/the-best-way-to-eliminate-methane-leaks-is-to-drill/?ref=calregulatory.com) in our seismically active state is to deplete the underlying reservoirs." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-choosing-the-right-infrastructure-projects-can-deliver-affordable-abundance/?ref=calregulatory.com) - **Gas Prices are High for July 4 – California's Price-Gouging Fixes are Still on the Shelf:** "The oil industry sees that as a return to an old fight. **Zach Leary**, a lobbyist with the Western States Petroleum Association, said California already debated price-gouging penalties during the 2023 special session, and that the Energy Commission [decided](https://www.energy.ca.gov/filebrowser/download/7958?fid=7958&ref=calregulatory.com) the refinery-margin penalty could hurt supply, maintenance and consumers. \[**Senator Josh**\] **Becker** rejected that comparison, saying SB 493 targets a wartime emergency, not the regulation of refinery margins." [**CAL MATTERS**](https://calmatters.org/environment/2026/07/california-gas-prices-july-fourth/?ref=calregulatory.com) - **Gridmatic Study Shows Big Gap in Grid-Scale Battery Performance in California:** "A Gridmatic analysis of California’s battery storage fleet finds a wide gap in asset performance, showing that bidding strategy and operational execution — not just location or market conditions — are key drivers of revenue differences across utility-scale batteries in the California Independent System Operator market." [**ESS NEWS**](https://www.ess-news.com/2026/07/01/gridmatic-study-shows-big-gap-in-grid-scale-battery-performance-in-california/?ref=calregulatory.com) - **Kern Oil Documentary Explores California's Energy Future:** "In 2013, more than 3,500 new wells were drilled in Kern County. By 2024, that number had fallen to just 21 new wells." [**AGNET WEST**](https://agnetwest.com/kern-oil-documentary-california-energy-debate/?ref=calregulatory.com) - **PG&E Corporation Outlines its Role in California's Energy Transition as Investors Weigh Long-Term Risks:** "While the company’s business model is built around regulated returns, its risk profile is more complex than that of many peers due to historical wildfire exposure and related legal and financial consequences. Market participants therefore weigh the stability associated with essential-service utilities against the residual risks tied to operating in areas where climate and vegetation conditions can increase the likelihood of extreme events. This dual perspective often shapes discussions of valuation and potential long-term scenarios." [**AD HOC NEWS**](https://www.ad-hoc-news.de/boerse/news/ueberblick/pg-and-e-corporation-outlines-its-role-in-california-s-energy-transition/69706287?ref=calregulatory.com) - **Reliability Risks are Evolving, Grid in "Precious Position," NERC Says:** "Many of the emerging concerns facing the system are no longer driven by single contingencies or localized disturbances but by correlated and system-wide stresses, including energy limitations, operational challenges associated with maintaining reliability in lower-inertia systems, and declining availability of aging combustion generation..." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/bottom%5Flines/reliability-risks-are-evolving-grid-in-precarious-position-nerc-says/article%5F13d84b53-1f4e-4d34-9c7a-b80667aa15c0.html?ref=calregulatory.com) - **2026 Summer Reliability Assessment:** "Inverter-based resource output variability remains a concern, such as from the evening ramp requirements from declining solar and Santa Ana winds, which can overspeed wind turbines, requiring them to curtail." [**NERC**](https://www.nerc.com/globalassets/our-work/assessments/nerc%5Fsra%5F2026.pdf?ref=calregulatory.com) - **Satellite Data Reveals High Emissions in San Joaquin Valley, Offering California Officials Clear Opportunity to Protect Communities, Climate:** "[New analysis](https://library.edf.org/AssetLink/uamp718pxj51x4hlxlta1867goew671n.pdf?ref=calregulatory.com) of observations collected by MethaneSAT during 2024 and 2025 shows that the oil and gas operations in the San Joaquin Basin emit 18 tonnes of methane every hour, roughly 20% higher than [estimated by](https://www.epa.gov/ghgemissions/us-gridded-methane-emissions?ref=calregulatory.com) the U.S. EPA’s inventory, and twice as high as the state figures from the California Air Resources Board." [**ENVIRONMENTAL DEFENSE FUND**](https://blogs.edf.org/energyexchange/2026/06/25/satellite-data-reveals-high-emissions-in-san-joaquin-valley-offering-california-officials-clear-opportunity-to-protect-communities-climate/?ref=calregulatory.com) - **The Ninth Circuit Upheld Southern California's Zero-NOx Water Heater Rule by Separating Emissions From Energy Use:** "The rule is South Coast Air Quality Management District Rule 1146.2\. It sets zero-NOx limits on commercial and industrial water heaters and small boilers rated between 75,000 and 2,000,000 British thermal units per hour, phasing in from January 1, 2026 through 2033\. In practice the standard cannot be met by burning natural gas, so it functions as an electrification requirement for the covered equipment across the South Coast region, home to roughly 17 million people." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/the-ninth-circuit-upheld-southern-californias-zeronox-water-/?ref=calregulatory.com) - **Trump Targets California Again in SpaceX Feud:** "And, he’s at it again: the Trump administration has [launched ](https://www.theguardian.com/us-news/2026/jun/29/california-trump-administration-energy-production?ref=calregulatory.com)a formal federal investigation into the California Coastal Commission, significantly escalating ongoing battles over offshore energy production, commercial space launches and environmental oversight along the Pacific coastline. The National Oceanic and Atmospheric Administration is executing a comprehensive performance evaluation of California’s coastal management program under the federal Coastal Zone Management Act." [**OIL PRICE**](https://oilprice.com/Energy/Energy-General/Trump-Targets-California-Again-In-SpaceX-Feud.html?ref=calregulatory.com) ### July 2 CPUC Voting Meeting Results: PG&E $2.6B Capital Structure Decision Delayed; SOMAH Expansion Denied URL: https://www.calregulatory.com/july-2-cpuc-voting-meeting-results-pg-e-2-6b-capital-structure-decision-delayed-somah-expansion-denied/ Last updated: 2026-07-03T00:08:06.000Z As summarized in two standalone posts from earlier today, the Commission [adopted its final Track 1 Resource Adequacy decision](https://www.calregulatory.com/resource-adequacy-cpuc-adopts-2027-2029-local-capacity-and-ucap-framework-baker-presses-for-load-trading-market/) and a [final decision establishing the application process](https://www.calregulatory.com/sb-1221-cpuc-adopts-gas-decommissioning-pilot-framework-consent-rules-loosened-cost-shift-questions-remain/) for [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com&%5F%5Fcf%5Fchl%5Ff%5Ftk=vH6VhsGImisFwjXVTonIlzaoZljDakbxjCBkn7woSC0-1783030753-1.0.1.1-Z4IltYS2%5FzjmxZ1JtptD6o11Q0Iz2Wp4smW7RpS52FA) neighborhood decarbonization pilots. The CPUC also delayed action on a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K933/606933345.PDF?ref=calregulatory.com) that would deny PG&E's request to exclude approximately **$2.6 billion** in wildfire liabilities and a state loan from its capital structure calculation. **President John Reynolds** held that item until July 16 for further review. Other notable decisions and resolutions from the July 2 meeting are provided below. (Note that **Commissioner Christine Harada** was not present today.) _This post is for paying subscribers only._ ### SB 1221: CPUC Adopts Gas Decommissioning Pilot Framework; Consent Rules Loosened, Cost-Shift Questions Remain URL: https://www.calregulatory.com/sb-1221-cpuc-adopts-gas-decommissioning-pilot-framework-consent-rules-loosened-cost-shift-questions-remain/ Last updated: 2026-07-02T22:37:35.000Z On July 2, the CPUC adopted a [final decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K895/609895776.pdf?ref=calregulatory.com) establishing the application process for [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com&%5F%5Fcf%5Fchl%5Ff%5Ftk=vH6VhsGImisFwjXVTonIlzaoZljDakbxjCBkn7woSC0-1783030753-1.0.1.1-Z4IltYS2%5FzjmxZ1JtptD6o11Q0Iz2Wp4smW7RpS52FA) neighborhood decarbonization pilots. The decision creates the first formal pathway for gas corporations to propose voluntary projects that replace gas service with zero-emission alternatives and enable decommissioning of the underlying gas distribution system. The item carried 4-0\. (**Commissioner Christine Harada** was not present today). _This post is for paying subscribers only._ ### RESOURCE ADEQUACY: CPUC Adopts 2027-2029 Local Capacity and UCAP Framework; Baker Presses for Load-Trading Market URL: https://www.calregulatory.com/resource-adequacy-cpuc-adopts-2027-2029-local-capacity-and-ucap-framework-baker-presses-for-load-trading-market/ Last updated: 2026-07-02T21:22:14.000Z The CPUC adopted its [final Track 1 Resource Adequacy decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K912/609912508.pdf?ref=calregulatory.com) on July 2, setting CAISO's recommended Local Capacity Requirements at **23,618 MW** for 2027, **24,545 MW** for 2028, and **25,480 MW** for 2029\. The LA Basin climbs from 6,823 MW to 7,721 MW across the three years. The decision also adopts CAISO's 2027 Flexible Capacity Requirements, which reach their system-wide maximum in March at **30,378 MW**, with the CPUC-jurisdictional share at **29,063 MW**. _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: SB 884 Cost Questions; Rule 30 Recommendations; and Climate Credit Changes URL: https://www.calregulatory.com/wednesday-aggregate-27/ Last updated: 2026-07-01T23:17:05.000Z Today’s aggregate covers: - Utility responses in the Senate Bill 884 undergrounding proceeding (re: Benefit-Cost Ratios); - Cal Advocates’ recent fifth-floor communications on PG&E's Rule 30; - A possible affordability-focused redesign of the Climate Credit; and - A draft resolution streamlining IOU Low Carbon Fuel Standard spending plans. --- ### ELECTRIC LINE UNDERGROUNDING PG&E, SCE and SDG&E [filed their responses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K981/609981344.PDF?ref=calregulatory.com) to ALJ **Regina DeAngelis**'s [June 18 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K053/609053256.PDF?ref=calregulatory.com) in the[ Senate Bill 884](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220SB884&ref=calregulatory.com) undergrounding proceeding, which asked how the utilities intend to build and verify benefit-cost ratios (BCR) in Phase 2 applications. - SCE largely sat out, saying it has no current plan to submit an electrical undergrounding plan, leaving PG&E and SDG&E to address the substance. - PG&E says its project-cost estimates will follow [AACE-](https://en.wikipedia.org/wiki/AACE%5FInternational?ref=calregulatory.com)style maturity classes, with early projects at rough-order-of-magnitude levels that may be off by -50% to +100%, moving toward -5% to +10% as engineering advances. - Notably, PG&E treats cost estimates and risk-reduction estimates as separate categories with separate standards. Cost estimates mature as engineering advances; wildfire-risk modeling does not achieve comparable precision at any stage. Consequently, PG&E does not propose milestone-specific BCR accuracy ranges, and instead applies a flat **30%** uncertainty factor when comparing mitigation alternatives. - On O&M, PG&E says its assumptions are built mainly from 2023 General Rate Case forecasts and normalized historical data. Undergrounding is assumed to eliminate [PSPS](https://www.sce.com/outages-safety/outage-preparedness/outage-types/public-safety-power-shutoff-psps?ref=calregulatory.com)\-related and vegetation-management O&M, cut patrols, inspections and emergency work by approximately 90%, and reduce routine maintenance more modestly. - PG&E does not plan to track avoided O&M savings project by project after construction, arguing those savings are counterfactual and unfold over asset lives of 48 to 55 years. - SDG&E breaks from PG&E on this point: it says it will track actual O&M *costs* at the project level after construction, even though it agrees avoided savings are not directly observable either way. The filing also shows how PG&E wants to handle risks that may not be fully captured in the model. For evacuation constraints, tree-strike exposure and PSPS geography, PG&E says engineers will conduct more granular reviews outside the systemwide risk model. Those reviews could support targeted undergrounding or hybrid designs where full undergrounding isn't cost-effective, provided the hybrid option stays within PG&E's 30% uncertainty band and outperforms the full-undergrounding alternative. **INSTANT ANALYSIS:** PG&E is asking the CPUC not to treat SB 884 benefit-cost ratios as a mechanical ranking tool. Its main argument is that the cost side of the BCR gets more refined as projects mature, while the risk side stays a modeled estimate indefinitely. That gives PG&E room to apply engineering judgment when localized evacuation, vegetation, or PSPS conditions aren't captured cleanly by the model. The exception is defined, not open-ended. A hybrid design qualifies only if its BCR stays within 30% of the overhead alternative's BCR and beats the underground alternative's. PG&E's O&M claims deserve scrutiny. It projects major long-term avoided-cost benefits from undergrounding, but will not audit those savings project by project after construction (only through periodic GRC review at the program level). SDG&E commits to tracking actual post-construction O&M costs, though it treats avoided savings the same way PG&E does. --- ### LARGE LOAD TRANSMISSION Cal Advocates recently engaged in multiple ex parte communications in PG&E's [Rule No. 30 proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com). Cal Advocates argued Rule 30 should prevent ratepayers from subsidizing billions in transmission infrastructure, noting that data center-related upgrades approved over the past two years exceed **$4 billion**. Its recommendation for Type 4 network upgrade costs is a single proposal: an interim **$50 million** advance, or **$667/kW**, until a permanent method is developed. An attached handout lists three other approaches for comparison, not as Cal Advocates alternatives: - A CAISO-tariff-modeled option tying advances to contracted capacity; - The [Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K498/586498115.PDF?ref=calregulatory.com) method, capping refunds at **75%** of net revenue; and - PG&E's own "customer responsibility" proposal, which Cal Advocates says would produce no upfront financing because it excludes CAISO transmission planning process upgrades and upgrades not solely triggered by one customer. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/07/image.png) Cal Advocates urged the CPUC to reject PG&E's Base Annual Revenue Calculation refund structure and interest payments on refunds, arguing refunds should track actual revenues rather than forecasts so customers aren't refunded before load materializes. It characterized interest refunds as an unnecessary ratepayer burden, saying no other jurisdiction pursues them for large-load interconnections. It also noted that none of the large-load advice letters PG&E has filed in this proceeding have requested or received interest. Cal Advocates also backed a minimum demand charge on a fixed load ramp over PG&E's customer-specific ramp, citing gamesmanship risk. It said several other provisions have broader agreement among the proceeding's parties, including minimum contract terms/early termination fees and lowest-cost rules for applicant-built facilities. **INSTANT ANALYSIS:** Cal Advocates wants Rule 30 built on cost causation before PG&E's large-load queue becomes a ratepayer problem. The dispute is over Type 4 upgrades: PG&E's "incremental" definition excludes CAISO-Transmission Planning Process upgrades and anything not solely triggered by one customer, which Cal Advocates says leaves ratepayers financing most of the transmission build. The $50 million figure is a placeholder pending a permanent method. The real question is whether large-load customers can reserve transmission capacity now and push the financing risk onto other ratepayers. --- ### CLIMATE CREDIT CPUC **President John Reynolds** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K606/609606098.PDF?ref=calregulatory.com) directing the [Climate Credit ](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com)toward affordability, electrification, and usage-based need. The ruling states that the CPUC's earlier principle (withholding the credit during high-cost periods to preserve the carbon price signal) no longer reflects current statutory direction. [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com), the governor's affordability directive ([Executive Order N-5-24](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com)), and [a recent CPUC decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K990/605990203.PDF?ref=calregulatory.com) each point toward providing greater assistance during high-cost periods, particularly for high-usage and low-income customers. For the electric credit, Reynolds intends to prioritize three options: - Retaining the status quo with possible refinements; - Adopting his own proposal concept; or - Considering proposals from parties. His concept would replace the flat per-household credit with a modular structure. One version ties the number of credits to baseline usage: customers below baseline receive one credit, customers above baseline receive two, and CARE customers above baseline receive three. A second version ties the number of credits to climate zone, providing larger credits in hotter regions while relying on existing utility billing infrastructure. Reynolds also asks parties to address whether a purely volumetric, cents-per-kWh credit would better serve affordability and electrification goals than either tiered approach. The gas credit receives more limited treatment. CARB's [2026 Cap-and-Invest updates](https://ww2.arb.ca.gov/news/carb-adopts-updates-californias-cap-and-invest-program-support-affordability-and-align-climate?ref=calregulatory.com) will shift an increasing share of gas utility allowance value to electric utilities beginning in 2028, reaching 70% by 2031, with the remaining 30% reserved primarily to benefit low-income gas customers. Reynolds's concept would leave gas credit timing, eligibility, and distribution unchanged before 2028\. Beginning in 2028, the reserved 30% would be allocated among CARE gas customers, while the remaining, shrinking allowance pool would be distributed among non-CARE customers. This approach depends on CARE customers representing a small enough share of gas customers that they fare better under the reserved allocation than under the current equal-distribution structure. Opening comments are due **July 24**, with reply comments **July 31**. A workshop is scheduled for **August 10**. Party proposals are due **September 14**, and utility implementation assessments are due **October 9**. **INSTANT ANALYSIS:** This ruling reflects a change in the underlying rationale for the Climate Credit. The program was originally designed to preserve a carbon price signal by avoiding payment during high-cost periods. Reynolds's guidance reorients the credit toward affordability, directing greater assistance to customers facing higher costs. Both electric concepts raise distributional questions the ruling itself acknowledges. Usage and climate zone correlate with cost burden, but not precisely with income. A high-usage customer in a hot climate zone is not necessarily low-income, and Reynolds specifically raises the concern that added assistance could disproportionately benefit higher-income customers in hotter zones. The gas credit receives comparatively little attention because CARB's allowance reallocation is already reducing the pool available for distribution. Reynolds's approach limits Commission effort in this phase to preserving benefits for CARE customers as that pool contracts, rather than pursuing a broader redesign. --- ### LOW CARBON FUEL STANDARD [Draft Resolution E-5463](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K910/609910353.PDF?ref=calregulatory.com) streamlines the process by which PG&E, SDG&E and SCE seek approval for programs funded by [Low Carbon Fuel Standard](https://ww2.arb.ca.gov/our-work/programs/low-carbon-fuel-standard?ref=calregulatory.com) credit proceeds. If ultimately adopted, the draft resolution would replace the current ad hoc advice-letter process with a fixed annual cycle: - New implementation plans would be due **January 31**; and - Budget extensions would proceed through the **September 30** forecast advice letter. If that letter remains unresolved by year-end, the prior year's budget would remain in effect. The draft resolution also treats LCFS verification costs as overhead. Separately, medium- and heavy-duty electrification infrastructure would qualify as equity spending when it meets CARB requirements. The draft resolution accepts that truck emissions benefits may occur along travel corridors rather than only at a vehicle's domicile or charging location. These provisions respond directly to CARB's revised LCFS rules, which: - Shifted [Clean Fuel Reward](https://cleanfuelreward.com/site/home?ref=calregulatory.com) funding from light-duty EV rebates toward medium- and heavy-duty vehicle incentives; - Raised equity-spending requirements to 75% for large and medium IOUs; - Reduced required utility remittances to the statewide program; - Expanded the list of preapproved holdback projects; and - Added third-party verification requirements beginning in 2027. **INSTANT ANALYSIS:** The annual filing cycle is primarily administrative. It provides a predictable schedule, which benefits utilities and stakeholders tracking the docket. The substantive change originates with CARB. Funding is moving from light-duty rebates toward medium- and heavy-duty infrastructure. Additionally, the corridor-based approach to equity accounting means a charging site need not be located in a disadvantaged community to count as equity spending, provided the vehicles it serves operate in one. The result is a more expansive funding lane for freight and fleet electrification than previously existed. ### NEWS CODEX: At-Berth Regulation; Senate Bill 1221 PD; Gridmatic Study URL: https://www.calregulatory.com/news-codex-4/ Last updated: 2026-07-20T23:40:41.000Z - **California's Bad Energy Policy is the Real Threat to the AI Boom:** "California wants to lead the AI revolution. Companies are racing to build data centers here, drawn by the talent, the capital, and the technology sector that has defined the state’s economy for a generation. California utilities are already fielding service requests totaling 18.7 gigawatts of new capacity. There is one problem Sacramento has been slow to confront: its energy supply is not adequate to sustain the innovation it claims to champion. The culprit is not the data centers. It is California’s own energy policy."[**PACIFIC RESEARCH INSTITUTE**](https://www.pacificresearch.org/californias-bad-energy-policy-is-the-real-threat-to-the-ai-boom/?ref=calregulatory.com) - **California's Choice – Cleaner Air for Schools or Money for Utilities:** "The funds at stake are part of the California Schools Healthy Air, Plumbing, and Efficiency program, or [CalSHAPE](https://www.energy.ca.gov/programs-and-topics/programs/california-schools-healthy-air-plumbing-and-efficiency-program?ref=calregulatory.com), which funds schools’ HVAC and plumbing repairs and upgrades. The state required its three big utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — to fill the initiative’s coffers with about $1 billion in fees collected from customers between 2020 and 2023." [**CANARY MEDIA**](https://www.canarymedia.com/articles/carbon-free-buildings/california-schools-or-utilities?ref=calregulatory.com) - **California's Community Choice Aggregators are Leading the Way on Energy Storage:** "Three recent announcements by Community Choice Aggregators in California are shining a spotlight on the varying ways the municipal energy groups are leading the charge on integrating batteries into California’s electricity supply." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/06/29/californias-community-choice-aggregators-are-leading-the-way-on-energy-storage/?ref=calregulatory.com) - **Cleaning Up California's Ports – the At-Berth Regulation, Tanker Terminal Compliance, and the Fuel Supply Risks Nobody is Talking About:** "...California has set a compliance deadline for a technology that does not yet exist in a form that can safely operate on petroleum tankers. When the compliance deadline arrives, CARB will face a choice it has not publicly acknowledged: enforce the regulation and risk constraining the fuel supply, or back down and undermine the regulation’s credibility. Neither outcome serves the port communities the rule was designed to protect." [**STILLWATER ASSOCIATES**](https://stillwaterassociates.com/cleaning-up-californias-ports-the-at-berth-regulation-tanker-terminal-compliance-and-the-fuel-supply-risks-nobody-is-talking-about/?ref=calregulatory.com) - **CPUC Proposed Decision Risks Derailing Gas Transition:** "California passed a promising Neighborhood Decarbonization Program. The CPUC’s plan for implementing SB 1221 sets it up to fail." [**LEGAL PLANET** ](https://legal-planet.org/2026/06/24/cpuc-proposed-decision-risks-derailing-gas-transition/?ref=calregulatory.com) - **Gridmatic Study Reveals Huge Gap in California Grid-Scale Battery Performance:** "Unlike ERCOT, CAISO anonymizes public market data, masking resource identities and obscuring asset-level activity. A report by Gridmatic reveals that static bidding strategies and operational execution create a wide gap in performance across the state’s utility-scale battery energy storage assets."[**PV MAGAZINE**](https://pv-magazine-usa.com/2026/06/30/gridmatic-study-reveals-huge-gap-in-california-grid-scale-battery-performance/?ref=calregulatory.com) - **More Than 120 Candidates Seek Spot on ROWE Board:** "Under California Assembly Bill 825, which implements the work of Pathways, CAISO plans to transfer governance of its Western Energy Imbalance Market and Extended Day-Ahead Market to ROWE in 2028\. ROWE plans to expand its board to seven members after the organization has governance authority." [**RTO INSIDER**](https://www.rtoinsider.com/135284-120-candidates-seek-spot-rowe-board/?ref=calregulatory.com) - **New BPA Chief Promises "More to Say" On Day-Ahead Market Decision:** "\[**Travis**\] **Kavulla**’s past expressions that support a West-wide organized electricity market and his previous role on the WEM Governing Body have fueled speculation among industry participants that he may revisit BPA’s May 2025 decision to join Markets+ rather than [CAISO’s](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) Extended Day-Ahead Market. While Kavulla acknowledged the debate over Western markets during his speech at the ceremony, he unsurprisingly offered little concrete about his current thinking on the market direction, instead emphasizing the physical challenges facing the Northwest grid." [**RTO INSIDER**](https://www.rtoinsider.com/135286-new-bpa-chief-kavulla-promises-more-to-say/?ref=calregulatory.com) - **PG&E's Bidirectional Charging Programs Seek to Answer "Million Dollar Question" About Lowering Customer Costs:** "A recent[ ](https://www.pge.com/en/newsroom/currents/future-of-energy/new-pg-e-study-shows-electrification-will-lower-electricity-rate.html?ref=calregulatory.com)[study](https://www.pge.com/en/newsroom/currents/future-of-energy/new-pg-e-study-shows-electrification-will-lower-electricity-rate.html?ref=calregulatory.com) by utility Pacific Gas & Electric found that demand flexibility–shifting electric use to times when demand is low and energy is less expensive– could save about $1.8 billion in infrastructure costs by 2040." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/vehicle-to-grid/article/55387412/pges-bidirectional-charging-programs-seek-to-answer-million-dollar-question-about-lowering-customer-costs?ref=calregulatory.com) - **Powering Down Prices:** "While no single solution exists to California’s electricity affordability crisis, the need to deploy capital investment to build out the infrastructure necessary to meet a growing demand for power is not a new condition. For over a century, regulators have worked to balance the competing interests of safe, reliable utility service at just and reasonable rates. Foundational principles of cost-of-service ratemaking that govern electric utilities and their regulators offer solutions that can push for better cost controls while maintaining safe and reliable electric service." [**UC BERKELEY LAW**](https://www.law.berkeley.edu/wp-content/uploads/2026/06/Powering-Down-Prices%5FCLEE-Report%5FJune-2026.pdf?ref=calregulatory.com) - **UC Berkeley Report Targets IOU Earnings:** "Its main argument: high investor-owned utility rates are eroding the economic case for electrification at the precise moment California needs customers to switch. One in five IOU customers fell behind on bills in 2025 by an average of **$639**. California industrial rates run 2.5 to 3 times higher than neighboring states." [**CALIFORNIA REGULATORY INTELLIGENCE**](https://www.calregulatory.com/tuesday-briefing-uc-berkeley-report-targets-iou-earnings-plus-a-july-1-bts-rate-decrease/) [UC Berkeley Report Targets IOU EarningsHigh investor-owned utility rates are eroding the economic case for electrification at the precise moment California needs customers to switch.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-e0ff8fa8-3edd-4d79-b85d-add47715a422.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Jun-01-2026--6--4033c44b-afcf-4a18-ad1f-e96716d0da6f.png)](https://www.calregulatory.com/tuesday-briefing-uc-berkeley-report-targets-iou-earnings-plus-a-july-1-bts-rate-decrease/) - **The Case for Utility Wildfire Suppression:** "In California, PG&E and Southern California Edison together plan to spend more than $23 billion on wildfire prevention through 2025 — a 26 percent increase over their prior three-year cycle. In Oregon, PacifiCorp will invest $875 million over the next three years, while Hawaiian Electric plans to spend $450 million over a similar period." [**LATITUDE MEDIA**](https://www.latitudemedia.com/news/the-case-for-utility-wildfire-suppression/?ref=calregulatory.com) ### TUESDAY BRIEFING: UC Berkeley Report Targets IOU Earnings, Plus a July 1 BTS Rate Decrease URL: https://www.calregulatory.com/tuesday-briefing-uc-berkeley-report-targets-iou-earnings-plus-a-july-1-bts-rate-decrease/ Last updated: 2026-06-30T12:30:14.000Z Today's briefing looks at a UC-Berkeley policy report, informed by many familiar names in the California energy sector e.g., **Severin Borenstein**, **Matthew Freedman**, **Martha Guzman Aceves**, **Cliff Rechtschaffen**, **Matt Vespa**, and **Michael Wara**. The report identifies barriers to California realizing its energy vision, with recommendations on how to proceed amidst the current affordability crisis. Additionally, today's briefing examines a **July 1** rate *decrease* for SoCalGas BTS customers plus the utilities' semiannual Independent Evaluator reports on third-party energy efficiency solicitations. Separately, CRI would like to say thank you to all readers for your support, and particularly the recent wave of new paid subscribers. Your patronage is greatly appreciated and keeps the machine running. Please [reach out](https://www.calregulatory.com/contact-us/) at any time with questions, concerns or recommendations. \-- MC --- ## AFFORDABILITY A [new policy report](https://www.law.berkeley.edu/wp-content/uploads/2026/06/Powering-Down-Prices%5FCLEE-Report%5FJune-2026.pdf?ref=calregulatory.com) from UC-Berkeley's [Center for Law, Energy & the Environment](https://www.law.berkeley.edu/research/clee/?ref=calregulatory.com) (CLEE) frames California's electricity affordability crisis as a governance failure more than a clean-energy cost problem. Its main argument: high investor-owned utility rates are eroding the economic case for electrification at the precise moment California needs customers to switch. One in five IOU customers fell behind on bills in 2025 by an average of **$639**. California industrial rates run 2.5 to 3 times higher than neighboring states. The report identifies three barriers to California realizing its energy future. ### Barrier 1: The IOU Business Model Under cost-of-service ratemaking, the report notes, utilities earn a profit by building capital, not by controlling costs. The General Rate Case process sets a four-year budget; spending under that budget generates a profit. Regulatory lag, contra its oft-negative connotation, is the mechanism that makes cost-of-service ratemaking work. And California has spent years undermining it. The report says: > Longstanding economic theory of regulated monopolies identifies regulatory lag as a **positive** feature that applies performance pressures that are otherwise lacking outside of a competitive market. The report adds that miscellaneous tracking accounts recovered outside of authorized GRC rates grew from $86.6 million annually in 2018 to nearly **$2.4 billion** in 2024\. Non-GRC cost-adjustment accounts now contribute more than one-third of total electric utility revenue requirements. As a whole, the report finds, these accounts have transferred cost risk from utility shareholders to ratepayers while removing managerial pressure to find efficiencies between rate cases. The report recommends the legislature impose a minimum standard for authorizing any new balancing or memorandum account. The relevant costs must be: - Largely outside of utility control; - Unpredictable and volatile, and - Substantial and recurring. Costs that cannot clear that bar would stay in the GRC. The report also recommends sunset dates on all existing and new accounts, tying them to the utility's next GRC absent a specific finding otherwise On the issue of financing, the report notes that when a utility finances an infrastructure project, ratepayers carry it at about **7.5%**, which is the weighted average cost of utility debt and equity. Public bond financing for the same project runs around **4.5%**. The difference compounds over the life of an asset that may depreciate over decades. More importantly, a project financed outside the utility revenue requirement never enters rate base at all, which means it never enters rates. [Senate Bill 254](https://www.nossaman.com/newsroom-insights-californias-ambitious-new-bill-overhauls-the-states-approach-to-wildfires?ref=calregulatory.com) moved certain transmission projects in that direction; Senate Bill 905 (as amended) calls for a CPUC rulemaking to broaden that approach. On ROE, the CPUC cut authorized return by **30 basis points** in its most recent Cost of Capital proceeding, reducing them to about 10% for each IOU, which is still the highest of any U.S. region from 2021–2025\. The report holds that ROE reductions have limited near-term rate impact because recovery spreads over the life of an asset, **but** the long-run cost reduction is real. [Assembly Bill 2463](https://calmatters.digitaldemocracy.org/bills/ca%5F202520260ab2463?ref=calregulatory.com) would require the CPUC to support future cost of capital decisions with specific data and analysis. ### Barrier 2: Limited Regulatory Capacity The report says the CPUC has statutory authority to inspect utility accounts and examine utility officers under oath at any time but it does not have the capacity to do so. Utilities file between 600 and 1,300 advice letters per year, and the CPUC and intervenors closely review a fraction of them. The recommendations are therefore: - More staff; - Higher pay for specialized expertise; - A dedicated office of economists; and - Authority to conduct proactive investigations outside GRC timing constraints, modeled on the CPUC's post-San Bruno independent investigation and FERC's enforcement unit. The report also floats the idea of longer-term reforms while cautioning that institutional reform carries unintended consequence risk and requires further study. ### Barrier 3: Wildfires According to the report, wildfires are the single largest driver of IOU rate increases over the past five years. From 2019 to 2024, California authorized IOUs to recover more than **$40 billion** in wildfire-related costs: about **$13.6 billion** in post-catastrophe liability and $**26.6 billion** in pre-catastrophe mitigation. Wildfire costs now represent 14 to 19% of an average residential IOU bill, which is approximately $250–$500 per household annually. California's ranking for average monthly residential bills moved from 38th in 2018 to 8th in 2024. The 2017-2018 fire seasons were an inflection point. The Camp Fire pushed PG&E into bankruptcy while SCE and SDG&E faced severe credit downgrades. [Assembly Bill 1054](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201920200AB1054&ref=calregulatory.com) created the **$21 billion** Wildfire Fund (half from IOU shareholders, half from ratepayer-backed bonds through 2035). But the 2025 Los Angeles fires threatened to deplete it. Senate Bill 254 authorized an **$18 billion** Continuation Fund on the same cost-split structure, extended bond recovery to 2045, required IOUs to securitize an additional **$6 billion** in wildfire CapEx, revised Wildfire Mitigation Plan requirements to incorporate cost-per-ignition-avoided analysis, and required WMP filings at least one year before the next GRC. The report's main wildfire recommendation is a split ROE applying a lower but nonzero return specifically to capital expenditures included in utility wildfire mitigation and undergrounding plans. The Wildfire Fund and Continuation Fund already established precedent by removing equity return entirely on **$11 billion** in securitized wildfire CapEx. A split ROE extends that logic as a permanent structural adjustment rather than a one-off negotiation. The report also recommends increasing state and local investment in community hardening. Defensible space and forest treatment work differently than utility WMPs; they reduce how bad a fire gets once it starts, not just whether utility equipment started it. The [2021 Caldor Fire](https://en.wikipedia.org/wiki/Caldor%5FFire?ref=calregulatory.com), where pre-treated structures in Christmas Valley survived while surrounding ones did not, is the report's primary evidence. ### THE POLITICAL CONSTRAINT Every recommendation in the report disturbs an existing bargain. - Tracking account limits challenge a practice utilities, legislators, and the CPUC have used for twenty years. - ROE reductions face constitutional zone-of-reasonableness constraints and credit market risk. - CPUC reform would be so complicated that the report declines to recommend it without further study. - A split ROE for wildfire CapEx goes directly at the earnings value of the largest capital programs in IOU portfolios. The report accepts all of this. Its main claim is that California cannot electrify its economy on IOU rates that keep outrunning inflation, and that bending the cost curve requires changing the incentive architecture that produced those rates, not redistributing the existing cost burden across customer classes. **INSTANT ANALYSIS:** Most California affordability debates argue over who pays which share of a given bill. CLEE instead asks why the total number is so large. - The tracking account data is the report's hardest evidence. Growth from $86.6 million to $2.4 billion annually in non-GRC cost recovery over six years is not a rounding error in a $42 billion revenue requirement; it is a major shift in how California utility regulation operates. The GRC was conceived as a forum for cost discipline, and one-third of total revenue requirements now bypasses it. - The split ROE recommendation will draw the most resistance. California IOUs are in the middle of a long-term shift in wildfire spending from operational expenditures toward capital assets. This shift is rational from an engineering standpoint but it means wildfire costs are migrating from passthrough OpEx, which carries no shareholder return, into rate base CapEx, earning about 10%. A split ROE intercepts that migration. Utilities will argue it impairs capital access. But the report's readymade counter-argument is that wildfire CapEx already carries an implicit return in reduced liability exposure that ordinary infrastructure investment does not. - The report's regulatory capacity section is the least developed. Disallowances are how cost-of-service ratemaking actually controls costs, and a regulator that cannot identify imprudent spending cannot disallow it. Investing in CPUC capacity is less visible than a rate cut and harder to sell, but the report sees it as one of the few interventions that improves the system's ability to self-correct rather than requiring continuous legislative intervention. --- ## NATURAL GAS RATES SoCalGas filed a Tier 1 advice letter ([AL 6655-G](https://www.socalgasenvoy.com/ebb/attachments/1782741927451%5FAL%5F6655-G.pdf?ref=calregulatory.com)) to remove a temporary rate component tied to SDG&E's Transmission Integrity Management Program Balancing Account undercollection. For context, a 2025 resolution ([Resolution G-3611](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M565/K236/565236244.PDF?ref=calregulatory.com)) authorized SDG&E to recover $21.6 million plus interest over 12 months beginning July 1, 2025\. Because SoCalGas and SDG&E operate an integrated transmission system with shared rate-recovery mechanisms, SoCalGas carried its allocated share of that recovery in its own rates. The 12-month period is now complete. SoCalGas proposes to remove its allocation effective **July 1**. The filing reduces SoCalGas's annual revenue requirement by **$26.2 million**. About 88% of that total ($23.1 million) flows through Backbone Transportation Service, which produces a **3.1%** per-unit rate reduction for BTS customers. Protests are due **July 16**. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/06/rates.png) SoCalGas's Illustrative Rates **INSTANT ANALYSIS:** The filing provides large backbone shippers with a meaningful July 1 rate reduction. The filing also illustrates that SDG&E-related transmission cost recovery moves through SoCalGas rates because the Southern California gas transmission system doesn't track neatly with utility service-territory lines. --- ## ENERGY EFFICIENCY California's four large IOUs filed their semiannual Independent Evaluator reports on third-party energy efficiency solicitations, a recurring compliance check the CPUC created in 2018 to oversee the outsourcing of program design and delivery to non-utility implementers. These aren't performance evaluations; they're process reports, assessing whether solicitations ran fairly and flagging where procurement is breaking down. This round covers October 2025 through March 2026 and arrives as the IOUs push the CPUC to loosen the third-party framework in their 2028–2035 business plans. ### SDG&E SDG&E has [nothing to report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K653/609653614.PDF?ref=calregulatory.com). Its last solicitations closed in spring 2025, and this filing is now its third consecutive period announcing no activity. ### PG&E PG&E [still has two statewide solicitations moving](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K619/609619414.PDF?ref=calregulatory.com): - A **$6.7 million** "Career and Workforce Readiness" program, targeting Disadvantaged Workers under CPUC-defined eligibility criteria (income thresholds, incarceration history, foster-care emancipation) for placement in EE and electrification jobs. This program is currently in contract negotiations. - A **$30 million**, four-year all-electric nonresidential HVAC solicitation, originally scoped as "Market Support" before PG&E reclassified it mid-design as "Resource Acquisition." This program is moving through bidder evaluation. ### SCE SCE's "Statewide Midstream Plug Load Appliance" solicitation [required a 1.0 Total Resource Cost ratio just to advance an offer to evaluation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K522/609522043.PDF?ref=calregulatory.com). The independent evaluator recommended lowering that to 0.85, arguing cost-effectiveness should be judged at the portfolio level, not the offer level. SCE refused, holding that it won't contract for programs that can't forecast a 1.0 TRC ratio. Bidder feedback backed the independent evaluator. Fewer than 10% of measure permutations were cost-effective at the program's **$40 million** scale before administrative costs, and five measure packages had none. The evaluator also stated that proposing initial program design is a third-party implementers' job, not the IOU's. SCE's evaluation team concluded the program's viability risks were unresolved, declined to move to negotiations, and the $40 million solicitation then shut down. ### SoCalGas SoCalGas [filed the most active report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K611/609611510.PDF?ref=calregulatory.com). It shows the opposite failure mode: not a fairness problem, but solicitations getting stuck in execution. Its "Residential Window Retrofit" pilot (IDEEA Round 3) sat in CPUC measure-package review for over a year. That process is supposed to run 20 days preliminary and 35 days complete-package, but the clocks only start once a complete package is on file, and repeated incompleteness findings kept resetting them. Mid-review, the CPUC also tripled its cost assumption for the underlying window measure, forcing both sides to revisit whether the pilot was still worth pursuing before agreeing to continue. Approval finally came on March 31, 2026\. SoCalGas's Large Commercial solicitation became a re-solicitation entirely because the incumbent contractor walked away in late January, then fell further behind amid procurement review group pushback over bidder-selection rationale and how much meter-based savings the program should capture. SoCalGas told its own independent evaluator the contract had to close by year-end specifically to hit the 60% third-party threshold, the same requirement it's now asking the CPUC to convert into a soft target. **INSTANT ANALYSIS:** These filings detail an IOU retreat from mandatory third-party outsourcing, and the strongest evidence isn't in the business-plan proposals themselves; it's in what already broke during this reporting period. SCE shows what happens when an IOU holds its cost-effectiveness line against the independent evaluator and bidder pushback: the program doesn't get redesigned, it dies before contracting. SoCalGas shows the inverse problem, where even a utility actively trying to move forward gets stalled by CPUC review mechanics, procurement review group scrutiny, and contractor turnover, turning solicitation logistics into the bottleneck rather than the solicitation design itself. SCE's bidder data suggests the plug-load program may have been unbuildable at its $40 million scope regardless of who controlled the design. SCE's insistence on control didn't just override third-party flexibility, it surfaced a scoping problem faster. ### NEWS CODEX: Senate Bill 925; Climate Disputes; Offshore Wind Lawsuit URL: https://www.calregulatory.com/news-codex-senate-bill-925-climate-disputes-offshore-wind-lawsuit/ Last updated: 2026-06-26T19:00:47.000Z - **AEU Report Sees Progress on Generator Queues, but More Work Needed:** "Most of the ISO/RTOs have made progress on improving their interconnection queues as they have implemented [FERC](https://www.rtoinsider.com/category/rto/rto-public-policy/rto-ferc-federal/?ref=calregulatory.com) Order 2023, Advanced Energy United said in an update to its scorecard issued just after the order was approved. The [*report*](https://advancedenergyunited.org/reports/interconnection-progress-report/?%5Fcldee=RSMnizUKyc-oop%5F7uFDUGl1XGK1wM32vQYY%5FPIzEo%5FNo6Jekj1qQRiXBet7MfvSB&recipientid=lead-6fdb562a5f5ef011bec17c1e52190206-96580ecc7bb548658f7253586ee9bf87&esid=1ed3c9d2-7d6a-f111-a826-0022481d5e91&ref=calregulatory.com), written by Grid Strategies and the Brattle Group, found that [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com) and [SPP](https://www.rtoinsider.com/category/rto/rto-spp/?ref=calregulatory.com) have made 'promising improvements' in the past couple of years. But it did not name any grid operator as the best because of the complexity of the issues, AEU Managing Director **Caitlin Marquis** said." [**RTO INSIDER**](https://www.rtoinsider.com/134988-aeu-report-progress-generator-queues/?ref=calregulatory.com) - **Alternative Western RA Effort Grapples with Tx, Governance Rules:** "The work group leading the EDAM-aligned RA effort must reconcile differing opinions before it can present a draft proposal to the ROWE board." [**RTO INSIDER**](https://www.rtoinsider.com/135282-alternative-western-ra-effort-transmission-governance-rules/?ref=calregulatory.com) - **A Month into EDAM, the Data Already Shows Two Very Different Grids:** "In May, day-ahead energy prices in PacifiCorp East averaged just $8.62/MWh, less than half PacifiCorp West’s $18.97/MWh. PacifiCorp East cleared negative in 17% of all hours, while PacifiCorp West went negative only 2% of the time. Those differences reflect fundamentally different resource mixes, operating conditions and exposure to California’s solar-driven price dynamics."[**UTILITY DIVE**](https://www.utilitydive.com/news/caiso-edam-day-ahead-pacificorp-analysis/823240/?ref=calregulatory.com) - **CalCCA Urges CPUC to Fix Flawed Resource Adequacy Proposal Before it Raises Costs and Risks Reliability for Millions of Californians:** "The PD leaves nearly $180 million in savings on the table. Right now, load-serving entities must plan for reliability needs hour-by-hour, but they can only trade monthly — a mismatch that leads to unnecessary, costly over-buying. CalCCA proposed a straightforward fix: allow hourly obligation trading to match hourly requirements." [**CALCCA**](https://cal-cca.org/cpuc-ra-proposal/?ref=calregulatory.com) - **California's $11 Billion Wind Project Set a Record – Four Days Later, Output Collapsed:** "...hourly CAISO data shows that SunZia increased California’s wind-generation potential and helped produce new highs. It also shows that low-wind periods continue to occur, sometimes only days after record-setting output. The lesson from the data is straightforward: adding more wind raises the peaks, but it does not eliminate the valleys. Any grid built around large amounts of wind generation must still maintain sufficient dispatchable backup, storage, imports, or other resources to carry the system when wind production falls." [**A PRAGMATIC APPROACH TO ENERGY**](https://kclapp.substack.com/p/californias-11-billion-wind-project) - **California's Electric Price Tag Hinders Data Center Development:** "With industrial electricity prices sitting over double the national average, state regulations surrounding the size of backup generators and lengthy waiting periods to connect to the grid, California is considerably shielded from data centers’ impacts." [**LA MAG**](https://lamag.com/technology/californias-electric-price-tag-hinders-data-center-development/?ref=calregulatory.com) - **California Can Turn Fusion Momentum into Commercialization – SB 925 is the Next Step:** "Authored by Senator **Jerry McNerney** (SD 5), SB 925 directs the California Energy Commission to develop a strategic plan for fusion energy research, development, and commercialization in the state. Notably, the bill includes key recommendations from Clean Air Task Force’s [*State Policy Options for Fusion Energy Deployment*,](https://www.catf.us/resource/state-policy-options-for-fusion-energy-deployment/?ref=calregulatory.com) which details steps that states can take to create conducive environments for fusion energy deployment. SB 925 passed unanimously, 37–0, with Democratic and Republican support."[**CLEAN AIR TASK FORCE**](https://www.catf.us/2026/06/california-can-turn-fusion-momentum-commercialization/?ref=calregulatory.com) - **California Democrats Threaten to Block Newsom Priorities Over Imperiled Climate Deal:** "At stake are billions of dollars earmarked for public transit, safe drinking water and affordable housing raised from climate market auctions. The Senate is also threatening to hold up many of Newsom’s own priorities, including funding for high-speed rail and wildfires, electric-car tax credits and a clean jet fuel subsidy."[ **CAL MATTERS**](https://calmatters.org/politics/2026/06/newsom-climate-rules-budget-fight-senate-democrats/?ref=calregulatory.com) - **A Climate Policy Betrayal in California:** "As policymakers grapple with the fallout from the war in Iran, California’s climate regulator approved carbon market regulations that undermine the state’s climate goals. Promoted as an affordability measure, the new rules won’t reduce gasoline prices—but they will transfer billions of dollars in public investments to private interests." [**KLEINMAN CENTER FOR ENERGY POLICY**](https://kleinmanenergy.upenn.edu/commentary/blog/a-climate-policy-betrayal-in-california/?ref=calregulatory.com) - **California Gas Generation Down 60% From 2024 as Solar, Imports Surge:** "Utility-scale solar generation overtook natural gas generation in the California Independent System Operator’s footprint over the first five months of 2026, according to a Tuesday report from the Energy Information Administration. From January through May, solar generation in CAISO increased 21% compared with the same period in 2024, while natural gas generation decreased 60%, EIA found." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-gas-generation-down-60-percent-from-2024-as-solar-and-imports-surge/823104/?ref=calregulatory.com) - **California Solar Surged Ahead of Gas in the First 5 Months of 2026:** "Solar didn’t beat gas on its own, though. Battery developers have built 16 gigawatts of capacity in CAISO to charge up on solar power and then compete with gas after sundown. This buildup has rapidly altered grid dynamics in the evenings, when batteries regularly become the top source of power for multiple hours. Meanwhile, wind imports recently jumped as the gigantic [SunZia project came online](https://www.canarymedia.com/newsletters/sunzia-wind-reaches-commercial-operations?ref=calregulatory.com), and that takes the fight to gas in the middle of the night, further depressing its output."[ **CANARY MEDIA**](https://www.canarymedia.com/articles/solar/california-solar-ahead-of-gas?ref=calregulatory.com) - **California Needs Water and Clean Power – It Might Have a Fix for Both:** "In California, a sprawling 4,000-mile network of canals winds through citrus orchards and fields of tree nuts, delivering irrigation and drinking water to homes and farms across the state. The canals are critical in an increasingly arid part of the country. But what if they could help fulfill another urgent need: renewable energy? To test that idea, researchers, private enterprise and a public utility in the Central Valley are installing solar panels atop the man-made waterways." [**NEW YORK TIMES**](https://www.nytimes.com/2026/06/22/climate/california-canals-solar-panels-water-nexus.html?ref=calregulatory.com) - **California to Sue Trump Administration Over Offshore Wind Buybacks:** "The state of California plans to sue the U.S. Department of the Interior and several other parties over the **Trump** administration’s agreements with offshore wind developers to 'buy back' their leases for several projects, [including Golden State Wind off the coast of California,](https://oag.ca.gov/system/files/attachments/press-docs/OCLSA%20Notice%20Letter%206.23.26.pdf?ref=calregulatory.com) Attorney General **Rob Bonta** said..." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-file-suit-over-trump-administrations-offshore-wind-buybacks/823790/?ref=calregulatory.com) - **California Prepares to Sue Over OSW Lease Cancellation:** "CAISO’s current 2025/26 transmission planning process base case includes 4.5 GW of future offshore wind capacity, but a federal agreement cancelled an offshore wind project that could have generated up to 2 GW." [**RTO INSIDER**](https://www.rtoinsider.com/135086-california-officials-issue-notice-of-intent-to-sue-offshore-wind-deal/?ref=calregulatory.com) - **California Preps for Battle Royale Over Offshore Wind Leases That Trump Wants to Kill:** "On June 23, California Attorney General Rob Bonta and the chair of the California Energy Commission, **David Hochschild**, issued a formal Notice of Intent to Sue, alleging [an illegal agreement](https://www.energy.ca.gov/news/2026-06/california-sends-notice-intent-file-suit-challenging-trump-administrations?ref=calregulatory.com) between the US Department of the Interior and Golden State Wind, a 50-50 joint venture between the Spanish firm Offshore Wind and the UK firm Reventus Power." [**CLEAN TECHNICA**](https://cleantechnica.com/2026/06/24/floating-offshore-wind-farms-california-lawsuit-trump/?ref=calregulatory.com) - **CEC Grants $21M to Improve Large Load Flexibility:** "Improved conductors, sensors and control systems will by 2030 more effectively connect to California’s grid about 1.1 million new public EV chargers and 4.5 million heat pump water heaters, **Sebastian Rubio Ruiz**, CEC energy specialist, said during a June 22 agency voting meeting. The state’s data center peak demand is projected to increase by up to 8,300 MW by 2040, pushing [*CAISO*](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com)’s peak load up by about 11%." [**RTO INSIDER**](https://www.rtoinsider.com/135078-cec-grants-21m-improve-large-load-flexibility/?ref=calregulatory.com) - **Oppenheimer's Grandson Supports Nuclear Energy Bill:** "The grandson of the man who oversaw the invention of the atomic bomb spoke out Wednesday morning in support of nuclear energy development in California. **Charles Oppenheimer**'s testimony before the state Senate Energy and Utilities Committee was part a push by state Democratic lawmakers to expand clean energy production.[**Assembly Bill 2647**](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202520260AB2647&ref=calregulatory.com), authored by Assemblymember Lisa Calderon, D-City of Industry, would require the California Energy Commission to study nuclear energy development in an effort to reach 100% zero-carbon and renewable energy goals by 2045, according to a [**legislative analysis**](https://leginfo.legislature.ca.gov/faces/billAnalysisClient.xhtml?bill%5Fid=202520260AB2647&ref=calregulatory.com)." [**CENTER SQUARE**](https://www.thecentersquare.com/california/article%5F52598b25-5a33-4c53-861f-fffa972cdab4.html?ref=calregulatory.com) - **Solar, Batteries Take the Reins in California's Energy Race:** "More than $3.7 billion worth of solar-generation projects could begin construction in California before the end of 2026." [**INDUSTRIAL INFO**](https://www.industrialinfo.com/iirenergy/industry-news/article/solar-batteries-take-the-reins-in-californias-energy-race--359170?ref=calregulatory.com) - **Stakeholders Urge New BPA Leader to Remain Focused on Tx, Markets:** "'The priorities and decisions Administrator Kavulla makes will be consequential for the region' — Northwest Energy Coalition Executive Director **Tamara Kennedy**." [**RTO INSIDER**](https://www.rtoinsider.com/135068-stakeholders-urge-new-bpa-leader-remain-focused/?ref=calregulatory.com) - **Terra-Gen Wins Consent for GW-Scale Solar-BESS Park in California:** "Undertaken by project vehicle Discovery Solar PV and Storage LLC, part of Terra-Gen, the scheme will generate around USD 44 million in property tax revenue in its first full year of operations. The solar-storage park will be located near Mojave, at the western edge of the Antelope Valley, and will use photovoltaic panels made by First Solar Inc. The entire complex will span across 7,700 acres (3,116 hectares) of 473 privately-owned parcels." [**RENEWABLES NOW**](https://renewablesnow.com/news/terra-gen-wins-consent-for-gw-scale-solar-bess-park-in-california-1297127/?ref=calregulatory.com) - **The Best Way to Eliminate Methane Leaks is to Drill:** "There are two things we now know with almost absolute certainty: (1) Californians will consume *at least* another [5 billion barrels of oil](https://californiapolicycenter.org/five-billion-barrels-of-crude-oil/?ref=calregulatory.com), even if consumption reaches zero by 2045, and (2) depleting our oil reserves, especially in Los Angeles, Ventura, and Santa Barbara counties, is the most effective way to control oil-related emissions of methane and volatile organic compounds. Drilling for oil in California is no longer just a compelling economic choice. It is also guaranteed to help the environment." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-the-best-way-to-eliminate-methane-leaks-is-to-drill/?ref=calregulatory.com) - **The Coming Western Energy Supply Crunch:** "Grid managers are some of the soberest people you’ll meet, and they’re starting to get spooked about energy shortages in the West. Forecasts of a looming supply crunch in California, the Pacific Northwest and the Desert Southwest are drawing attention at industry events, in formal regulatory proceedings and among gurus who study this stuff. A presentation prepared by a grid modeler for a gathering in San Diego last month put it in terms that, for a grid modeler, are stark. 'Even with all planned resource additions, loss of load is encountered,' according to [the analysis](https://www.westernenergyboard.org/wp-content/uploads/01%5FVIC%5F2026-WARA-CREPC-WIRAB-Meeting-5-12-2026.pdf?ref=cleanpowercalifornia.org) from Vic Howell of the Western Electricity Coordinating Council." [**THE CURRENT** ](https://www.cleanpowercalifornia.org/the-coming-western-energy-supply-crunch/?ref=calregulatory.com) - **Two Microgrids with Solar Power Being Developed for Tribal Community in California:** "The Paskenta Band of Nomlaki Indians and [OATI](https://www.oati.com/?ref=calregulatory.com) are partnering to develop [two microgrids](https://www.oati.com/news/?ref=calregulatory.com) for the tribal community in Northern California. The goal of the project is to bring renewable energy onto tribal lands so they can have greater energy independence and control over their electricity supply." [**CLEAN TECHNICA**](https://cleantechnica.com/2026/06/23/two-microgrids-with-solar-power-being-developed-for-tribal-community-in-california/?ref=calregulatory.com) ### THURSDAY BRIEFING: CPUC Asks Whether PCIA Reform Should Get Bigger URL: https://www.calregulatory.com/thursday-briefing-cpuc-asks-whether-pcia-reform-should-get-bigger/ Last updated: 2026-06-25T12:30:07.000Z - Today's briefing covers a new ruling in the ERRA/PCIA reform docket that opens the door for parties to argue that Track 3 in the proceeding should go beyond technical PCIA refinements. - SCE's 2025 Risk Spending Accountability Report shows a significant underspend against authorized safety, reliability, and maintenance work. The report raises familiar questions about forecast-based authorizations, execution constraints, and whether risk-reduction work is being delayed or shifted. - A new scoping memo addresses PG&E's latest cost-recovery application for Diablo Canyon extension costs. --- ### ERRA/PCIA REFORM The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K173/609173180.PDF?ref=calregulatory.com) in the ERRA/PCIA Reform docket that opens post-workshop comments in Track 3\. Parties may now address issues raised at the June Track 3 Planning Workshops, issues from earlier Track 3 comments, and a specific set of ALJ questions in the ruling. For the Day 1 (June 8 workshop) questions, the ALJ asks whether four topics clear a net-benefits threshold sufficient to warrant inclusion in Track 3 scope: - Targeted recovery for uneconomic legacy resources; - Revisiting allocation, including potential mandatory allocations; - Mechanisms to reduce volatility and stabilize rates; and - Other frameworks for achieving indifference that produce greater ratepayer net benefits and promote competition among load-serving entities. Parties must also state whether any topic should be treated as mutually exclusive with the others. Day 2 (the June 9 workshop) involves ERRA and PCIA refinements. Parties should identify their two or three highest-priority issues and describe the record-development complexity each requires, including the analysis needed. Day 3 (the June 15 workshop) covers data access. The ALJ proposes a template for a joint data-access issues list (type of data desired, why it is necessary and relevant to scope, the providing party's concerns, and joint options for addressing those concerns), drawing data desired from both Community Choice Aggregators and utilities. Two further questions ask parties to identify a shared underlying motivation behind any opposed data-access proposal, and how much time is needed between the Track 3 scoping memo and the deadline for load-serving entities to meet and confer and file a joint case management statement. Comments are due **July 9**, with reply comments due **July 16**. **INSTANT ANALYSIS:** Track 3 may become more than a technical PCIA clean-up. The ALJ is expressly asking whether parties want a fundamental reform in scope. The ruling now lets parties contest whether the indifference framework itself should be supplemented or partially redesigned, rather than confining their arguments to PCIA mechanics. The mandatory-allocation reference raises the possibility of a move away from after-the-fact cost recovery toward direct assignment or sharing of legacy resource obligations. The mutual-exclusivity question lets parties argue that one reform forecloses another. If Track 3 moves toward meaningful reforms, the scope and symmetry of access between utilities and CCAs will shape the evidentiary record. Parties seeking major PCIA changes must show the current framework produces problems and that their alternative delivers net benefits, reduces volatility, and preserves real competition among LSEs. --- ### UTILITY RISK SPENDING SCE filed its [2025 Risk Spending Accountability Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K237/609237726.PDF?ref=calregulatory.com) (RSAR), which shows a **$932 million** capital shortfall against authorized levels for safety, reliability, and maintenance work. Recorded Safety, Reliability, and Maintenance-eligible capital came in at about **$5.01 billion**, 16% below authorization. O&M ran much closer to the original plan: about **$1.78 billion** recorded, $51 million (3%) under. - Distribution drove the capital shortfall at $523 million below authorized (−14%). SCE points to early-2025 storm restoration that diverted crews, the late-September issuance of its 2025 GRC decision, and the time needed to ramp contractor resources and work scope. Transmission capital came in at **$327 million** under (−35%), part of it FERC-jurisdictional, the rest deferred by permitting, licensing, outage, contractor, redesign, environmental, and access constraints. - On O&M, the underspending concentrated in Distribution (**−$71 million**, −8%) and "Other" (**−$77 million**, −12%): lower work volumes, fewer dead and diseased tree removals, reduced inspection find rates, accounting shifts, and timing. Transmission O&M went the other way: **$101 million** over authorized (+69%), driven by storm response and field remediation above forecast. - By risk area: wildfire O&M ran **$48 million** under, wildfire capital came in at **$256 million** under, and underground equipment failure capital came in **$130 million** under. RAMP-related totals were **$77 million** under on O&M (−16%) and **$430 million** under on capital (−22%). SCE frames the variances as timing and execution rather than scope reduction, and stresses that 2025 authorized amounts rested on forecasts built years earlier and not approved until late in the test year. **INSTANT ANALYSIS**: The filing tests how far safety-spending accountability can ride on GRC forecasts built years before the money is approved. SCE's answer is that 2025 was a transition year. Storms, permitting, outage limits, contractor ramp, changed field conditions, accounting treatment, and a GRC decision that did not surface until September moved authorized work across programs and years rather than erasing it. The numbers raise a question: when does coming in under authorization reflect prudent flexibility, and when does it mean authorized risk-reduction work is slipping? SCE leans on CPUC precedent affording utilities room to reprioritize, and several explanations hold up (emergency storm response genuinely consumed finite crews). But the scale invites scrutiny. A logical inference is that RSARs are turning into back-end accountability forums for wildfire, reliability, and safety capital. --- ### DIABLO CANYON COST RECOVERY Commissioner **Karen Douglas** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K032/609032588.PDF?ref=calregulatory.com) for PG&E's application to recover **$595 million** in 2027 Diablo Canyon operating costs from ratepayers. The proceeding will examine PG&E's: - Forecast operations and maintenance costs; - Nuclear fuel expenses to be amortized through 2030; - Resource Adequacy substitution capacity costs and true-up costs; and - The netting of CAISO revenues against the 2027 Record Period revenue requirement. The proceeding will also review: - The statewide non-bypassable charge and related rate proposals from PG&E, SCE, and SDG&E; - PG&E's 2027 Volumetric Performance Fee spending plan; - A proposed **$26 million** reclassification from the Diablo Canyon Transition and Relicensing Memorandum Account to the Extended Operations Balancing Account; and - Whether PG&E's testimony satisfies prior CPUC requirements from four Diablo Canyon extension decisions. The ruling deems cost-effectiveness review, historical cost review, and modifications to the fixed management fee escalation method as out of scope, citing the absence of statutory triggers and the accelerated ERRA-like schedule's unsuitability for a broader inquiry. **INSTANT ANALYSIS**: The ruling confines this case to rate recovery. PG&E's $595 million revenue requirement will be contested on forecast reasonableness, not on whether the plant should be running. Intervenor testimony is due **July 17**, with rebuttals due **August 14**. A proposed decision is expected on October 30, with a final decision on **December 3**. ### New Proposal Would Use IRP Portfolios to Trigger LSE Procurement URL: https://www.calregulatory.com/new-proposal-would-turn-irp-portfolios-into-binding-procurement-obligations/ Last updated: 2026-06-30T04:52:21.000Z A [June 23 ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M609/K223/609223925.PDF?ref=calregulatory.com) seeks party comments on a new option for the CPUC's Reliable and Clean Power Procurement Program ([RCPPP](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/the-reliable-and-clean-power-procurement-program?ref=calregulatory.com)), aimed at turning the Integrated Resource Planning process into a direct procurement obligation for load-serving entities. Rather than tying the program closely to Resource Adequacy or creating an RPS-style clean energy mandate, the proposal would use the CPUC's Preferred System Plan and/or the CAISO Transmission Planning Process base-case portfolio to identify the mix of new resources needed five years ahead for reliability and emissions compliance. Those needs would be expressed in Net Qualifying Capacity (NQC), by resource type or attribute category, and allocated to load-serving entities based on their share of the CEC's [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) load forecast. Each LSE would have to put 100% of its allocated new resources under long-term contract within three years and online within five, with the first full online compliance deadline proposed for **June 1, 2033**. The ruling allows flexibility within resource categories (compliance bands such as 70% to 130%) but would penalize LSEs that fall short of their total NQC obligation or rely too heavily on the lowest-cost resource types. Resource accreditation would use marginal [Effective Load Carrying Capability](https://blog.ucs.org/mark-specht/elcc-explained-the-critical-renewable-energy-concept-youve-never-heard-of/?ref=calregulatory.com) (ELCC) values rather than the RA program's [Slice-of-Day](https://www.ascendanalytics.com/blog/californias-slice-of-day-framework-understanding-impacts-on-resource-adequacy-and-resource-value?ref=calregulatory.com) framework. Resources must be incremental to the mid-term reliability baseline: online after Jan. 1, 2020 and not already counted toward a prior procurement requirement. The ruling frames the proposal as a bridge between IRP, transmission planning and procurement, addressing a current deficiency: the CPUC and CAISO plan around portfolios that assume resources will be built, but no standing mechanism requires LSEs to procure the specific mix reflected in those portfolios. The proposed cadence assumes the CAISO's biennial Transmission Planning Process cycle under [FERC Order 1920](https://www.ferc.gov/news-events/news/fact-sheet-building-future-through-electric-regional-transmission-planning-and?ref=calregulatory.com) is adopted; if it is not, the schedule changes. Comments are due **July 22**, with replies due **August 7**. ### INSTANT ANALYSIS The CPUC is again trying to solve the core IRP problem: portfolios get modeled, transmitted to the CAISO for transmission planning, and treated as the backbone of California's clean-reliability future...but no standing mechanism requires LSEs to procure the resource mix those portfolios assume. The new RCPPP option would make the Preferred System Plan and/or Transmission Planning Process base case the procurement anchor, translating the five-year resource need into LSE-specific NQC obligations allocated by load share. The proposal deliberately refuses to collapse IRP into RA or RPS. Both programs would continue separately, with RCPPP layered on top as a long-term procurement compliance regime. The ruling argues that, in a ground-up design, short-term RA requirements would flow from long-term procurement needs, not the other way around. The practical cost is two accreditation systems (marginal ELCC for RCPPP and slice-of-day for RA) which the ruling acknowledges may be inefficient but justifies on the view that long-term portfolio value should track the evolving system mix. If adopted, the framework would move California off episodic ad hoc procurement orders and onto a recurring compliance structure: 100% of allocated new resources would be under contract within three years, online within five, with penalties tied to net cost of new entry plus a separate penalty meant to deter overreliance on the cheapest resource types. The first full online compliance deadline would be **June 1, 2033**. The schedule assumes the CAISO's biennial Transmission Planning Process cycle under FERC Order 1920 is adopted, with RCPPP running every two years and procurement deadlines falling every other year. If that cycle changes, the compliance calendar will change with it. The proposal also moves away from the 2025 Staff Proposal's collective Central Procurement Entity reserve, instead proposing a 1% buffer and asking parties whether that smaller cushion is sufficient. ### July 2 CPUC Voting Meeting Preview: Paper Capacity Dies; PG&E Eats $2.6 Billion URL: https://www.calregulatory.com/july-2-cpuc-voting-meeting-preview-paper-capacity-dies-pg-e-eats-2-6-billion/ Last updated: 2026-06-24T12:30:46.000Z The CPUC's **July 2** [voting-meeting agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M609/K457/609457851.pdf?ref=calregulatory.com) features several consequential items spanning Resource Adequacy, natural gas decommissioning work, and utility capital structure. Notable movement on Demand Response and low-income subsidies is also on tap. Summaries of select agenda items can be found below the paywall. --- _This post is for paying subscribers only._ ### SoCalGas/SDG&E 2027 CAP: Embedded Cost Gains Ground as Intervenors Fracture URL: https://www.calregulatory.com/socalgas-sdg-e-2027-cap-embedded-cost-gains-ground-as-intervenors-fracture/ Last updated: 2026-06-22T16:06:27.000Z On June 15, parties served rebuttal testimony in SoCalGas/SDG&E's 2027 Cost Allocation Proceeding ("CAP," [A.25-09-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K104/582104341.PDF?ref=calregulatory.com)). SoCalGas/SDG&E (the Sempra Utilities) and the following intervenors served rebuttal testimony: - Clean Energy; - Indicated Shippers; - Southern California Generation Coalition (SCGC); - TURN; and - Western Manufactured Housing Communities Association (WMA). On the biggest question in the proceeding, whether to retire Long-Run Marginal Cost (LRMC) and make embedded cost the universal allocation method, the applicants' submission is strong. The ultimate question is "who will pay," which has intervenors fractured. Recall that the Sempra Utilities provided the following illustrative rates when they filed the CAP in September 2025. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/06/rates1.png) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/06/rates2.png) ***Links to all parties' testimony submissions are at the bottom of this post.*** --- ### SUMMARY OF REBUTTAL TESTIMONY - The Sempra Utilities' rebuttal returns to one argument across 10 chapters: each proposal rests on recorded-cost evidence, and intervenors must justify any departure from cost causation. - Sempra witnesses **Frank** **Seres/Marjorie Schmidt-Pines** [defend](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9422/608725833.pdf?ref=calregulatory.com) embedded cost as universal and move to discontinue LRMC. - Sempra witness **Michael Foster**'s residential fixed-charge chapter is the cleanest execution of the burden-shift; he [casts](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9422/608866933.pdf?ref=calregulatory.com) the below-cost charge as the thing requiring justification, and his strongest factual point is the CARE inversion: approximately **80–82%** of CARE customers subsidizing about half of non-CARE customers. He also states that incentivizing electrification through gas ratemaking and promoting gas affordability are "diametrically opposed principles." - On methodology, the major cost-allocation intervenors mostly agree with the Sempra utilities. The Indicated Shippers, Clean Energy, and TURN all back the migration to embedded cost, and SCGC [supports](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9423/608969643.pdf?ref=calregulatory.com) the framework as consistent with longstanding policy; only Cal Advocates holds out for LRMC. Clean Energy's witness **Allison Smith** makes a compelling case: LRMC was adopted in 1992 to send growth-era investment signals, and a shrinking customer base removes that rationale (which Cal Advocates' own witnesses concede). - The deepest divide is intervenor-versus-intervenor. Witness **Brian** **Collins** (Indicated Shippers) argues peak-day demand sizes the system; witness **Mike Florio** (TURN) [argues](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9411/608725824.pdf?ref=calregulatory.com) that with load declining and spending now safety-and-reliability-driven, annual throughput is the true cost driver. Florio's package shifts about **$67 million** onto retail noncore customers; Collins attacks it adjustment by adjustment, and Clean Energy joins him, noting an approximate **$17 million** (**30%**) hit to the NGV class tied to transit agencies facing about **$1.3 billion** in budget cuts. - On distribution allocation, Florio is isolated; the applicants, Indicated Shippers, and Clean Energy all oppose his throughput allocator. TURN is not uniformly opposed, though: Florio backs the applicants on median storage capacity, equal-cents-per-therm load balancing, and assigning 12 Bcf to load balancing, though TURN and SoCalGas/SDG&E describe the current baseline differently. - Two issues unite the cost-allocation intervenors against the utilities. The backbone-to-local-transmission reallocation (approximately **$116.4 million**) faces broad opposition, but the opponents don't agree on a remedy: SCGC's **8%**, Cal Advocates' peak-month-with-residential-carve-out, and Indicated Shippers' peak-day method all compete with the applicants' about **20%**. And the Firm Access and Storage Rights Memorandum Account (FASRMA) is the clearest intervenor target: Collins says SoCalGas would use an approximate **$27 million** Noncore Storage Balancing Account overcollection to eliminate an approximately **$4 million** the FASRMA undercollection tied mainly to stranded off-system delivery capital, against a program that generated only about **$30,000** in net interruptible off-system delivery revenue. - On Asset Retirement Obligations (AROs), TURN and the Indicated Shippers want AROs excluded; the applicants and SCGC want them in, with witness **Cathy** **Yap** leaning on FERC and prior CPUC treatment of AROs as plant cost. WMA's **Mary** **Neal** is narrower, arguing only that mobile-home-park operators, not tenants directly, bear the submeter-discount effect. ### INSTANT ANALYSIS SoCalGas/SDG&E seem well-positioned to win the methodology argument: embedded cost is headed for adoption with the major cost-allocation intervenors largely aligned and Cal Advocates isolated. What the applicants have **not** secured is the allocation outcomes that flow from a methodology win. Embedded cost is a framework, not an answer, and once the framework is agreed upon, the dispute moves to allocators, where the intervenors cannot agree among themselves. That plays to the utilities' advantage. A Commission facing one unified opposition number can adopt it; a Commission facing Collins's peak-day theory, Florio's annual-throughput theory, and three different backbone calculations has more reason to defer to the filed study. The exception is FASRMA, where opposition among the cost-allocation intervenors is unified and the factual record is lopsided enough that the applicants are likely to lose it outright. A key point is that every allocator dispute is ultimately about who absorbs the cost of a shrinking system. The Indicated Shippers and TURN disagree over whether industrial noncore or residential core carries it; Clean Energy is fighting to keep it off transit fleets. For a gas-only utility with no electric pivot, securing cost-based allocation now (before the customer base contracts further) is the name of the game. [A2509014 Rebuttal Testimony of Allison F. Smith on behalf of Clean EnergyA2509014 Rebuttal Testimony of Allison F. Smith on behalf of Clean Energy.pdf1 MBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A2509014-Rebuttal-Testimony-of-Allison-F.-Smith-on-behalf-of-Clean-Energy.pdf "Download") [A25-09-014 Rebuttal Testimony of Brian C. Collins On Behalf Of Indicated ShippersA25-09-014 Rebuttal Testimony of Brian C. Collins On Behalf Of Indicated Shippers.pdf847 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A25-09-014-Rebuttal-Testimony-of-Brian-C.-Collins-On-Behalf-Of-Indicated-Shippers.pdf "Download") [A.25-09-014 Rebuttal Testimony of SCGC608969643 (2).pdf483 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/608969643--2-.pdf "Download") [A.25-09-014 Rebuttal Testimony of SCGC608967722 (2).pdf2 MBdownload-circle](https://www.calregulatory.com/content/files/2026/06/608967722--2-.pdf "Download") [A.25-09-014 Ch 13 Rebuttal Testimony of Dandridge PDFAA.25-09-014 Ch 13 Rebuttal Testimony of Dandridge PDFA.pdf199 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-13-Rebuttal-Testimony-of-Dandridge-PDFA.pdf "Download") [A.25-09-014 Ch 14 Rebuttal Testimony of Martinez PDFAA.25-09-014 Ch 14 Rebuttal Testimony of Martinez PDFA.pdf163 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-14-Rebuttal-Testimony-of-Martinez-PDFA.pdf "Download") [A.25-09-014 Ch 15 Rebuttal Testimony of Martinez PDFAA.25-09-014 Ch 15 Rebuttal Testimony of Martinez PDFA.pdf238 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-15-Rebuttal-Testimony-of-Martinez-PDFA.pdf "Download") [A.25-09-014 Ch 16 Rebuttal Testimony of Dandridge PDFAA.25-09-014 Ch 16 Rebuttal Testimony of Dandridge PDFA.pdf132 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-16-Rebuttal-Testimony-of-Dandridge-PDFA.pdf "Download") [A.25-09-014 Ch 17 Rebuttal Testimony of Martinez PDFAA.25-09-014 Ch 17 Rebuttal Testimony of Martinez PDFA.pdf165 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-17-Rebuttal-Testimony-of-Martinez-PDFA.pdf "Download") [A.25-09-014 Ch 18 Rebuttal Testimony of Gadani PDFAA.25-09-014 Ch 18 Rebuttal Testimony of Gadani PDFA.pdf144 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-18-Rebuttal-Testimony-of-Gadani-PDFA.pdf "Download") [A.25-09-014 Ch 19 Rebuttal Testimony of Seres and Schmidt-Pines PDFAA.25-09-014 Ch 19 Rebuttal Testimony of Seres and Schmidt-Pines PDFA.pdf332 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-19-Rebuttal-Testimony-of-Seres-and-Schmidt-Pines-PDFA.pdf "Download") [A.25-09-014 Ch 20 Rebuttal Testimony of Borkovich PDFAA.25-09-014 Ch 20 Rebuttal Testimony of Borkovich PDFA.pdf384 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-20-Rebuttal-Testimony-of-Borkovich-PDFA.pdf "Download") [A.25-09-014 Ch 21 Rebuttal Testimony of Duran PDFAA.25-09-014 Ch 21 Rebuttal Testimony of Duran PDFA.pdf425 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-21-Rebuttal-Testimony-of-Duran-PDFA.pdf "Download") [A.25-09-014 Ch 22 Rebuttal Testimony of Foster PDFAA.25-09-014 Ch 22 Rebuttal Testimony of Foster PDFA.pdf425 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.25-09-014-Ch-22-Rebuttal-Testimony-of-Foster-PDFA.pdf "Download") [A. 25-09-014 - Rebuttal Testimony of Mary Neal on Behalf of WMA 5-15-2026A. 25-09-014 - Rebuttal Testimony of Mary Neal on Behalf of WMA 5-15-2026.pdf568 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A.-25-09-014---Rebuttal-Testimony-of-Mary-Neal-on-Behalf-of-WMA-5-15-2026.pdf "Download") [A2509014 Rebuttal Testimony MFlorio\_061526A2509014 Rebuttal Testimony MFlorio\_061526.pdf736 KBdownload-circle](https://www.calregulatory.com/content/files/2026/06/A2509014-Rebuttal-Testimony-MFlorio%5F061526.pdf "Download") ### NEWS CODEX: California Petroleum Reserve; Oakland Coal Terminal; Renewables Curtailments URL: https://www.calregulatory.com/news-codex-3/ Last updated: 2026-06-15T21:55:43.000Z - **1M+ Customers Have Connected Solar to PG&E's Grid:** "PG&E has recently focused on virtual power plant deployment. In July it executed the largest-ever coordinated demand response test, with its VPP delivering 535 MW for two hours. In February, PG&E and Sunrun completed a hyperlocal VPP deployment, using the [storage-plus-solar systems of Sunrun customers](https://investors.sunrun.com/news-events/press-releases/detail/362/sunrun-and-pge-dispatch-energy-from-northern-california?ref=calregulatory.com) to '\[export\] energy to alleviate local grid constraints, with the goal of helping PG&E avoid or defer distribution upgrades,' Sunrun said." [**UTILITY DIVE**](https://www.utilitydive.com/news/a-million-customers-have-connected-solar-to-pges-grid/822676/?ref=calregulatory.com) - **Another California Refinery Closure Will Threaten National and Global Economies:** "Three of the largest ports in America are in California. Los Angeles and Long Beach in Southern California, and Oakland in Northern California. It is important to note that these ports cannot handle large volumes of imported fuel due to infrastructure limitations. This is because California’s in-state refineries were designed to meet California’s fuel requirements. With the current refineries that have shut down and the potential for additional refineries shutting down, both military and our civilian airports are put at extreme risk due to those port infrastructure limitations." [**ENERGY NEWS BEAT**](https://energynewsbeat.co/big-oil-companies/another-california-refinery-closure-will-threaten-national-and-global-economies/?ref=calregulatory.com) - **California's Hot Rock Summer:** "California is the nation’s geothermal leader, producing more than two thirds of geothermal electricity in 2025\. But geothermal still represents a small share, about five percent, of the state’s overall electricity generation." [**POLITICO**](https://www.politico.com/newsletters/california-currents/2026/06/12/californias-hot-rock-summer-00961204?ref=calregulatory.com) - **California Bragging – Misleadingly Accurate:** "...achieving the 90% clean energy required by law by 2035 would require providing 100% clean energy for approximately 7,884 hours, an increase of approximately 6,000 hours over the 10-year period, more than double the recent pace of 'clean energy' hour increases. This would require a significant increase in solar and wind generation and more than doubling current battery storage capacity to displace the current electricity imports." [**CLIMATE CHANGE CONUNDRUM**](https://edreid.substack.com/p/california-bragging) - **California Petroleum Reserve Under Discussion in Response to Energy Security Concerns:** "The Trump administration is considering creating a petroleum reserve in California after a proposal from Sable Offshore Corp. The company proposed a West Coast Strategic Petroleum Reserve, and U.S. Energy Secretary **Chris Wright** confirmed that there is 'active dialogue' on the issue, according to [E&E News](https://www.eenews.net/articles/trump-admin-in-active-dialogue-on-strategic-petroleum-reserve-in-california/?ref=calregulatory.com). The administration cited the state’s strategic military importance, geographic isolation from major domestic energy networks, and increasing dependence on imported crude oil. A reserve would require a major expansion of oil infrastructure in California." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-petroleum-reserve-under?ref=calregulatory.com) - **California Supreme Court Declines to Hear Rooftop Solar Billing Case:** "The high court’s decision means a lower court ruling from March will stand. That decision, issued by the California Court of Appeals, upheld a California Public Utilities Commission [policy that sharply scaled back grid export rates paid to residential solar](https://pv-magazine-usa.com/2022/12/15/california-pulls-the-plug-on-rooftop-solar/?ref=calregulatory.com) customers, known as net energy metering (NEM 3.0)." [**PV MAGAZINE** ](https://pv-magazine-usa.com/2026/06/10/california-supreme-court-declines-to-hear-rooftop-solar-billing-case/?ref=calregulatory.com) - **CPUC Finalizes Community Solar Scheme, CLASS Argues Program is "Destined for Continued Failure":** "The ongoing debates around community solar in California follow a decision made by the US Environmental Protection Agency to [cancel the US$7 billion Solar For All programme](https://www.pv-tech.org/us-to-kill-us7-billion-solar-for-all-support-for-low-income-households/?ref=calregulatory.com), which was established under the Biden-era Inflation Reduction Act to fund access to solar projects for close to one million low-income US households. California, in particular, was set to receive US$249 million in Solar For All financing." [**PV TECH**](https://www.pv-tech.org/cpuc-finalises-community-solar-scheme-class-destined-for-continued-failure/?ref=calregulatory.com) - **Even $75M from Trump May Not Save Oakland's Embattled Coal Terminal:** "**Ben Eichenberg**, an attorney with the San Francisco Baykeeper, an environmental group in the Bay Area, said that terminal construction 'really hasn’t gone anywhere because there’s no money to build' the facility. 'The Trump administration stepping in and saying they’re going to supply that money gives it a new lifeline,' he said. 'This terminal project was drowning, and they’ve just been thrown the life preserver.'" [**GRIST**](https://grist.org/energy/trump-oakland-coal-terminal-funding/?ref=calregulatory.com) - **Visualizing California Renewables Curtailments:** "April 2026 was an all-time record for renewables curtailment in California. [1.46 million MWhs](https://www.caiso.com/about/our-business/managing-the-evolving-grid?ref=calregulatory.com). That’s a lot. Equivalent to [18%](https://www.caiso.com/documents/daily-renewable-report-jun-09-2026.html?ref=calregulatory.com) of all grid-scale wind and solar generation for the month."[ **ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/06/15/visualizing-california-renewables-curtailments/?ref=calregulatory.com) - **What's Really Going on With Tahoe's Power Situation?** "An investor-owned utility company serving tens of thousands of Lake Tahoe residents in California is seeking a new power supplier starting next year, with customers left in limbo about who that might be. Liberty Utilities services approximately 50,000 customers across the Tahoe Basin - including North and South Lake Tahoe as well as parts of Truckee. The California-based company sources its energy from Nevada. A portion comes from solar facilities, but the majority is purchased through another investor-owned utility, NV Energy, which will stop supplying Liberty after May 2027." [**CAP RADIO**](https://www.capradio.org/articles/2026/06/11/whats-really-going-on-with-tahoes-power-situation/?ref=calregulatory.com) ### NEWS CODEX: Geothermal Ring of Fire; Community Solar Decision; PG&E's Electrification Impact Study URL: https://www.calregulatory.com/news-codex-geothermal-ring-of-fire-community-solar-decision-pg-es-electrification-impact-study/ Last updated: 2026-06-12T17:34:53.000Z - **California's Hot-Rock Potential:** "California is perched on the 'Ring of Fire,' a chain of volcanic, earthquake-prone areas wrapped around the Pacific ocean. The grinding of tectonic plates beneath California has left a string of hotspots from Pinnacles National Park through the Berkeley Hills and up to Mt. Shasta. Other accessible heat pockets lie beneath thin, spreading plates under Nevada, Utah and New Mexico. The Salton Sea region has yet more potential." [**THE CURRENT**](https://www.cleanpowercalifornia.org/californias-hot-rock-potential/?ref=calregulatory.com) - **California Democrats Threaten to Block Newsom Priorities Over Imperiled Climate Deal:** "California Senate Democrats want to put the brakes on a new program by **Gov. Gavin Newsom**’s administration that steers free pollution permits to oil refineries and other major polluters — and they’re using the state budget to force the issue. In the [spending proposal](https://sbud.senate.ca.gov/system/files/2026-05/5.28-sub-2-energy-utilities-air-closeout-agenda-outcomes.pdf?ref=calregulatory.com) they released last month, the senators moved to block the program until the state funds a [three-party climate deal](https://calmatters.org/politics/2025/09/california-cap-and-trade-extension/?ref=calregulatory.com) the governor struck with the Legislature last year, an agreement they say Newsom is now breaking. They call their counterplan 'Deal is a Deal,' signaling a standoff that could stretch through the summer." [**CAL MATTERS**](https://calmatters.org/politics/2026/06/newsom-climate-rules-budget-fight-senate-democrats/?ref=calregulatory.com) - **California Doubles Down on "Unworkable" Community Solar Program:** "The CPUC voted to advance a community solar program that solar industry members are calling 'unworkable.' The Solar Energy Industries Association says 'virtually ensures' that no new community solar projects will be developed in the state under current structure." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/06/12/california-doubles-down-on-unworkable-community-solar-program/?ref=calregulatory.com) - **CPUC Passes Through "Failed" Community Solar Program, Industry Advocates Say:** "Yesterday’s CPUC vote implemented the community solar program as-written, without support from solar advocates. CPUC finalized that the state’s community solar program will use CPUC’s existing [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com) pricing structure, that would 'ensure non-participating customers do not pay on their electricity bills for more than the avoided wholesale cost of the electricity generated.'" [**SOLAR POWER WORLD**](https://www.solarpowerworldonline.com/2026/06/cpuc-passes-through-failed-community-solar-program-industry-advocates-say/?ref=calregulatory.com) - **California Plug-In Solar Bill Advances After Another Unanimous Vote:** "Senate Bill 868 is on the move after an 18-0 vote in the Assembly committee on utilities and energy. The bill would create rules allowing Californians to use so-called 'balcony solar' devices with up to 1,200 watts output that plug directly into a standard outlet." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/06/11/california-plug-in-solar-bill-advances-after-another-unanimous-vote/?ref=calregulatory.com) - **California Selects Scale to Build Microgrid for Santa Barbara City College Emergency Hub:** "The campus microgrid being developed by [New Jersey-based Scale ](https://www.microgridknowledge.com/distributed-energy/community-solar/article/33018948/scale-microgrids-500-mw-community-solar-deal-seen-as-opportunity-to-add-value-to-microgrids?ref=calregulatory.com)will integrate solar panels, battery storage and EV charging infrastructure. Previously known as Scale Microgrid Solutions, the company has built numerous on-site power projects for tribes, communities and companies throughout California." [**Microgrid Knowledge**](https://www.microgridknowledge.com/campus-microgrids/news/55381756/california-selects-scale-to-build-microgrid-for-santa-barbara-city-college-emergency-hub?ref=calregulatory.com) - **Data Center Growth Projections Creep up in California:** "During a June 9 workshop, California Energy Commission staff said data center peak demand is projected to increase by 5,800 MW by 2040 under a planning scenario and up to 8,300 MW under a local reliability scenario. These increases would bump up [CAISO](https://www.rtoinsider.com/category/rto/rto-caiso-weim/?ref=calregulatory.com)’s peak demand by about 9% and 11%, respectively, by 2040." [**RTO INSIDER**](https://www.rtoinsider.com/134080-data-center-growth-projections-creep-up-california/?ref=calregulatory.com) - **Energy Reality Emerges as a Clear Winner in California Primary:** "In a striking break from the green orthodoxy that has dominated California politics for years, former **Attorney General Xavier Becerra** [openly declared in May](https://nypost.com/2026/05/31/us-news/leading-dem-california-governor-candidate-announces-massive-break-with-the-left-on-key-policy/?ref=calregulatory.com) that the state still needs Chevron and the reliable energy it produces. 'They’re not the bad guy,' Becerra said. 'You need Chevron. I need Chevron. My people of the state of California need Chevron.' That pragmatic nod to energy reality helped propel Becerra to victory in the state’s jungle gubernatorial primary, while billionaire climate activist **Tom Steyer** finished a distant third behind Becerra and **Republican Steve Hilton**. Steyer’s also-ran finish came despite having poured more than $215 million of his own money into the race while pushing the Rockefeller-backed '[Make Polluters Pay](https://apnews.com/article/california-governor-election-race-election-primary-3954393a06fbf8b7fc11b0d2e6e90d40?ref=calregulatory.com)' and 'Keep It in the Ground' agenda." [**FORBES**](https://www.forbes.com/sites/davidblackmon/2026/06/11/energy-reality-emerges-as-a-clear-winner-in-california-primary/?ref=calregulatory.com) - **Five Billion Barrels of Crude Oil:** "One would think the experts who define and enforce California’s energy policies would recognize the futility of destroying California’s oil industry when demand for oil is going to persist for at least another 20 years. Why not extract it right here? Instead we export the jobs and the environmental impact to [nations with minimal standards](https://www.energy.ca.gov/data-reports/energy-almanac/californias-petroleum-market/foreign-sources-crude-oil-imports?ref=calregulatory.com)." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/five-billion-barrels-of-crude-oil/?ref=calregulatory.com) - **How to Use Time-of-Use Pricing to Manage EV Charging:** "The solution is to have different sets of TOU periods with staggered starting and ending times." [**ECONOMICS OUTSIDE the CUBE**](https://mcubedecon.com/2026/06/02/how-to-use-time-of-use-pricing-to-manage-ev-charging/?ref=calregulatory.com) - **Inside the Findings of PG&E's Electrification Impact Study:** "Electrification growth may provide downward pressure on distribution rates by as much as 25% (\~3.5 cents/kWh) by 2040." [**E3**](https://www.ethree.com/webinar-pge-eis/?ref=calregulatory.com) - **Sonoma Clean Power Aims for 1,000 No-Cost Smart Thermostats Amid VPP Push:** "The thermostat deployment is part of a broader effort to expand a multi-resource virtual power plant that includes thousands of electric vehicle chargers, battery storage systems, heat pump water heaters, and smart electrical panels, SCP said in November. The California Energy Commission provided a [$4.99 million grant](https://cal-cca.org/scp-awarded-4-99-million-grant-to-expand-smart-energy-access-for-underserved-communities/?ref=calregulatory.com) for the project and SCP will kick in $1 million of its own funds." [**UTILITY DIVE**](https://www.utilitydive.com/news/sonoma-clean-power-aims-for-1000-no-cost-smart-thermostats-amid-vpp-push/822515/?ref=calregulatory.com) - **When the Lights Went Out in Spain – and Why California Should Pay Attention:** "What happens when a power system loses its ability to control voltage? Unfortunately, we now have a recent and well-documented example, and the parallels to California’s current direction are uncomfortably close." [**GREEN NUKE**](https://kilovar1959.substack.com/cp/200008271) - **Why is Grid Inertia Still Important?** "In contrast to gigantic 2,256 megawatt nuclear power plants such as Diablo Canyon Power Plant near San Luis Obispo, California which provide very large amounts of synchronous grid inertia, so-called inverter-based resources such as solar powered generators, wind power generators, and batteries supply negligible amounts of synchronous grid inertia. Within the past decade, political decision makers in states such as California have been advocating for increasingly larger penetrations of IBRs without understanding the adverse impact those energy policy choices are having on electrical grid reliability." [**GREEN NUKE**](https://greennuke.substack.com/p/why-is-grid-inertia-still-important) ### June 11 CPUC Voting Meeting Results: Commission Makes SoCalGas Shareholders Pay for Safety Fixes URL: https://www.calregulatory.com/june-11-cpuc-voting-meeting-results-commission-makes-socalgas-shareholders-pay-for-safety-fixes/ Last updated: 2026-06-12T04:25:35.000Z At its June 11 [voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K056/608056639.pdf?ref=calregulatory.com), the CPUC approved the following items. - A revised safety culture plan submitted by SoCalGas, paid for by shareholders. - A $267.9 million utility-owned storage project for SDG&E. - A limited shared renewables program. - Updated prices for the Renewable Market Adjusting Tariff program. - The 2026 annual fee structure for registered Core Transport Agents. --- ### UTILITY SAFETY A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K379/608379820.pdf?ref=calregulatory.com) approves SoCalGas's "Revised Safety Culture Improvement Plan" as a foundation for implementation, while explicitly declining to find the plan's specific interventions adequate or effective. The CPUC's decision finds substantial improvement over SoCalGas's earlier submission but requires refinement in five areas: - Integrating security into the safety framework; - Strengthening contractor integration; - Improving resource allocation through "Learning Teams"; - Expanding speak-up mechanisms beyond occupational safety; and - Providing intervention-level metrics in quarterly compliance reports. Sempra must remain part of a consolidated plan. Rate recovery is denied for all plan costs (development, implementation, and future iterations), which will be paid by shareholders. **DAIS DISCUSSION**: Commissioners supported the decision while stressing that approval of the plan is not approval of SoCalGas's safety culture. - **Commissioner Darcie Houck** described the revised plan as a starting point, not an endpoint, and emphasized that the CPUC will retain close oversight through quarterly compliance reports until the next safety culture assessment in 2029\. She gave credit to SoCalGas for producing "a substantial improvement" on its previous plan but explicitly noted that "ratepayers will not be paying the cost of developing, implementing or revising the plan." - **Commissioner Karen Douglas** said safety culture improvement must be demonstrated through implementation, reporting, and measurable outcomes over time. - **Commissioner Christine Harada** drew on her aerospace background, saying safety in that industry meant making sure things did not "go kaboom in the wrong way." She said safety is not proven by polished reports, dashboards, or lists of completed activities, but by changes in behavior, priorities, incentives, escalation, management discipline, accountability, and how SoCalGas allocates resources and responds to employees and contractors who raise concerns. **INSTANT ANALYSIS**: The CPUC is letting SoCalGas move forward because the revised plan is better and the proceeding has already outlasted the reassessment timeline the company would have faced under R.21-10-001\. The CPUC retains full authority to press on security, contractors, resource allocation, speak-up culture, Sempra oversight, and reporting. Cost recovery is the decision's most consequential outcome. Shareholders must fund all of this work until the next safety culture assessment clears the company. The logic is that these costs arose from SoCalGas's own organizational failures, and ratepayers should not pay to correct them. Commissioner Houck tied that outcome to the circumstances that led to the investigation and California's affordability crisis, while Commissioner Harada said customers should not be asked to pay for the company to correct deficiencies in its own safety culture. --- ### UTILITY-OWNED GENERATION [Resolution E-5467](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K379/608379816.pdf?ref=calregulatory.com) approves SDG&E's Membership Interest Purchase Agreement to acquire [Westside Canal Phase 2a](https://ceqanet.lci.ca.gov/2020040122/4?ref=calregulatory.com) from [RWE](https://www.rwe.com/en/?ref=calregulatory.com) for **$267.9 million**, with RWE retained for operations and maintenance under a 10-year services agreement. The project is a **119 MW**, four-hour lithium-ion storage facility in Imperial Valley. It came online in December 2024 and would be owned by SDG&E, with costs recovered through the Cost Allocation Mechanism (CAM) to all benefitting customers. SDG&E sought approval under the CPUC's summer reliability and Effective Planning Reserve Margin (EPRM) framework. The resolution rejects protests from the Independent Energy Producers (IEP), CalCCA, and Cal Advocates. - IEP argued the solicitation excluded independent developers and violated the Commission's competitive market first policy. - CalCCA argued SDG&E exceeded its 120-220 MW EPRM range and that only 11.4 MW of the project should flow to CAM. - Cal Advocates argued the project provides no incremental reliability benefit (RWE is already selling RA from it on a merchant basis) and that the net market value does not justify the acquisition cost. Resolution E-5467 finds SDG&E's procurement consistent with prior summer-reliability decisions, the cost competitive against other approved projects and RFO offers, and the "meet and exceed" language from [D.21-12-015](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M428/K821/428821475.PDF?ref=calregulatory.com) still operative through [D.25-06-048](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K237/571237404.PDF?ref=calregulatory.com), meaning EPRM ranges are not caps. On deliverability, the project has interim status for 2025 and 2026 but will not reach Full Capacity Deliverability Status until transmission upgrades complete, currently expected in 2034\. The resolution accepts the risk that interim deliverability may not be available in future years. It cites price reductions, RWE penalty provisions, continued CAISO market participation, and quarterly CAM Procurement Review Group reporting as mitigation. **DAIS DISCUSSION**: Commissioners approved the item 5-0, but their discussion was more guarded than the vote count suggests. A representative from Energy Division framed the project as statewide reliability support rather than a strict SDG&E-only need, noting that EPRM procurement by one IOU supports the system-wide objective and that the system has not generally met the minimum EPRM targets. Staff also emphasized that utility ownership changes the market behavior of the asset: SDG&E must bid under least-cost dispatch rules, with revenues returned to customers, while a merchant owner would not face the same bidding constraints. **Commissioner Matthew Baker** said he viewed the project as the weakest of three utility-owned battery projects before the CPUC and would have preferred more time to examine operational issues. He credited the price reduction and the relative cost position of the asset, but also acknowledged the force of the protests: - SDG&E’s specific incremental EPRM need may be only about 11 MW; - SDG&E is long on Resource Adequacy; - The battery likely would remain in service under RWE; and - Full deliverability remains unresolved until 2034 unless operational changes, such as an eight-hour configuration, address the issue. Baker nevertheless supported the resolution, saying he would be nervous letting the opportunity pass. **President John Reynolds** also supported the item, emphasizing the multi-year review process, independent evaluator oversight, multiple rounds of negotiation, and Energy Division’s cost review against comparable projects. He described planning reserve margins as an insurance policy against emergencies, while acknowledging significant remaining uncertainty over the project’s deliverability and pointing to the required SDG&E updates to the procurement review group as an ongoing check. **INSTANT ANALYSIS:** The CPUC is blessing SDG&E's use of emergency-reliability authority to pull a fully operational merchant-adjacent storage asset into utility ownership and spread $267.9 million across all benefitting customers through CAM. However, this is not an unqualified endorsement. Commissioner Baker accepted the deal despite calling it the weakest of the utility-owned battery cases and recognizing the core protest arguments on need, merchant operation, and deliverability. The deliverability problem is the main ratepayer risk. The project has interim deliverability now, but full deliverability is not expected until 2034, and the CPUC is relying on price concessions, penalty provisions, market participation and quarterly reporting rather than a firm RA-value guarantee. The approval therefore expands utility-owned storage under the summer-reliability framework while leaving a significant portion of the long-term RA value question unresolved. --- ### SHARED RENEWABLES A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K372/608372079.PDF?ref=calregulatory.com) implements the California Shared Renewables Portfolio in a form far more limited than community solar advocates sought. A **$33 million** state appropriation reverted to the General Fund in June 2025, and the EPA terminated California's [Solar for All](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/state-of-california-solar-for-all-program?ref=calregulatory.com) award in August 2025, eliminating the external funding that a 2024 decision ([D.24-05-065](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M533/K188/533188781.PDF?ref=calregulatory.com)) assumed would make the program workable. The investor-owned utilities must file Tier 2 advice letters within 90 days proposing Community Renewable Energy tariffs built on the [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), but compensation cannot exceed [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com) avoided costs and nonparticipating customers cannot fund adders of any kind. If external funding later materializes, each IOU must file a separate Tier 3 advice letter covering the implementation plan, marketing, bill credits, and balancing account details. If no developer executes a ReMAT Power Purchase Agreement within two years of the Tier 2 disposal date, each IOU may discontinue its program via Tier 1 advice letter. The decision also: - Consolidates Green Tariff oversight into procurement review and [ERRA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com) cost proceedings; - Eliminates annual forums and advisory board meetings; - Moves stranded Green Tariff costs into ERRA; - Shifts the [Disadvantaged Communities Green Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/solar-in-disadvantaged-communities/the-disadvantaged-communities-green-tariff-dac-gt-program?ref=calregulatory.com) and [Community Solar Green Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/solar-in-disadvantaged-communities/the-community-solar-green-tariff-csgt-program?ref=calregulatory.com) funding from GHG allowance proceeds to Public Purpose Program surcharge collections effective **July 1, 2026**; - Reduces the advice letter tier required for new Community Choice Aggregator DAC-GT programs from Tier 3 to Tier 2; and - Directs program administrators to transition reporting to [DGStats](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) within 90 days of vendor notification that the platform is ready. **DAIS DISCUSSION:** Commissioners approved the decision 3-1, with President John Reynolds and Commissioners Karen Douglasand Christine Harada voting yes and Commissioner Darcie Houck voting no (Commissioner Baker was recused). - President Reynolds framed the decision as a ratepayer-protection measure. He contrasted competitively procured utility-scale solar with community renewable energy projects, which can receive administratively set compensation regardless of location, and said the pricing structure must ensure nonparticipating ratepayers do not pay more than the avoided-cost value of the electricity generated. - Commissioner Houck dissented, saying she still has objections to D.24-05-065 and that the loss of third-party funding made the program even less practical. She said the ReMAT-based compensation mechanism may not be practical, warned that pending legislation in Assembly Bill 18 could force additional changes, and said the CPUC was trying to “make a square peg fit into a round hole” by moving ahead with a program that lacks funding and has uncertain participation. - Commissioners Douglas and Harada supported the decision on ratepayer-protection grounds. Douglas said ReMAT was the appropriate foundation because it allows contracts of up to 20 years, compared with 12 years under the PURPA standard offer contract, and said statewide affordability concerns required the Commission to be “very rigorous” about limiting nonparticipant cost exposure. - Harada acknowledged that the decision would disappoint community solar advocates, but said the CPUC could not create a new subsidy or shift costs to other customers without external funding or legislative direction. She also emphasized that DGStats reporting will be important to determine whether the program produces participation, savings or project development. **INSTANT ANALYSIS:** This decision builds a tariff shell and waits for money that does not currently exist. The 3-1 vote reflected broad agreement that community solar has value, but not agreement that this structure is likely to work. Commissioner Houck’s dissent captured the practical problem: with the Solar for All award terminated, the state appropriation reverted, AB 18 pending, and ReMAT compensation unlikely to support new projects, the Commission may be setting up a program that remains mostly theoretical. The majority treated that problem as a legal and affordability constraint rather than a reason to stop. Every compensation structure that would make a community renewable energy project financeable was rejected as either a statutory violation or a matter requiring legislative action. Any CCA or Electric Service Provider may enter or exit the program at any time via Tier 1 advice letter, but participation in a program with no revenue support sufficient to attract project development is academic until external funding reappears. --- ### REMAT PROGRAM [Resolution E-5457](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K150/608150933.pdf?ref=calregulatory.com) updates fixed avoided-cost prices for the CPUC's Renewable Market Adjusting Tariff program, the feed-in tariff for renewable generators of 3 MW or less. The resolution adopts new ReMAT prices based on weighted-average Renewable Portfolio Standard contract prices from utility, Community Choice Aggregator and ESP contracts executed between 2020 and 2025 for projects of **20 MW** or less. The 2026 prices are as follows. - **$58.38/MWh** for as-available non-peaking; - **$67.40/MWh** for as-available peaking; and - **$92.33/MWh** for baseload. Against the 2025 figures, non-peaking rises from $52.85/MWh, peaking falls slightly from $67.99/MWh, and baseload increases from $75.96/MWh. PG&E, SCE and SDG&E must file Tier 1 advice letters within 30 days to amend their tariffs. Existing contracts are unaffected. The ReMAT program has produced 65 contracts totaling roughly 112 MW since inception, mostly small hydro and solar PV. Two contracts were executed in 2025\. **INSTANT ANALYSIS:** The baseload price jumps 21%, from $75.96/MWh to $92.33/MWh, driven by geothermal contracts dominating the baseload reference set. Non-peaking prices rise modestly. Peaking is essentially unchanged. In short, this is the administratively set avoided-cost rate catching up to a higher cost environment for small baseload renewables. The practical effect is limited by program scale. ReMAT has never been a volume story. But the resolution keeps a standardized procurement channel open for sub-3 MW projects and gives the utilities updated tariff prices without reopening PURPA or RPS policy skirmishes. The resolution changes nothing about actual program design. --- ### CORE TRANSPORT AGENTS [Resolution G-3621](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K566/608566014.pdf?ref=calregulatory.com) reaffirms the CPUC's 2026 annual fee structure for registered Core Transport Agents, keeping the base fee at **$5,000** while applying variable fees only to CTAs that generated consumer-protection costs in 2025. The methodology from [Resolution G-3597](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M509/K545/509545115.PDF?ref=calregulatory.com) remains intact. Fixed administrative costs are spread across all 39 registered Core Transport Agents; variable costs are assigned by [Consumer Affairs Branch](https://www.cpuc.ca.gov/about-cpuc/divisions/news-and-public-information-office/consumer-affairs-branch?ref=calregulatory.com) complaints and [Utility Enforcement Branch](https://www.cpuc.ca.gov/regulatory-services/enforcement-and-citations/utility-enforcement-branch?ref=calregulatory.com) unauthorized-enrollment investigations and enforcement actions. Staff calculated 2025 fixed costs at **$212,491**, or **$5,449** per Core Transport Agent, within the 20% tolerance band. The base fee stays put. The complaint picture is worse. The Consumer Affairs Branch received 2,942 CTA-related complaints in 2025, up **75%** from 2024, including 2,067 phone contacts and 875 informal written complaints. For 2026, the CAB variable charge is **$5.94** per phone contact and **$189.52** per informal written complaint. Utility Enforcement Branch charges are **$680.43** per unauthorized-enrollment complaint and **$739.17** per enforcement action. The largest total fees fall on [Wave Energy](https://www.linkedin.com/company/wave-energy-llc/?ref=calregulatory.com), [SFE Energy](https://www.sfeenergy.com/?ref=calregulatory.com), [Big Tree Energy](https://www.bigtreeenergy.com/?ref=calregulatory.com), and United Energy Trading/[Callective Energy](https://callectiveenergy.com/about/?ref=calregulatory.com). **INSTANT ANALYSIS:** CTA-related complaints rose 75% in 2025, and unauthorized-enrollment complaints increased 88%. But total enforcement actions fell 83%, from 393 in 2024 to 65 in 2025, including a drop in citations from 387 to 55\. Four suppliers generated 52% of all complaints. The CPUC is not socializing those costs. The cost-causation design remains intact, and high-complaint CTAs pay substantially more than low-complaint ones. ### CRI Housekeeping Notes: June Publishing, Premium Access, Contact Reminder URL: https://www.calregulatory.com/cri-housekeeping-notes-june-publishing-premium-access-contact-reminder/ Last updated: 2026-06-11T18:05:50.000Z Hi all, some housekeeping notes. - CRI is on a summer break from **June 16-23**. Posting will be limited or paused during this period. - In the meantime, if you find CRI useful, please sign up for [**premium access**](https://www.calregulatory.com/pricing-2/#/portal/signup/6a023109c799620001352e52/monthly), which helps keep the lights on. **Group rates are available via no-hassle monthly invoicing –** [**contact us**](https://www.calregulatory.com/contact-us/) **for details.** - For those following markets beyond California, please check out my reporting at [RTO Insider](https://www.rtoinsider.com/category/rto/ieso/?ref=calregulatory.com). This work is focused on Ontario ([IESO](https://ieso.ca/?ref=calregulatory.com)) but may soon extend to Alberta ([AESO](https://www.aeso.ca/?ref=calregulatory.com)) and Nova Scotia ([IESO Nova Scotia](https://ieso-ns.ca/?ref=calregulatory.com)). If you are a stakeholder in those markets, [let's talk](https://www.calregulatory.com/contact-us/). - If you have any tips, news, recommendations, or want to introduce yourself, we'd like to [hear from you](https://www.calregulatory.com/contact-us/). For formal meeting requests, please send a calendar invite. Best, [**Michael Cade**](https://www.linkedin.com/in/mikecade/?ref=calregulatory.com)**/Principal Analyst @ CRI** ### RESOURCE ADEQUACY: The Assumptions Behind the 2028 LOLE Study (R.25-10-003) URL: https://www.calregulatory.com/resource-adequacy-the-assumptions-behind-the-2028-lole-study-r-25-10-003/ Last updated: 2026-06-11T12:30:36.000Z The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K305/608305690.PDF?ref=calregulatory.com) in the Resource Adequacy docket that attaches Energy Division's "[Revised Inputs & Assumptions" for the 2028 Loss of Load Expectation Study](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K310/608310037.PDF?ref=calregulatory.com). This document establishes the modeling inputs and assumptions for the 2028 LOLE study, which has not yet been conducted. Integrated Resource Planning stakeholders will continue using the February 2026 inputs for the remaining analytical work in the 2024-2026 IRP cycle under the [Joint Agency Single Forecast Set agreement](https://efiling.energy.ca.gov/GetDocument.aspx?tn=269494&DocumentContentId=106587&ref=calregulatory.com). ### **MODEL & DATA VINTAGE** Staff deployed SERVM 10.28 and expanded the weather and hydro record to 2000-2024\. California demand moves to the [California Energy Commission 2025 Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr/2025-integrated-energy-policy-report?ref=calregulatory.com) Planning Scenario without known loads, non-CAISO resources are refreshed from the 2034 [Western Electricity Coordinating Council Anchor Data Set](https://www.wecc.org/program-areas/reliability-planning-performance-analysis/reliability-modeling/anchor-data-set-ads?ref=calregulatory.com), and all costs shift to 2024 real dollars. Staff also added ambient-temperature derates for thermal units. Unlike IRP modeling, the RA study uses [Net Dependable Capacity](https://www.lawinsider.com/dictionary/net-dependable-capacity?ref=calregulatory.com) for unit maximum output rather than the monthly Net Qualifying Capacity cap. ### **LOAD** Staff decomposes the 2025 IEPR managed forecast into consumption and demand modifiers (EV charging, transportation electrification, building electrification, behind-the-meter PV and storage, energy efficiency, climate adjustment, and data centers) grossed up for T&D losses to model demand at the generator busbar. Staff calibrates to the IEPR 1-in-2 consumption forecast rather than managed demand, which leaves SERVM's 2028 managed peak 1,032 MW above the IEPR figure: **49,388 MW** versus 48,356 MW. ### **BASELINE RESOURCES** The 2028 CAISO baseline grows from 97,843 MW to **114,813 MW**, a net gain of **16,970 MW**, driven by batteries at 9,891 MW, solar at 5,555 MW, and wind at 1,244 MW. Combined Heat & Power rises 1,676 MW partly because staff reclassified units previously coded as combined cycle gas turbine or peakers. Demand response capacity falls 508 MW following the CPUC's [discontinuation of the Demand Response Auction Mechanism programs](https://www.utilitydive.com/news/demand-response-california-dram-der-distributed-energy-resources/715987/?ref=calregulatory.com). Diablo Canyon is in the RA baseline through its extended operating dates while IRP modeling continues to use the original retirement schedule. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/06/table-8.png) ### **OPERATIONS & PROFILES** The study retains an **11,040 MW** maximum available import cap alongside a **4,000 MW** peak-hours cap from 5 p.m. to 10 p.m., with three-hour ramping between the two, applied in all months. Hydro modeling uses the full 25-year record with separate run-of-river and scheduled-hydro treatment for PG&E and SCE. Natural gas inputs use the CEC North American Market Gas-Trade Model mid scenario. ### **RA MODELING** SERVM tests whether CAISO meets the 0.1 days/year LOLE standard and calculates Total Reliability Need in perfect-capacity terms. In response to SCE and CalCCA concerns, staff will run a [MISO](https://www.misoenergy.org/?ref=calregulatory.com)\-style load-uncertainty sensitivity alongside the existing CPUC distribution. LOLE concentrates in June through September via the prior cycle's stress-test method, and if the system proves over-reliable, staff will test three methods in the following order: - Adding perfect demand; - Reducing capacity pro rata across all technology types; and - Lowering the simultaneous import limit. Final results include both UCAP-derated and non-UCAP-derated Planning Reserve Margin values. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/06/12.png) ### **EMISSIONS** Unspecified imports are assigned [CARB](https://ww2.arb.ca.gov/?ref=calregulatory.com)'s default emissions rate of **0.428 metric tons/MWh**, while 8.31% of Northwest hydro is designated as a GHG-free specified import exempt from hurdle rates and emissions charges. Behind-the-meter CHP emissions are estimated from the 2025 IEPR forecast and added to modeled dispatch emissions to align with CARB electric-sector accounting. ### INSTANT ANALYSIS This filing establishes the assumptions that will produce the first major reliability determination in this proceeding, with the LOLE study expected by **August 2026**. The baseline expansion makes over-reliability a plausible starting point: the 2028 CAISO baseline is nearly 17 GW larger than the prior version, led by approximately 10 GW of batteries and 5.5 GW of solar. That makes staff's stress-test methodology choices consequential. Adding perfect demand, reducing capacity pro rata, and lowering the import limit affect different resource classes and load-serving entities differently, and the document does not indicate which approach staff will prioritize. The load assumptions remain contested. The 1,032 MW gap between SERVM's modeled 2028 managed peak and the IEPR projection is a direct product of staff's decision to calibrate to consumption rather than managed demand. Staff also agreed to run a narrower MISO-style load-uncertainty sensitivity, but the base case still uses the wider CPUC distribution. If the sensitivity produces a meaningfully different Planning Reserve Margin, parties will dispute which result should govern. External-region treatment may shift the result as much as the CAISO resource stack. Running both an as-is Anchor Data Set case and a calibrated-to-0.1-LOLE case will show how much California's modeled reliability depends on assumed surplus from neighboring regions, particularly a Pacific Northwest that may itself be resource-short. Diablo Canyon adds a separate mismatch: it's counted in the 2028 RA baseline but excluded from IRP modeling, meaning any RA determination premised on its presence will need revisiting as the extended operating dates approach. ### How Much Risk is Enough? The Answer Will Shape Billions in Utility Spending (R.26-04-016) URL: https://www.calregulatory.com/how-much-risk-is-enough-the-answer-will-shape-billions-in-utility-spending-r-26-04-016/ Last updated: 2026-06-09T20:00:57.000Z On June 8, parties submitted opening comments in the CPUC's Risk-Based Decision-Making Framework proceeding. The Risk-Based Decision-Making Framework governs how utilities quantify and propose safety spending in General Rate Cases. [R.26-04-016](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K216/606216455.PDF?ref=calregulatory.com) is the successor docket to [R.20-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M344/K081/344081678.PDF?ref=calregulatory.com), and picks up a handful of unfinished tasks from that proceeding's final decision ([D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com)), including: - Adopting a formal risk tolerance standard; - Formalizing additional RAMP review time for the [CPUC's Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com); and - Standardizing Benefit-Cost Ratio methodology, including optional Present Value Revenue Requirement treatment. --- ### **RISK TOLERANCE** A key dispute is whether the definition of risk tolerance should incorporate affordability. SoCalGas/SDG&E [say no](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K276/608276993.PDF?ref=calregulatory.com) and repeatedly answer that affordability is "outside the scope of this proceeding," arguing tolerance must be defined first to protect safety, with cost addressed separately afterward. On the other side stands a combined advocate-and-industrial bloc: Cal Advocates, TURN, Mussey Grade Road Alliance (MGRA), and EPUC/Indicated Shippers all support incorporating affordability or ratepayer cost tolerance into the framework. PG&E [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K229/608229912.PDF?ref=calregulatory.com) adopting a risk tolerance standard but wants it built through evidentiary hearings, not workshops, citing serious-injury-and-fatality exposure, public safety impacts, and litigation risk. SCE [wants](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K305/608305566.PDF?ref=calregulatory.com) the Benefit-Cost Ratio methodology stabilized before risk tolerance is finalized, using two coordinated workshop tracks. TURN is the most skeptical that an abstract standard can be built at all, [warning ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K212/608212022.PDF?ref=calregulatory.com)utilities will drive stated tolerance toward zero because capital grows rate base and profit. TURN invokes [Arrow's Impossibility Theorem](https://en.wikipedia.org/wiki/Arrow%27s%5Fimpossibility%5Ftheorem?ref=calregulatory.com) against any representative-consensus working group and instead favors building on D.25-08-032's budget-constrained portfolios anchored in ESJ affordability. MGRA [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K305/608305571.PDF?ref=calregulatory.com) Commission-led development, wants the Safety Policy Division directed to produce an improved proposal while allowing parties to submit alternatives, and proposes two scope additions: - The relationship between risk tolerance and risk-aversion scaling functions (which [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) Wildfire Mitigation Plan decisions are already pushing utilities to address collaboratively); and - [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com) integration of the OEIS WMP process into the Risk-Based Decision-Making Framework, including the loss of Commission ratification of WMPs, evidentiary use of OEIS-approved WMPs in General Rate Case proceedings, RAMP/WMP duplication, and intervenor compensation. MGRA frames at least some of these as potential future-phase items rather than immediate scope. EPUC/Indicated Shippers support incorporating affordability in the definition but reject a rigid standard, favoring a flexible framework keyed to each utility’s execution history. They demand unscaled, risk-neutral Benefit-Cost Ratios at the Risk Reporting Unit, project and program levels, backed by Risk Spending Accountability Report over/under-spending records and Risk Mitigation Accountability Reports. They also reject the lifestyle-risk benchmark (motor vehicles, drownings, housefires) and instead propose an unscaled Benefit-Cost Ratio of 1.0 or higher as the cost-effectiveness threshold, with a higher baseline for utilities with documented poor execution records. ### **RISK-SCALING** Cal Advocates [targets](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K212/608212020.PDF?ref=calregulatory.com) PG&E's proportional method of distributing risk evenly across a circuit segment, arguing it cannot capture within-segment heterogeneity. Cal Advocates also cites the Safety Policy Division Sempra RAMP finding that SDG&E's scaling did not meaningfully correlate with unscaled risk or unscaled Consequence of Risk Event values and appeared to increase Benefit-Cost Ratio values rather than guide risk-informed prioritization. EPUC/Indicated Shippers independently demand unscaled, risk-neutral Benefit-Cost Ratios. ### **BENEFIT-COST RATIO & O&M** Most parties support a standard O&M treatment. PG&E and SCE want net O&M in the denominator so all resource costs are measured against risk-reduction benefits, and PG&E expressly rejects SPD's Method 3, which moves O&M savings into the numerator, on grounds it would reward low-risk-reduction, high-savings projects. Cal Advocates argues that avoided O&M belongs in the numerator as a benefit. TURN supports denominator placement with a Present Value Revenue Requirement base and a discount rate consistent with the numerator. ### **PRESENT VALUE REVENUE REQUIREMENT** SoCalGas/SDG&E argue a PVRR derived from estimates lacks precision because reliable revenue-requirement figures exist only after the General Rate Case Results of Operations model runs, and answer "outside scope" to the PVRR questions. SCE opposes mandatory PVRR in Benefit-Cost Ratios as a ratemaking question belonging in the General Rate Case. PG&E is more nuanced: it has provided estimated PVRR in its 2027 General Rate Case and supports resolving Benefit-Cost Ratio methodology in this proceeding, but urges caution and framework stability before any further changes. Cal Advocates wants a standard method developed through an SPD workshop and white paper, with PG&E presenting its CHARGE tool. EPUC/Indicated Shippers call for a 20-year recovery period, Year Zero at in-service date, and discounting at current [Weighted Average Cost of Capital](https://en.wikipedia.org/wiki/Weighted%5Faverage%5Fcost%5Fof%5Fcapital?ref=calregulatory.com) on an after-tax basis, applied at the Risk Reporting Unit level for controls and tail risks such as wildfire and dam safety, with program-level application acceptable for other enterprise risks. ### **I**NSTANT ANALYSIS A risk tolerance standard will mean little unless the Commission also decides how much utility discretion remains inside the Benefit-Cost Ratio calculation. SoCalGas/SDG&E would define risk tolerance first and address affordability afterward; Cal Advocates, TURN, MGRA and EPUC/Indicated Shippers say the cost of eliminating risk is part of deciding what residual risk is tolerable. The key test is unscaled, risk-neutral Benefit-Cost Ratio reporting: a mitigation that clears 1.0 only after risk-aversion adjustments is not the same as one that clears 1.0 before utility scaling is applied. SCE wants Benefit-Cost Ratio methodology stabilized before risk tolerance is finalized. PG&E would put tolerance on a hearing track while moving BCR issues through workshops. The scoping memo will show how much of the parties' competing BCR agenda survives: PG&E and SCE want material BCR issues resolved in this proceeding rather than the [SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) undergrounding case; EPUC/Indicated Shippers want unscaled, risk-neutral BCRs at the RRU/project/program level; and Cal Advocates wants PVRR standardized as a fuller measure of ratepayer cost. ### NEWS CODEX: Changes to Cap-and-Invest; Critique of SOMAH Program; Possible EDAM Dysfunction URL: https://www.calregulatory.com/mnews-codex/ Last updated: 2026-06-09T17:17:32.000Z - **CAISO Expedites Congestion Revenue Rights Design Proposals:** "CAISO's congestion revenue rights enhancements initiative is intended to address a longstanding complaint by the ISO's Department of Market Monitoring about the impact of CRR payments on electricity ratepayers." [**RTO INSIDER**](https://www.rtoinsider.com/133527-caiso-expedites-crr-design-proposals/?ref=calregulatory.com) - **CAISO Monitor Warns of "Significant Dysfunction" in EDAM Due to Potential Self-Scheduling**: "DMM’s report comes after CAISO staff published a [report](https://stakeholdercenter.caiso.com/InitiativeDocuments/Stage-2-Analysis-Paper-Extended-Day-Ahead-Market-EDAM-Congestion-Revenue-Allocation-Apr-14-2026.pdf?%5Fgl=1%2Aylrr7x%2A%5Fga%2ANDEyMjcyMzczLjE3NjgyMzgxMDQ.%2A%5Fga%5FNDS4B4M2WP%2AczE3NzY3OTQ1ODEkbzEzOCRnMCR0MTc3Njc5NDU4OCRqNTMkbDAkaDA.&ref=calregulatory.com) in April that found the new CRA design is not expected to present material concerns under likely transfer situations when EDAM opened with PacifiCorp." [**RTO INSIDER**](https://www.rtoinsider.com/132470-caiso-monitor-warns-market-dysfunction-under-self-schedule-incentives/?ref=calregulatory.com) - **California Energy Commission Approves 3.2GWh BESS Project Through Newsom's Accelerated Permitting Scheme:** "The project, in California’s Alameda County, will store excess solar generation or low-cost grid electricity during off-peak hours. Construction is expected to begin in May 2027, with the project going into operation around 18 months later." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/california-energy-commission-approves-3-2gwh-bess-project-through-newsoms-accelerated-permitting-scheme/?ref=calregulatory.com) - **California is Rethinking Nuclear – Environmental Groups Should Too:** "Environmental groups don’t need to become nuclear power cheerleaders. But when Californians face rising electric bills, record heatwaves, and worsening wildfires, demanding they shut down a major source of the state’s carbon-free electricity is deeply out of touch." [**THE HILL**](https://thehill.com/opinion/energy-environment/5913823-california-nuclear-power-debate/?ref=calregulatory.com) - **California Makes Controversial Change to Cap-and-Invest Program:** "The California Air Resources Board...[approved](https://ww2.arb.ca.gov/news/carb-adopts-updates-californias-cap-and-invest-program-support-affordability-and-align-climate?ref=calregulatory.com) major changes to the state’s [cap-and-invest program](https://ww2.arb.ca.gov/our-work/programs/cap-and-invest-program/about?ref=calregulatory.com), including a controversial plan to allow polluting industries to earn free emissions allowances if they invest in decarbonizing their facilities — a move critics say could [undermine California’s decarbonization goals](https://www.canarymedia.com/articles/emissions-reduction/california-cap-and-invest-proposal?ref=calregulatory.com)." [**CANARY MEDIA**](https://www.canarymedia.com/articles/emissions-reduction/california-controversial-cap-and-invest-program?ref=calregulatory.com) - **California Provides Free Solar for Farmworker Households:** " In the case of SOMAH, the program is run so inefficiently that most poor families lose interest and cancel or withdraw. Neither program is reducing greenhouse gas emissions appreciably. And some poor folks find it hard to justify poking a hole in their roof for a small amount of benefit." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/renewable/solar/california-provides-free-solar-for-farmworker-households/?ref=calregulatory.com) - **Costly Blunder of Diablo Canyon Nuclear Plant:** "Recent media has profiled studies and potential legislation floating around the capitol touting the extended operation of Diablo Canyon nuclear plant beyond 2030 as a panacea for the state’s future energy needs, but they are fueled by outdated sources and wishful thinking. More accurate and up-to-date analysis reveals Diablo Canyon to be that 1960s clunker best left up on blocks in the garage. Propping it up will only add to ratepayer woes and fatten PG&E’s already bloated pockets at a time when 'affordability' is the mantra *du jour*." [**SANTA BARBARA INDEPENDENT**](https://www.independent.com/2026/05/19/costly-blunder-of-diablo-canyon-nuclear-plant/?ref=calregulatory.com) - **Defying Trump, California Continues to Bet Big on Offshore Wind:** "The proposed [Pier Wind project](https://polb.com/port-info/projects/?ref=calregulatory.com#pier-wind) at the Port of Long Beach is a 400-acre terminal for the positioning, storage and assembly of some of the world’s largest offshore wind turbines, which would be towed north to federal wind lease areas some 20 miles off Morro and Humboldt bays." [**LA TIMES**](https://www.latimes.com/environment/story/2026-05-24/defying-trump-california-continues-to-bet-big-on-offshore-wind?ref=calregulatory.com) - **FERC Denies Complaint Against SCE for Limiting Battery Charging:** "FERC's ruling appears to give Southern California Edison some latitude in how it serves battery storage customers under its tariff." [**RTO INSIDER**](http://rtoinsider.com/133985-ferc-denies-complaint-sce-limiting-battery-charging/?ref=calregulatory.com) - **Inside Gavin Newsom's Solar Scam:** "From the beginning, the SOMAH program has been plagued by delays and cancellations. More than 400 applications have wound up cancelled or withdrawn, or about a third of the [total](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/somah/evaluation-somah/third-triennial-2026-report/somah%5Fthird%5Ftriennial%5Freport%5Fdraft.pdf?ref=calregulatory.com). On average, projects [take](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/somah/evaluation-somah/third-triennial-2026-report/somah%5Fthird%5Ftriennial%5Freport%5Fdraft.pdf?ref=calregulatory.com) three and a half years to make it through the program’s [gauntlet](https://calsomah.org/application-process-and-documents?ref=calregulatory.com) of paperwork and inspections. Some projects have been fully installed—only to sit idle for a year or more waiting for permission to begin operating. As a result, more than $700 million of the program’s budget remains unspent. In other words, California can’t even give away a heavily [subsidized](https://calsomah.org/incentives-finance?ref=calregulatory.com#:~:text=tax%20credits%20and%20incentives), and sometimes [free](https://calsomah.org/tribes?ref=calregulatory.com#:~:text=covering%20up%20to%20100%25%20of%20the%20cost%20for%20installing%20solar%20energy%20panels%20on%20qualified%20multifamily%20affordable%20housing), product." [**CITY JOURNAL**](https://www.city-journal.org/article/california-gavin-newsom-solar-panels-affordable-housing-somah?ref=calregulatory.com) - **Is it Time for a Price-Stabilizing Gas Tax?** "The barriers to adopting a more rational gasoline tax policy are not economic or administrative, but political. It would require legislators to step out of their comfortable roles of hating gas taxes or (in some cases, *and*) arguing that we need higher prices on fossil fuel energy. Regardless of where you think gas prices should be, you probably don’t think that wild gyrations are a good way to get there. No state, not even the largest in the country, can really influence the world oil market, but we can help California households cope with the impacts." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/05/18/now-is-it-time-for-a-price-stabilizing-gas-tax/?ref=calregulatory.com) - **Massive SunZia Wind Project Starts Commercial Operation:** "At least three California community choice aggregators have contracted to receive power from SunZia Wind. Silicon Valley Clean Energy has contracted for 125 MW of capacity from SunZia Wind. Central Coast Community Energy contracted for 205 MW of SunZia capacity and began receiving power on May 28\. The wind energy is procured on behalf of all the CCA’s customers to help support clean energy goals, a 3CE spokesperson said. The Clean Power Alliance, which serves Los Angeles and Ventura counties, initially contracted for 575 MW of capacity, adding another 125 MW in September 2025 for a total of 700 MW." [**RTO INSIDER**](https://www.rtoinsider.com/133829-massive-sunzia-wind-project-starts-commercial-operation/?ref=calregulatory.com) - **Pioneering Grid Battery Nudges California Closer to 24/7 Clean Energy:** "On June 1, the Tumbleweed project in California’s Kern County became the first major battery installation in the U.S. that can discharge power for up to eight hours at a time — twice as long as typical energy-storage facilities." [**CANARY MEDIA**](https://www.canarymedia.com/articles/long-duration-energy-storage/pioneering-grid-battery-california?ref=calregulatory.com) - **Trump Administration in "Active Dialogue" on Strategic Petroleum Reserve in California:** "A new reserve would come to a West Coast that has few pipelines connecting it to the rest of the country. But it likely would draw opposition from Newsom and other California lawmakers who have tried to reduce the state’s dependence on fossil fuels especially after multiple pipeline ruptures have sent oil washing up on California beaches over the past several decades." [**POLITICO**](https://www.calregulatory.com/saturday-briefing-californias-load-growth-problems-are-showing-up-everywhere/) - **U.S. Grid Reliability Improves This Summer:** "According to the Federal Energy Regulatory Commission, U.S. grid reliability will improve this summer as [75 gigawatts of capacity](https://www.utilitydive.com/news/ferc-summer-market-reliability-assessment/820962/?ref=calregulatory.com) are being added to the grid, and power plant retirements are expected to slow by more than 50% to 8 gigawatts. The increase in capacity is the largest one-year increase in over a decade. With the added capacity, resources, and operating reserves are expected to be adequate in all NERC assessment areas under normal operating conditions." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/ferc/u-s-grid-reliability-improves-this-summer/?ref=calregulatory.com) ### SATURDAY BRIEFING: California's Load Growth Problems are Showing Up Everywhere URL: https://www.calregulatory.com/saturday-briefing-californias-load-growth-problems-are-showing-up-everywhere/ Last updated: 2026-06-07T02:11:47.000Z Today’s briefing covers the CAISO’s $6.7 billion transmission plan, PG&E’s latest data-center interconnection agreements, the CPUC’s revised 2026 Avoided Cost Calculator proposal, four draft resolutions setting stricter standards for Demand Response, and a utility report on Vehicle-Grid Integration. The common thread is load growth: California is building wires, repricing DER value, testing large-load cost protections, and asking whether flexible demand resources are actually dependable enough to count. --- ### TRANSMISSION PLANNING The CAISO recently approved its [2025-2026 Transmission Plan](https://www.calregulatory.com/opponents-say-socalgass-outage-reports-undercut-the-case-for-higher-aliso-canyon-inventory/), which authorizes 38 projects totaling **$6.7 billion** over the next decade, driven by reliability, policy and congestion needs. CAISO is now planning around load growth from electrification, data centers, manufacturing and transportation as much as renewable zone access, especially in the Greater Bay Area. Most of the package is reliability-driven, with 33 projects totaling **$4.2 billion**,led by the **$1.424 billion** Tesla-Trimble-Metcalf 230 kV corridor expansion in PG&E territory. Four policy-driven projects total **$2.4 billion**, including the **$1.685 billion** Trout Canyon-Lugo 500 kV line. The single economic project is the **$150 million** Gates-Los Banos #3 500 kV series compensation to reduce Path 15 congestion. The plan also cancels the previously approved Serrano-Del Amo-Mesa 500 kV project, originally estimated at **$1.125 billion** and now priced by SCE at **$5 billion**, replacing its reliability function with the Mesa-Laguna Bell 230 kV #2 Upgrade and dropping the policy need entirely after updated resource portfolios added 2,000 MW of downstream battery storage. **INSTANT ANALYSIS:** The CAISO is basically saying that California needs billions in new grid investment to serve data centers, electrification and clean-resource growth simultaneously, putting the plan directly in the path of CPUC battles over Transmission Access Charge exposure and large-load cost responsibility. PG&E's Greater Bay Area dominates the reliability picture. The Tesla-Trimble-Metcalf project and related Bay Area upgrades indicate that South Bay load growth is becoming a system-planning driver, not a one-off interconnection issue. Path 15 deserves close attention. The CAISO's congestion forecast has moved from 244 hours on the most limiting circuit in 2030 (per the 2021-2022 plan) to **3,256 hours** forecast for 2035, supporting the Gates-Los Banos project now and pointing toward a larger backbone decision next cycle. Central Valley constraints are becoming a major bottleneck for California's resource strategy. The CAISO is not approving every big-wire project blindly. The Serrano-Del Amo-Mesa cancellation shows the ISO will kill projects when costs outrun the original planning case. In short, transmission planning is becoming bigger, more iterative and more politically exposed to large-load cost allocation. --- ### LARGE LOAD INTERCONNECTION The CPUC issued [Draft Resolution E-5455](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K718/607718746.PDF?ref=calregulatory.com), which approves PG&E's agreement to energize Google's 250 MW San Jose data center with stronger ratepayer protections. The draft resolution caps annual refunds at actual net revenues received (not projected future revenues) and extends the refund window from 10 to 15 years. The agreement must be updated within 60 days of a decision in the [Rule 30 proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com) to reflect whatever cost-responsibility framework the CPUC adopts for broader transmission network upgrades. This is not a typical interconnection case. Google's load depends directly on the Newark-NRS 230 kV line (a **$1 billion**\+ project whose FERC-approved revenue requirement hits ratepayers at approximately **$100 million** per year) plus more than 10 other South Bay transmission upgrades. The CPUC previously capped refunds at 75% of net revenues for STACK Infrastructure and Microsoft ([Resolutions E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K498/586498115.PDF?ref=calregulatory.com) and [E-5439](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K970/595970063.PDF?ref=calregulatory.com)). Here it allows 100%, but only because the Rule 30 proceeding handles network-upgrade cost exposure separately. The earliest the CPUC will consider this item is **July 2**. **INSTANT ANALYSIS:** The "Base Annual Revenue Calculation" (BARC) process is being rewritten case by case. The process was built for distribution-scale energization where thousands of similar customers statistically absorb any single customer's stranded-cost risk. Here the Commission isn't rejecting BARC; it's acknowledging that BARC unadjusted can refund a customer up to nine times first-year net revenues in year one. Bottom line: Google can proceed, but the agreement is explicitly contingent on conforming to Rule 30's eventual network-upgrade cost framework. --- Separately, PG&E [is asking](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7919-E.pdf?ref=calregulatory.com) the CPUC to approve a non-standard interconnection package for GIC San Jose's 97.3 MW data center at 350 W. Trimble Road in San Jose. The project requires a new 115 kV switching station for regular service plus a customer-funded redundant 115 kV line. Regular-service upgrades are estimated at **$58.28 million**; the redundant Special Facilities package at **$10.73 million**. PG&E wants approval by Q1 2027 to begin construction by Q3 2027 and meet the customer's Q3 2028 service date. The ratepayer-protection structure runs on actual costs with progress billing rather than estimates. Refunds on the regular-service facilities are tied to actual revenues after service begins, calculated through PG&E's BARC process over 10 years: if load underperforms, refunds will shrink or disappear. The redundancy package carries no refund rights and triggers ongoing ownership charges. **INSTANT ANALYSIS:** This is another large-load data center interconnection through PG&E's exceptional-case process, smaller in scale than the Google agreement currently pending before the CPUC. The filing extends the template PG&E has been building across recent advice letters: - Actual-cost payment; - BARC-based refunds; - Minimum demand protections; - No refund rights for customer-requested redundancy; and - A CPUC/FERC jurisdictional split on cost recovery. PG&E is normalizing bespoke large-load agreements ahead of the Rule 30 outcome, using each filing to reinforce the same basic bargain: accelerated transmission service in exchange for upfront risk absorption, with the customer eating every dollar of optional redundancy. --- ### AVOIDED COST CALCULATOR The CPUC filed a revised [2026 Avoided Cost Calculator staff proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K229/608229880.PDF?ref=calregulatory.com), with [a ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K305/608305537.PDF?ref=calregulatory.com) setting opening comments as due **June 19**. The revision targets two things: - A reworked Integrated Calculation for generation capacity and GHG avoided costs; and - A change to the transmission avoided-cost methodology for SCE that drops the Locational Net Benefits Analysis in favor of Discounted Total Investment Method only. On GHG issues, staff propose to: - Collapse separate electric and gas values into a single electric-sector figure derived from Integrated Resource Planning modeling; - Eliminate the GHG Rebalancing component; and - Cap total GHG value at the high societal cost of carbon. The Integrated Calculation itself would move from a Python optimization criticized by stakeholders as a black box to an Excel-based framework using RESOLVE GHG shadow prices. Marginal capacity value would be derived from a hybrid solar-plus-storage resource rather than solved through the optimization. The hourly allocation changes are also substantive. Staff would swap expected unserved energy for loss-of-load hours as the basis for capacity value allocation, on the theory that each avoided loss-of-load hour carries equal marginal reliability value regardless of shortfall magnitude. Temperature would give way to SERVM energy prices as the trigger for identifying high-capacity-value days. This reflects IRP modeling showing California's reliability risk migrating from hot summer peaks toward winter periods driven by electrification load and low renewable output. The proposal would add weekday/weekend differentiation, consistent with reliability modeling and with Avoided Cost Calculator downstream uses (including Net Billing Tariff export rates) that already treat the two differently. **INSTANT ANALYSIS:** The proposal is a reweighting of the economic signals that flow through DER cost-effectiveness tests, electrification incentives, gas substitution economics, and Net Billing Tariff export rates across CPUC programs. The central policy move (collapsing gas-sector GHG avoided costs onto an electric-sector IRP proxy) reduces methodological inconsistency around electrification but does so before California has built a credible gas-sector marginal abatement cost. Staff acknowledged that deficiency themselves: no robust gas-sector GHG analysis has been completed since the interim **$114/tonne** value was adopted in 2022\. --- ### DEMAND RESPONSE The CPUC has four pending draft resolutions that impose stricter standards on Demand-Response program changes. - [Draft Resolution E-5456](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K789/607789354.PDF?ref=calregulatory.com) gives SCE approval to let customers enroll directly in its Capacity Bidding Program Elect, with SCE acting as aggregator, closing a participation shortfall that was leaving Self-Generation Incentive Program customers without a qualifying DR option when third-party aggregators stopped taking residential enrollments. - [Draft Resolution E-5444](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K792/607792084.PDF?ref=calregulatory.com) denies SDG&E approval for a new residential Capacity Bidding Program because its proposal weakens penalties too far from the existing model and lacks the Resource Adequacy compliance and load-impact filings required of supply-side resources. - [Draft Resolution E-5450](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M607/K797/607797629.PDF?ref=calregulatory.com) gives PG&E partial approval for changes to its Automated Response Technology program, including a 30-day performance evaluation timeline, Day-of Adjustment standardization, CAISO tariff alignment, and minor formatting updates. But the draft resolution rejects a 30% capacity-payment increase and a proposal to remove the cap that zeroes out negative performance, both insufficiently justified after just one year of program operation. - [Draft Resolution E-5453](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K056/608056801.PDF?ref=calregulatory.com) approves, with modifications, a joint PG&E and SCE request to update their Automated Demand Response Technology Incentive Program guidelines. The draft resolution expands eligible customer segments and measures, adds PG&E's ART program as a qualified residential AutoDR program, and clarifies cloud-based control requirements to align the two utilities' interpretations of existing policy. The earliest the CPUC will consider these items is **July 2**. **INSTANT ANALYSIS:** These draft resolutions are a rejection of sloppy program design. The CPUC will fix program-access problems and approve narrow implementation changes. What it will not do is approve residential DR expansion or DER-based supply-side programs without the documentation that real capacity resources require: defensible penalties, approved load impacts, RA compliance, and cost-effectiveness evidence. SDG&E got denied because its proposal had none of that. PG&E got half a loaf because it only brought some of it. --- ### VEHICLE-GRID INTEGRATION A new [joint report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K309/607309963.PDF?ref=calregulatory.com) filed by SCE, SDG&E, and PG&E provides a formal record of the CPUC's third annual VGI Forum held March 25 in the Transportation Electrification rulemaking ([R.23-12-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M521/K872/521872957.PDF?ref=calregulatory.com)). The report documents real but conditional VGI progress: managed and bidirectional charging can reduce long-term distribution costs, but only through grid-aware coordination that optimizes across bulk and distribution system needs simultaneously. Passive TOU-driven charging just moves load into new secondary peaks. Modeled savings (PG&E's[ Electrification Impact Study Part 2](https://www.ethree.com/wp-content/uploads/2026/03/PGE%5FEIS.pdf?ref=calregulatory.com) shows a **$1.8 billion** reduction in a **$25.5 billion** base case) depend on participation assumptions, reliable load response, sufficient aggregation scale, and whether VGI can actually defer specific upgrades. Cal Advocates cited the [DIDF](https://www.epri.com/research/products/000000003002034025?ref=calregulatory.com) precedent as a cautionary tale: that framework promised similar distribution deferrals and largely didn't deliver. Vehicle to Grid's commercial track record has promising data: [Tellus Green Power](https://telluspowergreen.com/?ref=calregulatory.com)'s school bus deployment ran 74 bidirectional chargers at 98%-plus uptime over two years. Residential is a different story: PG&E's [Vehicle-to-Everything pilots](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com) are behind enrollment targets, held back by equipment costs that outrun available incentives, no clear interconnection pathway, and dynamic rate complexity that makes it hard for customers to forecast savings. SCE's Charge Smart data points the other direction: customers respond when value is clear and upfront. Dynamic rates remain a system-level tool, not a distribution-level one; the forum said so repeatedly, and it's an important constraint on how far rates alone can take VGI. **INSTANT ANALYSIS:** The record now shows the familiar California sequence: large theoretical avoided-cost value, thin customer uptake, rate design that can't target distribution-level constraints, uncertain export compensation, and pilots expiring before they generate scalable rules. The unresolved questions are policy decisions the CPUC has deferred. VGI can still become a meaningful grid resource. But right now, it is not. ### Opponents Say SoCalGas’s Outage Reports Undercut the Case for Higher Aliso Canyon Inventory URL: https://www.calregulatory.com/opponents-say-socalgass-outage-reports-undercut-the-case-for-higher-aliso-canyon-inventory/ Last updated: 2026-06-04T15:17:40.000Z Sierra Club and Cal Advocates filed June 1 comments challenging SoCalGas's case for higher Aliso Canyon inventory, responding to [external](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K451/606451664.PDF?ref=calregulatory.com) and [internal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K861/606861012.PDF?ref=calregulatory.com) outage reports that **ALJ Ormond** directed the utility to file in [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com). Recall that the outage reports were meant to show whether upstream weather events, pipeline outages, and internal system constraints justify raising Aliso Canyon's maximum inventory level. _This post is for paying subscribers only._ ### June 11 CPUC Voting Meeting Preview: SoCalGas Under Continued Safety Scrutiny; SDG&E's $267.9M Battery Deal Nears Approval URL: https://www.calregulatory.com/june-11-cpuc-voting-meeting-preview-socalgas-under-continued-safety-scrutiny-sdg-es-267-9m-battery-deal-nears-approval/ Last updated: 2026-06-03T12:30:17.000Z Next week's [CPUC voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M608/K056/608056639.pdf?ref=calregulatory.com) covers a fair amount of ground: SoCalGas's safety culture oversight, SDG&E’s utility-owned storage acquisition, CTA complaint-cost allocation, shared renewables implementation (sans expected funding), and updated ReMAT avoided-cost prices. --- ### **UTILITY SAFETY CULTURE** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K435/606435795.PDF?ref=calregulatory.com) resolves Phase 2 of [I.19-06-014](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M306/K870/306870841.PDF?ref=calregulatory.com), the CPUC's seven-year examination of whether safety failures at SoCalGas (beginning with the [2015 Aliso Canyon leak](https://en.wikipedia.org/wiki/Aliso%5FCanyon%5Fgas%5Fleak?ref=calregulatory.com)) stem from organizational culture and governance deficiencies. The PD accepts SoCalGas's revised Safety Culture Improvement Plan as a credible framework for implementation but does not endorse the effectiveness of any specific intervention. SoCalGas is permitted to proceed. The PD does not declare the company "fixed." In its next quarterly compliance report, SoCalGas must: - Explicitly incorporate security into its definition of comprehensive safety; - Strengthen contractor integration with metrics and oversight comparable to employee-focused efforts; - Expand its corrective action program to capture public and non-occupational safety concerns; and - Demonstrate that "Learning Team" sessions on resource allocation (staffing vacancies, leak response timelines, informal downgrade practices) continue until no new insights emerge. Implementation-level reporting is required throughout: timelines, milestones, budgets, and intervention-specific metrics. Quarterly compliance reporting will continue through the next safety culture assessment, which must commence no later than **August 2029**. The PD also creates a Tier 2 Advice Letter pathway, which delegates authority to the CPUC's Safety Policy Division to approve Safety Culture Improvement Plan revisions when interventions fall short, bypassing a full Commission vote. The PD finds that SoCalGas's parent company, Sempra, has provided minimal participation and has not met expectations set in prior decisions. Going forward, SoCalGas must maintain a consolidated plan tracking Sempra's contributions and demonstrate through quarterly reporting how parent-level governance responds to assessment findings originally directed at Sempra. CPUC staff retains authority to engage SoCalGas's board directly as implementation evolves. Shareholders remain financially responsible. SoCalGas has already incurred more than **$5 million** in unrecoverable Safety Culture Improvement Plan costs, and the CPUC again rejects ratepayer recovery for safety culture remediation. The restriction extends through the next assessment cycle, leaving future implementation and plan revisions to shareholders. **INSTANT ANALYSIS:** The practical effect of this PD is a long-duration compliance obligation with no ratepayer cost recovery before the next assessment cycle and staff-controlled checkpoints at every quarterly interval. SoCalGas receives permission to implement, not credit for having solved anything. The finding that Sempra's participation is inadequate is now on the record, and future independent assessments are explicitly recommended to evaluate Sempra's influence. --- ### **UTILITY-OWNED STORAGE** [Draft Resolution E-5467](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K399/606399033.PDF?ref=calregulatory.com) approves SDG&E's acquisition of the 119 MW [Westside Canal Phase 2a battery storage project](https://ceqanet.lci.ca.gov/2020040122/4?ref=calregulatory.com) from an [RWE](https://www.rwe.com/en/?ref=calregulatory.com) subsidiary through a Membership Interest Purchase Agreement, plus a 10-year operations and maintenance agreement. The Imperial Valley project came online in December 2024 and is intended to support 2026 and 2027 summer reliability under the Effective Planning Reserve Margin framework. The total estimated cost is **$267.9 million**, recoverable through the Cost Allocation Mechanism. **INSTANT ANALYSIS**: The project already exists, already dispatches in CAISO markets, and RWE already sells short-term resource adequacy from it on a merchant basis. SDG&E's purchase adds no new physical capacity. Draft Resolution E-5467 approves it anyway by finding the project incremental on a technicality (it is not on the baseline resource list) and authorizes full CAM cost recovery across all benefitting customers. The cost-recovery question extends beyond this proceeding. Three protesters argued SDG&E had already hit the top of its 120-220 MW Effective Planning Reserve Margin procurement target and that CAM recovery should be capped accordingly. Energy Division rejects that, reading the Effective Planning Reserve Margin framework as a floor investor-owned utilities may exceed. The range is not a ceiling. The deliverability problem has no real answer in this draft resolution. The project has interim status for 2025 and 2026 but will not achieve full capacity deliverability until transmission upgrades are completed, potentially in 2034\. Quarterly reporting to the CAM Procurement Review Group creates visibility, not protection. If interim deliverability lapses, customers carry the full cost of a $267.9 million utility-owned asset that cannot perform the reliability function used to justify its approval. --- ### CORE TRANSPORT AGENTS [Draft Resolution G-3621](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K217/606217134.PDF?ref=calregulatory.com) reaffirms the annual fee structure for California Core Transport Agents, the non-utility gas suppliers serving residential and small commercial customers. The draft resolution retains the framework from a previous resolution ([Resolution G-3597](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M509/K545/509545115.PDF?ref=calregulatory.com), 2023) without introducing new fee design. Each registered CTA pays a **$5,000** base fee, with variable fees assessed only against companies that generated complaints or faced unauthorized enrollment investigations and enforcement activity in 2025. The CPUC grounds the structure in [Senate Bill 656](https://www.leginfo.ca.gov/pub/13-14/bill/sen/sb%5F0651-0700/sb%5F656%5Fcfa%5F20130628%5F170107%5Fasm%5Fcomm.html?ref=calregulatory.com) and a 2018 decision ([D.18-02-002](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M209/K856/209856533.pdf?ref=calregulatory.com)), which expanded CTA oversight after years of deregulated gas procurement. With 39 registered CTAs and 36 active participants, the CPUC argues the market is mature enough that higher fees pose no meaningful barrier to entry. Fixed administrative costs rose **34%** in 2025 but remain within the tolerance band established in G-3597, so the base fee remains at $5,000\. The more notable development is complaint volume, which surged **75%** over the prior year. Unauthorized enrollment complaints reviewed by the CPUC's Utility Enforcement Branch rose nearly as much, even as formal enforcement actions fell by more than half. The complaint surge produces wide fee dispersion. [Wave Energy](https://waveenergyservices.com/?ref=calregulatory.com) faces the largest total assessment at approximately $206,000\. [SFE Energy](https://www.sfeenergy.com/california/?ref=calregulatory.com) exceeds $118,000\. BP Energy, Shell, and Calpine each pay only the $5,000 base fee, having generated no complaints or enforcement activity. **INSTANT ANALYSIS:** This draft resolution further embeds complaint-driven cost allocation as the basis of California's retail gas oversight regime. CTAs with persistent enrollment and marketing problems are funding a growing share of CPUC enforcement infrastructure, while operators with clean complaint records pay only the administrative floor. The draft resolution does not propose market reforms or stricter registration standards, but the staffing expansion suggests that the CPUC expects elevated oversight demands to persist. --- ### SHARED RENEWABLES A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536932.PDF?ref=calregulatory.com) implements California's Shared Renewables Portfolio without the funding that was intended to support it. Federal Solar for All money is gone, terminated by the Environmental Protection Agency in August 2025\. A **$33 million** state appropriation reverted to the General Fund in June 2025\. The program will proceed anyway. The PD ties the new Community Renewable Energy tariff to the [Renewable Market Adjusting Tariff program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com). Proposals for capacity adders, expanded project sizes, time-of-delivery adjustments, and above-avoided-cost compensation were all rejected as inconsistent with the Public Utilities Code. Nonparticipating customers will not pay above avoided costs. **INSTANT ANALYSIS:** The basic concept of this program survives. The economics that would have driven participation do not. --- ### ReMAT PRICE UPDATE [Draft Resolution E-547](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K263/606263846.PDF?ref=calregulatory.com) updates fixed avoided-cost rates for California's [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), a feed-in tariff for small renewable generators at (or below) **3 MW**. PG&E, SCE, and SDG&E would have 30 days from the effective date to amend their tariffs. The 2026 rates reflect a weighted average of Renewable Portfolio Standard contracts executed 2020–2025 for projects 20 MW or smaller. The 43-contract pricing dataset is heavily weighted toward CCA-procured solar PV in Los Angeles County, including a substantial [Prologis](https://www.prologis.com/?ref=calregulatory.com) rooftop portfolio. The baseload category draws almost entirely on Nevada geothermal. A confidential geothermal contract executed in 2025 is the only new baseload entry (the most plausible driver of the $16.37 increase, though the draft resolution does not say so explicitly). As of February 2026, the program totals **65 contracts** and approximately **112 MW** since inception. **INSTANT ANALYSIS:** The baseload rate eclipsing **$92/MWh** confirms that firm renewable capacity (geothermal above all) commands a widening premium over intermittent resources in California's small-scale procurement market. The near-flat peaking price tells the opposite story: CCA solar has saturated that category to the point where new contracts move the weighted average almost nothing. CCAs now dominate the RPS contract dataset that sets these rates. The avoided-cost benchmark for small QFs is increasingly a CCA-derived number, not a utility one (a shift with long-term implications for how ReMAT prices reflect actual utility procurement costs). ### The CPUC's RA Reset: UCAP, Storage Penalties, EO Limits, and the End of Paper Capacity URL: https://www.calregulatory.com/the-cpucs-ra-reckoning-ucap-storage-penalties-eo-limits-and-the-end-of-paper-capacity/ Last updated: 2026-06-24T19:09:41.000Z The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K058/608058096.PDF?ref=calregulatory.com) in R.25-10-003, adopting 2027-2029 Local Capacity Requirements, 2027 Flexible Capacity Requirements, and a set of Slice-of-Day RA reforms that change what it means to hold RA capacity in California. The earliest the CPUC will consider this item is **July 2**. Comments are due **June 22**. --- ### **LOCAL & FLEXIBLE CAPACITY** The PD adopts the CAISO's recommended Local Capacity Requirements: - **23,618 MW** for 2027; - **24,545 MW** for 2028; and - **25,480 MW** for 2029\. The LA Basin climbs from 6,823 MW to **7,721 MW** over the three years. Seven of 10 local areas carry the CAISO’s resource-deficiency notation, meaning resource shortfalls or storage charging constraints could cause load shed after a first contingency at summer peak. The Western LA Basin is already hitting charging limits; the Eastern LA Basin hit them in 2025\. The PD adopts the 2027 Flexible Capacity Requirements without modification, peaking in November at **30,058 MW** system-wide and **28,448 MW** for CPUC-jurisdictional areas. ### **UNFORCED CAPACITY** Effective for the 2028 RA compliance year, dispatchable thermal, nuclear, geothermal, and non-hybrid storage resources will have their accreditation reduced by their Equivalent Forced Outage Rate during RA Measurement Hours. The formula is ***UCAP = (1 − EFORd) × Pmax***, applied separately for summer and non-summer seasons, using the best three of the prior four calendar years of CAISO outage data for each resource individually. New resources receive class-average EFORd values until unit-specific history accumulates. Thermal generators get weather-normalized ambient-temperature derates using NOAA 30-year typical weather-year data, preventing an anomalous hot year from permanently depressing a unit's accreditation value. Preliminary UCAP values will be published in early 2027 for party comment, with final values distributed in September 2027, leaving load-serving entities and counterparties about 15 months to assess what their contracted resources will be worth before the first compliance year opens. The PD defers six implementation questions to Track 2: - Hybrid resource methodology; - The Must-Offer Obligation basis once UCAP replaces Qualifying Capacity; - How EFORd will be calculated for the energy component of storage resources; - Fifth-hour foldback treatment; - Flexible RA interaction; and - Slice-of-Day template integration. None of those open items will delay the 2028 effective date. ### **STORAGE ACCREDITATION** The PD makes two distinct changes to storage accreditation, both effective immediately. The storage QC calculation is revised to address foldback: rather than treating Pmax as a constant, the new formula uses **MAX\_CONT\_ENERGY\_LIMIT** minus **MIN\_CONT\_ENERGY\_LIMIT** from the CAISO Master File, divided by four, constrained by the Point of Interconnection. The Master Resource Database's Maximum Continuous Energy default field is also revised to use that same calculation, though that is an administrative database change, not a modification to the accreditation formula itself. On energy-only resources, the PD issues three directives. - EO resources may not count toward RA capacity requirements (the PD rejects that proposal outright, as EO resources have never been studied for deliverability during stressed system conditions). - Whether standalone EO resources may count toward storage charging sufficiency is deferred pending CAISO's 2026–2027 Transmission Planning Process study, with preliminary results expected in November 2026\. - What the PD does adopt, beginning in 2027, is a same-Point of Interconnection rule: excess energy from an EO resource co-located with deliverable storage at the same point of interconnection may count toward charging sufficiency after subtracting the paired storage resource's own energy sufficiency need. ### **LONG-DURATION ENERGY STORAGE** LDES is defined as any storage resource capable of discharging at maximum capacity for at least eight continuous hours. Effective for 2027, load-serving entities may count LDES capacity across the full 24-hour Slice-of-Day period using a Forward Charge Period multiplier ranging from **2x** (eight-hour resources) to **8x** (72-hour-plus resources), grounded in the existing worst-day framework. No assumed initial state of charge is adopted. Closed-loop pumped storage hydropower receives LDES treatment; open-loop PSH is deferred. ### CHARGING SUFFICIENCY PENALTY AND DR The PD also closes an enforcement gap in the storage charging rules. Beginning in 2027, a load-serving entity with an MWh charging sufficiency shortfall would have that shortfall converted into a flat 24-hour MW adder. The adder would be applied to each hourly position, and the largest resulting hourly deficiency would determine the RA penalty. For Demand Response, the PD adopts a near-term correction to a Slice-of-Day misalignment. The CPUC will provide the CAISO with three Demand Response values: - The maximum showing value; - The peak showing value; and - The average hourly MW value during event hours within the Availability Assessment Hour window. Any non-event hour would be excluded from that average. ### **REJECTIONS & DEFERRALS** The PD rejects hourly load obligation trading. Energy Division's[ Transactability Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960179.PDF?ref=calregulatory.com) found no demonstrated inability for load-serving entities to meet Slice-of-Day obligations under existing mechanisms. Future proposals must prove a problem exists and clear five additional conditions. The PD does not adopt broader exceedance methodology changes; only a transmission-event protection rule for non-dispatchable resources takes effect in 2027. ### **INSTANT ANALYSIS** This PD prices operational performance into RA value. A thermal unit that trips frequently will be worth less. Storage that folds back before four hours will be credited accordingly. A load-serving entity that cannot cover charging sufficiency will now face a penalty with MW consequences. The six open UCAP implementation questions deferred to Track 2 are not minor. Hybrid resource methodology, Must-Offer Obligation basis, and Slice-of-Day template integration all affect how UCAP operates in compliance practice, and they remain unsettled 15 months before the first UCAP compliance year opens. The EO directive comes in three distinct parts. Anyone negotiating EO contracts should track all three components, particularly the Transmission Planning Process timeline. The LDES multiplier framework gives eight-hour-plus storage a formal RA accreditation pathway for the first time. That's important at a time when IRP procurement orders are already pushing toward longer-duration resources and developers have been contracting without a clear counting rule. The transactability rejection closes the question for now, but the Commission is explicit about what a future proposal would need to prove. If 2026 or 2027 Slice-of-Day compliance data show that load-serving entities cannot meet hourly obligations under existing mechanisms, CalCCA will be back with a record built around those findings. --- **Attachments:** - [Appendix A: Summary of Load Forecast Process Under Slice-of-Day RA Framework](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K058/608058317.PDF?ref=calregulatory.com) - [Appendix B: Unforced Capacity Framework](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M608/K058/608058097.PDF?ref=calregulatory.com) ### The Energization Quagmire: Bad Data and Big Backlogs URL: https://www.calregulatory.com/the-energization-quagmire-bad-data-and-big-backlogs/ Last updated: 2026-06-02T05:17:13.000Z A new [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K627/607627593.PDF?ref=calregulatory.com) in its Timely Energization docket directs PG&E, SCE, and SDG&E to respond to [questions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K583/607583175.PDF?ref=calregulatory.com) arising from [Guidehouse's review](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K644/607644153.PDF?ref=calregulatory.com) of the utilities' September 2025 Biannual Energization Reports. All parties may answer the same questions. ### **THE** KEY FINDING [Guidehouse](https://guidehouse.com/?ref=calregulatory.com) determined that the September 2025 data are insufficient to assess utility compliance with the energization targets established by the CPUC in a 2024 decision ([D.24-09-020](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K806/540806654.PDF?ref=calregulatory.com)). The data are directional only. ### **WHY THE DATA FAILED** D.24-09-020 established [enforceable average and maximum energization targets](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K809/540809275.PDF?ref=calregulatory.com), an eight-step framework, and a twice-yearly reporting obligation covering tariff projects under Rules 15, 16, 29, and 45, plus main panel upgrades. The September 2025 reports cover projects with complete applications from January 31, 2023 through June 30, 2025, a window that straddles the decision's September 2024 issuance date, mixing pre- and post-decision projects throughout. Each utility's tracking systems failed in a distinct way. - PG&E is still integrating systems and cannot reliably track Step 6 (IOU Site Readiness) or Step 8 (Energization); only 6.3% and 47% of completed tariff projects, respectively, have start or end dates for those steps. PG&E did, however, produce the most complete dataset overall, including a methodology for allocating overlapping utility and customer time and outlier flags on individual project records. (***PG&E's report is available*** [***here***](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K104/582104343.PDF?ref=calregulatory.com)***.***) - SCE provided complete step-date data across all eight steps (the only utility to do so) but its systems cannot separate IOU-controlled time from customer or third-party time, which means SCE cannot compare its reported timelines to the CPUC's utility-controlled targets at all. (***SCE's report is available*** [***here***](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K082/582082543.PDF?ref=calregulatory.com)*.*) - SDG&E struggled with multiple steps, could not track utility-controlled time separately from customer time, and cannot provide reliable end-to-end cycle data. SDG&E also cited funding constraints as a barrier to system improvements, noting that many required initiatives were not included in its most recent general rate case. (***SDG&E's report is available*** [***here***](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K028/582028396.PDF?ref=calregulatory.com)***.***) Guidehouse assessed data sufficiency against two thresholds: - 95% availability for compliance data points (tariff type, IOU-controlled steps, aggregate IOU-controlled and end-to-end timelines); and - 75% for contextual data points (capacity, costs, upstream triggers, delay causes). None of the three utilities met those thresholds. Approximately one-third of required data fields were missing for more than 75% of projects across all three IOUs. Beyond the timeline data failures, Guidehouse found that cost data at the time of energization is unreconciled for six to 12 months after project completion; that outlier treatment was inconsistent across all three IOUs; and that none of the utilities could reliably identify when a tariff project triggered an upstream capacity upgrade. ### **WHAT THE RULING IS BUILDING TOWARD** The ruling's [questions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K583/607583175.PDF?ref=calregulatory.com) cover the full range of problems Guidehouse identified. The CPUC is asking utilities and parties to address: - How IOU systems will be upgraded and when; - How overlapping IOU and customer time should be allocated; - How step start and end dates should be defined where no clear energization or meter-set date exists; - How upstream capacity triggers should be tracked; - How cost reconciliation should be standardized; - What data fields the annual [Section 935](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-4/article-14-5/section-935/?ref=calregulatory.com) staffing reports should contain, including job classifications, staffing levels, and apprentice pipeline information; - How staffing levels should demonstrate a relationship to energization timeline performance; and - Whether the proposed data sufficiency thresholds, outlier definitions, and data template modifications should be adopted. The ruling is a step toward deciding what data will count when the CPUC evaluates energization performance, and toward determining what happens when a utility's data do not meet the threshold required to support that evaluation. ### **INSTANT ANALYSIS** The CPUC cannot yet say whether PG&E, SCE, or SDG&E are meeting the energization targets adopted in D.24-09-020\. But Guidehouse's review is also a roadmap for making the next reporting cycles enforceable. The risk for the utilities is that bad data may become its own regulatory problem. The ruling's [questions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K583/607583175.PDF?ref=calregulatory.com) ask whether utilities that fail Guidehouse's proposed sufficiency thresholds should be required to file additional reporting on their energization backlogs. Whichever parties shape the definitions of utility-controlled time, customer delay, upstream capacity triggers, actual project costs, and outliers will shape how future energization performance is judged. ### SATURDAY BRIEFING: SB 1221 Work Advances as Angeles Link and Southern System Risks Remain Unresolved URL: https://www.calregulatory.com/saturday-briefing-sb-1221-work-advances-as-angeles-link-and-southern-system-risks-remain-unresolved/ Last updated: 2026-07-01T23:29:56.000Z Today's briefing looks at: - A PD establishing the application process for Senate Bill 1221 decarbonization pilots; - A new ruling in SoCalGas's Phase 1 Angeles Link cost-recovery proceeding; - SDG&E's Palomar Decarbonization Demonstration Project; and - More details from SoCalGas's May 15 Annual Customer Forum. --- ### LONG-TERM GAS PLANNING/DECARBONIZATION **Commissioner Karen Douglas** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K364/607364712.PDF?ref=calregulatory.com) establishing the application process for [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com) neighborhood decarbonization pilots. The PD authorizes gas corporations to seek approval for voluntary projects that replace gas service with zero-emission alternatives and enable decommissioning of the underlying gas infrastructure. - The program is capped at 30 pilots statewide. Project slots are allocated primarily between PG&E and SoCalGas/SDG&E by 2024 gas demand (seven each per round across the first two rounds) with one slot reserved for Southwest Gas and one for the smaller CPUC-regulated gas corporations, each usable in either of the first two rounds. - Application deadlines are **December 15, 2026**, **December 15, 2027**, and, per the ordering paragraph, **July 1, 2028**, if slots remain. (*Note: The summary section of the PD states *June 1*, 2028.*) - Each application must demonstrate, via net present value using the applicant's [WACC](https://www.investopedia.com/terms/w/wacc.asp?ref=calregulatory.com) as the discount rate, that avoided gas infrastructure costs exceed the cost of the zero-emission alternative. The PD requires four separate cost-effectiveness calculations varying the inclusion of non-ratepayer funding and administrative costs; the governing test excludes costs funded by non-ratepayer sources and excludes administrative and outreach costs. Applications must also: - Account for electric infrastructure upgrade costs; - Document outreach and stakeholder coordination; - Obtain non-binding expressions of interest from at least **67%** of property owners before filing; - Obtain binding notarized consent from that same threshold after Commission approval and before building remediation, appliance removal, or implementation spending begins; and - Show that substitute service is affordable and adequate, particularly for low-income customers. Required application contents include: - Project maps; - Customer counts; - Bill-impact estimates at specified percentiles; - Gas and electric infrastructure analyses; - Appliance and remediation offerings; - GHG emissions forecasts using the Avoided Cost Calculator; - Labor considerations; and - Cost-recovery proposals. Behind-the-meter costs must be expensed rather than capitalized; utilities may not earn their authorized rate of return on BTM costs and may propose amortization periods of up to ten years. Comments are due **June 18**. The earliest the CPUC will consider this item is **July 2**. **INSTANT ANALYSIS:** This is the CPUC's first bona-fide attempt to convert SB 1221 from gas-transition policy into a working project pipeline, and the PD is designed to make that conversion difficult. A pilot must prove that avoiding gas repair, replacement, or continued operation pays for the zero-emission alternative, using the utility's own cost of capital, excluding costs funded by non-ratepayer sources and excluding administrative and outreach costs from the governing calculation. That points to a limited candidate set: areas with expensive near-term gas work, limited electric upgrade needs, and a customer mix that converts without severe bill or remediation exposure. The application process (rather than advice letters) keeps every pilot subject to full Commission and intervenor scrutiny, which is where cost allocation, bill-impact assumptions, and electric-grid attribution get contested. The 67% consent requirement adds a second filter: utilities absorb substantial outreach cost before CPUC approval, then must obtain binding notarized consent before building remediation, appliance removal, or implementation spending begins. Projects with weak community support or complicated master-metered properties may not survive that sequence. Data collection, reporting, evaluation, and the shareholder incentive mechanics are all deferred to Track 4\. SB 1221's core rationale is generating lessons about whether targeted gas retirement can work as a ratepayer-beneficial alternative to continued infrastructure spending. Without evaluation criteria in place before pilots launch, that test is harder to interpret when results come in. If adopted, this PD will establish the first formal test of whether neighborhood-scale gas retirement can work within existing ratemaking discipline. --- ### ANGELES LINK/HYDROGEN A May 29 [ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K844/607844129.PDF?ref=calregulatory.com) asks parties in SoCalGas’s Angeles Link Phase 1 cost-recovery proceeding to address several questions in light of the Commission’s April 30 Phase 2A denial ([D.26-04-034](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com)): - Whether it is just and reasonable for ratepayers, or a subset of ratepayers, to bear Phase 1 costs, and if so, which ratepayers benefited and when recovery should occur; - Whether the CPUC must reach jurisdiction over Angeles Link to resolve the proceeding or can dispose of it on cost-recovery grounds alone; - What schedule should govern the remainder of the case, including whether evidentiary hearings are necessary; and - Whether any other determinations from D.26-04-034 should be considered in the Phase 1 proceeding. Responses are due **June 30**, with replies due **July 16**. **INSTANT ANALYSIS:** The CPUC has already rejected ratepayer recovery for the next stage of Angeles Link work where SoCalGas had not shown a sufficient ratepayer benefit. Phase 1 costs now face a related test, and SoCalGas has less to point to: Phase 1 was planning work, not construction, not permitting, and not anything a ratepayer can identify as a delivered project benefit. The jurisdiction question may be the more consequential one. If the CPUC can resolve this proceeding on cost-recovery grounds alone, it never has to rule on whether Angeles Link is a jurisdictional project, which means that question stays open, unresolved, and available to relitigate later. That is not necessarily bad for SoCalGas, but it forecloses the jurisdictional clarity the company has been seeking since 2022. In short, Phase 1 recovery is in serious trouble, the schedule is undefined, and the CPUC has given itself every offramp it needs to deny recovery without touching the harder jurisdictional question. --- ### HYDROGEN/DECARBONIZATION **Commissioner Christine Harada** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K627/607627608.PDF?ref=calregulatory.com) addressing SDG&E's [standalone request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904936.PDF?ref=calregulatory.com) to recover costs for the Palomar Decarbonization Demonstration Project. The project is an integrated hydrogen system at the [Palomar Energy Center](https://www.energy.ca.gov/powerplant/combined-cycle/palomar-energy-project?ref=calregulatory.com) involving on-site hydrogen production, storage, blending in one gas turbine, and hydrogen vehicle fueling. Note that the CPUC [previously denied](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com) SDG&E's capital cost recovery request for the project in the utility's 2024 GRC, finding the record lacked enough evidence to show ratepayer value. SDG&E now seeks recovery of **$17.4 million** in capital costs, **$2.6 million** in O&M costs through 2036, and an estimated **$31.1 million** revenue requirement. The scoped issues fall into three clusters. The first is evidentiary: whether the project produces operational, safety, emissions, decarbonization, and scalability findings that are unique from other research and pilots. The second is financial: total costs, revenue requirement, federal tax credits, public funding, and cost allocation between bundled and unbundled customers. The third is the bottom line: whether ratepayer cost is just and reasonable relative to project value. Intervenor testimony is due **July 31**. [Final CPUC Meeting of 2025; Palomar Decarbonization ProjectThis edition highlights consequential proposed decisions on cost of capital, long-term gas planning, and wildfire cost recovery.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Dec-16-2025--4--ea56a90eb2760d9ba5b8a2cdc51884613d709208bce61e82c24a69e82b6b7212.png)](https://www.calregulatory.com/wednesday-aggregate-5/) **INSTANT ANALYSIS:** The scoping memo puts SDG&E back in the same bind it faced in the GRC: the utility has to show that Palomar hydrogen is worth ratepayer money, not merely that it is innovative or aligned with decarbonization policy. That is a harder showing than it may appear. The CPUC already rejected the project once because SDG&E did not prove ratepayer value. This standalone application gives SDG&E another chance, but the scoped issues press directly on the weak points: public interest, unique operational learning, emissions value, scalability, public funding, tax credits, and allocation between bundled and unbundled customers. If SDG&E recovers costs through distribution rates, the project could reach a broad customer base even though the hydrogen system is located at a generation facility and appears tied to specific operational use cases. If recovery runs through generation rates, the question becomes whether unbundled customers should pay and whether the project produces benefits extending beyond bundled generation service. The ruling also keeps the dismissal argument alive in substance, even if the application was not thrown out at the scoping stage. Parties argued that the current filing contains no new facts or evidence beyond what SDG&E presented in the GRC, and the Commission made that the first scoped issue. That frames the case around evidentiary improvement, not hydrogen policy enthusiasm. --- ### SOCALGAS CUSTOMER FORUM SoCalGas filed its [2026 Post-Forum Report](https://www.socalgasenvoy.com/ebb/attachments/1780092137057%5F2026%5FPost-Forum%5FReport%5FDRAFT.pdf?ref=calregulatory.com) on System Reliability Issues following its May 15 customer forum, which drew approximately 60 participants. The forum covered: - Operational Flow Orders; - Minimum flow requirements; - System reliability transactions; - Scheduled quantity trades; - ENVOY updates; - Cost allocation; - Operational reliability developments; and - The Aliso Canyon biennial assessment. No customer questions or proposals were submitted before the meeting, and most agenda topics drew no questions. Substantive discussion was limited to system reliability transactions. - Shell asked about Otay Mesa pricing during a September 3, 2025 Southern System Reliability request; SoCalGas said the price spike was addressed in its Annual Compliance Review filing, Advice Letter 6558-G. - Shell also asked about the Energía Costa Azul LNG Project and the CPUC-rejected [North-South, Adelanto-to-Moreno pipeline](https://ia.cpuc.ca.gov/environment/info/ene/n-s/northsouth.html?ref=calregulatory.com) funding request; SoCalGas said the CPUC will not revisit ECA LNG impacts until operational data shows effects on Southern System customers. - ConocoPhillips asked whether renewable growth would reduce Southern System Reliability requests; SoCalGas said renewable generation has already affected system demand. - Jain Global asked whether baseload purchases would resume; SoCalGas said baseload transactions are not feasible under current Rule 41 Safe Harbor requirements and that it has requested changes in its pending ACR advice letter, with CPUC disposition pending. For more detail, see CRI's same-day forum summary from May 15: [What 0.5 Bcf/d from Costa Azul Means for ReliabilitySoCalGas hosted its 2026 Annual Customer Forum.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/zone-20b72226d44383aaa69e8aa564b4e6415d0a99a59246d886069f6cf8b9425566.png)](https://www.calregulatory.com/socalgas-customer-forum-185-high-ofos-no-north-south-expansion-what-0-5-bcf-d-from-costa-azul-means-for-reliability/) **INSTANT ANALYSIS:** The Southern System reliability problem has not gone away. Shell's question about the September 2025 Otay Mesa price spike points to the same crucial exposure: when Southern System constraints emerge, customers face reliability actions whose costs and mechanics can become consequential fast. SoCalGas's answer routes the issue into the Annual Compliance Review, where the CPUC evaluates reasonableness after the fact. The ECA LNG and Adelanto-to-Moreno exchange merits consideration. SoCalGas is indicating that the CPUC will not revisit the rejected pipeline funding request unless operational data shows actual harm to Southern System customers. That leaves the utility in a reactive position: it may need evidence of system failure before it can rebuild the case for infrastructure relief. By the time the data exists, customers will have already experienced the consequences. The baseload purchase answer may be the most actionable disclosure. SoCalGas has already asked the CPUC to modify Rule 41 Safe Harbor requirements in its pending Annual Compliance Review advice letter. Approval will expand the reliability toolkit. Denial will keep Southern System reliability management dependent on shorter-term transactions and after-the-fact reasonableness review. ### SCE Update: June 1 Rate Changes and RAMP Submission URL: https://www.calregulatory.com/sce-update-june-1-rate-changes-and-ramp-submission/ Last updated: 2026-06-01T04:34:11.000Z Today's briefing looks at two rate-related filings from Southern California Edison. ### JUNE 1, 2026 RATES SCE filed Advice Letter 5829-E to implement a **June 1** consolidated revenue requirement and rate update reflecting CPUC and FERC approvals, balancing account true-ups, wildfire cost changes, and the removal of expiring charges. SCE's authorized revenue requirement declines by **$26.4 million** relative to January 1 levels, producing an approximately **0.1%** system-average rate decrease for bundled customers. A typical non-CARE residential customer using 500 kWh per month will see an estimated $0.15 monthly decrease; CARE customers will see a $0.13 reduction. The largest upward driver is a **$380.7 million** distribution revenue increase tied to SCE's wildfire self-insurance program. After SCE entered into 2025 wildfire settlement agreements expected to exceed **$1 billion**, it triggered an adjustment mechanism that raises its 2026 self-insurance revenue requirement from $274 million currently in rates to **$650 million**. This constitutesan increase of **$376 million** before Franchise Fees and Uncollectibles. SCE will amortize the increase over 12 months to moderate rate impacts. Offsetting that increase are: - An **$84.5 million** reduction in transmission balancing account recovery reflecting an overcollection in the Transmission Access Charge Balancing Account Adjustment; - A **$73.4 million** credit from the 2023 ERRA review; - A **$240.3 million** reduction in energy efficiency funding requirements; and - The expiration of **$34.7 million** in [Thomas Fire](https://en.wikipedia.org/wiki/Thomas%5FFire?ref=calregulatory.com) Catastrophic Event Memorandum Account recovery rolling off rates after **May 31**. Smaller items include a **$15.4 million** increase for the [Electric Program Investment Charge](https://www.energy.ca.gov/programs-and-topics/programs/electric-program-investment-charge-epic-program?ref=calregulatory.com) RD&D and renewables program, **$6.8 million** for the 2026 Flex Alert paid media campaign, and **$3.6 million** annually for SCE's tariff on-bill financing pilot for residential clean-energy upgrades. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/impacts.png) **INSTANT ANALYSIS:** Beneath the near-flat system average sits a major redistribution of cost drivers: wildfire self-insurance rises by about $381 million after the utility triggered an approved adjustment mechanism tied to 2025 wildfire settlements. Meanwhile, offsets from transmission overcollections, ERRA credits, lower energy-efficiency funding, and the expiration of Thomas Fire recovery keep bill impacts modest. For large customers tracking distribution cost growth and wildfire exposure, the filing is another reminder that California utility rates remain under steady upward pressure even when bill impacts appear benign. The TACBAA reduction shows how balancing account timing can temporarily absorb rate pressure without altering the broader cost trajectory. --- ### RISK ASSESSMENT/MITIGATION Edison filed its [2026 Risk Assessment Mitigation Phase application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K868/606868101.PDF?ref=calregulatory.com) at the CPUC as the safety-risk foundation for its Test Year 2029 General Rate Case. The company identifies 10 RAMP risks: - Wildfire and Public Safety Power Shutoffs; - Overhead Equipment Failure; - Underground Equipment Failure; - Seismic; - Public Safety Risk Not Attributable to Asset Failure; - Major Physical Security Incident; - Cyber Attack; - Hydro Dam Safety; - Employee Safety; and - Contractor Safety. The January 2025 Southern California fires dominate SCE's case for planning around tail-risk events beyond historical experience. SCE developed an enhanced Wildfire Integrated Model and a climate-informed variant using data underlying the forthcoming California Fifth Climate Change Assessment, which has not yet been released. Grid hardening runs through a Benefit-Cost Ratio screen at the circuit level. SCE selects either covered conductor or targeted undergrounding based on whichever yields the higher BCR, provided at least one exceeds 1.0\. Where neither clears that threshold, no proactive hardening is proposed; vegetation management, inspections, and PSPS continue, but no grid investment moves forward. [Rapid Earth Fault Current Limiters](https://www.sce.com/sites/default/files/AEM/Supporting%20Documents/2023-2025/Rapid%20Earth%20Fault%20Current%20Limiter%20%28REFCL%29%20Projects%20at%20Southern%20California%20Edison.pdf?ref=calregulatory.com) (REFCLs), substation-based protection devices that suppress ground-fault current when an energized conductor contacts the ground, are prioritized separately based on execution feasibility at circuits where covered conductor hardening is already prevalent. Covered conductor raises wind-speed thresholds but does not remove shutoff risk when winds exceed them. SCE argues Benefit-Cost Ratios are one input, not the determinant; operational constraints, feasibility, and execution limits remain in the equation. **INSTANT ANALYSIS:** The 2026 RAMP is a capital intentions map. It previews the size and geography of SCE's 2029 wildfire hardening requests. The Benefit-Cost Ratio is where things may get contentious. SCE proposes no proactive grid hardening on circuits where the benefit-cost ratio falls below 1.0, leaving vegetation management, inspections, and PSPS as the remaining mitigation tools in those areas. Intervenors will argue that communities on sub-1.0 circuits are being left without physical protection because of a cost screen, not because the risk is low. If that argument gains traction, it may force SCE to revisit its 2029 hardening scope before its GRC is filed. SCE's climate-informed wildfire modeling carries similar vulnerabilities. Rather than relying on historical fire data, SCE is incorporating forward-looking climate projections into the risk calculations that drive its entire mitigation prioritization. The CPUC's safety staff has not yet evaluated that methodology. A successful challenge to the underlying assumptions would not just affect the climate modeling, it would move the risk scores, and with them, the hardening investments SCE plans to ask ratepayers to fund in 2029. ### PG&E Update: Rule 30 Cost-Shift Fight, Capital Structure Denial URL: https://www.calregulatory.com/pg-e-update-data-center-cost-shift-fight-capital-structure-denial/ Last updated: 2026-06-01T04:33:05.000Z In today's PG&E-focused briefing: - Parties submit reply briefs in the CPUC's Rule 30 docket; - A new PD denies PG&E's request to exclude approximately **$2.6 billion** in wildfire liabilities and a state loan from its capital structure calculations; and - A proposed settlement resolves all disputed issues in PG&E's [2024 ERRA compliance](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K607/557607577.PDF?ref=calregulatory.com) proceeding. --- ### TRANSMISSION-LEVEL INTERCONNECTION Parties in PG&E's Rule 30 proceeding filed reply briefs on May 22, deepening the dispute over who bears the cost of transmission upgrades required to serve data centers and other large new loads. In the same week, PG&E made a coordinated [ex parte pitch](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K627/607627861.PDF?ref=calregulatory.com) to all five commissioner offices. The pitch was a summary of PG&E's position: Type 4 Transmission Network Upgrade costs should continue flowing through the Transmission Access Charge rather than being assigned upfront to individual customers. In PG&E's view, the [Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K498/586498115.PDF?ref=calregulatory.com) **75%** revenue refund approach is proven, supported, and low-risk. Requiring upfront Type 4 financing would drive load to publicly owned utility territory or out of California entirely, leaving existing ratepayers holding upgrade costs with none of the rate-reduction benefit. PG&E illustrated the point with a Silicon Valley Power example: a CAISO-approved 230 kV line estimated at **$593 million** to **$858 million**, whose costs would flow through TAC regardless of whether the associated load ultimately lands in PG&E territory. PG&E also told commissioners that no customer has yet used interim Rule 30 implementation, arguing that uncertainty around Type 4 cost treatment and refund timing has frozen uptake. Below is a recap of the reply briefs. - PG&E [defends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K309/607309911.PDF?ref=calregulatory.com) Rule 30 as a framework that will lower existing customer bills, arguing that intervenor proposals for upfront Type 4 financing are anti-competitive and unnecessary given the protections already in the tariff. PG&E also pushes back on TURN's battery storage requirement as unsupported by the record, rejects Cal Advocates' Revenue Cap methodology as flawed, and opposes CLECA's exemption request on the grounds that industrial and data-center customers present similar interconnection risks. Last, PG&E asks the CPUC to approve a [May 7 partial settlement agreement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K273/606273116.PDF?ref=calregulatory.com) on reporting and information-sharing. - [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K313/607313660.PDF?ref=calregulatory.com), [Sierra Club](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K356/607356382.PDF?ref=calregulatory.com), [NRDC](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K868/606868104.PDF?ref=calregulatory.com), and [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K889/606889820.PDF?ref=calregulatory.com) largely align around the argument that Rule 30 as proposed exposes existing ratepayers to unacceptable cost-shift risk from speculative hyperscale load. All four call for upfront financing requirements, direct cost-assignment mechanisms, or refundable load-development fees grounded in cost causation and beneficiary-pays principles. - TURN advances a refundable **$667/kW** interim load-development fee for loads of 25 MW or above. Cal Advocates proposes the same figure as one of several interim options alongside a flat **$50 million** fee, with its primary emphasis on a Revenue Cap methodology and Resolution E-5420-based refund approach. Both parties treat Resolution E-5420 as a fallback rather than a preferred endpoint. - Sierra Club and NRDC frame the dispute as a fairness question: whether unprecedented data-center growth should be socialized onto existing ratepayers or assigned proportionally to the customers driving it. Both reject PG&E's FERC preemption argument, citing the CPUC's own filing in [FERC Docket RM26-4-000](https://www.ferc.gov/rm26-4?ref=calregulatory.com), in which the CPUC affirmatively argued that large-load interconnection cost allocation remains a matter of state jurisdiction. - CLECA [does not oppose](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K132/607132965.PDF?ref=calregulatory.com) Rule 30 itself, but argues PG&E is misapplying data center-driven risk provisions to decarbonizing and Emissions Intensive Trade Exposed customers that do not present comparable stranded-load risks. CLECA urges the CPUC to allow such customers to access Rule 30 or continue under existing exceptional-case procedures, without being subject to the heightened minimum demand charges, extended contract terms, and early termination obligations built for speculative hyperscale load. - CalCCA's [reply brief](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K889/606889819.PDF?ref=calregulatory.com) reflects its settled position. With reporting and information-sharing issues resolved through the May 7 partial settlement with PG&E, Cal Advocates, and Sierra Club, CalCCA takes no position on cost allocation, jurisdiction, or stranded-cost protection. Its one remaining dispute is PG&E's proposed privacy and cybersecurity review requirements for CCAs receiving Rule 30 customer data. **INSTANT ANALYSIS:** The identical ex parte deck delivered to all five commissioner offices two days before reply briefs shows where PG&E sees its exposure. PG&E is pushing Resolution E-5420 as the endpoint, but TURN and Cal Advocates treat that resolution as a floor, and Sierra Club and NRDC want something more direct. The bigger question is whether the CPUC's final decision separates hyperscale data-center load from policy-aligned industrial load growth. --- ### UTILITY FINANCES/COST OF CAPITAL The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K933/606933345.PDF?ref=calregulatory.com) denying PG&E's request to exclude approximately **$2.6 billion** in wildfire liabilities and a state loan from its capital structure calculations. PG&E sought to exclude debt and equity impacts tied to: - The 2019 Kincade Fire; - The 2021 Dixie Fire; and - A **$1.4 billion** forgivable Department of Water Resources loan tied to the Diablo Canyon extension. PG&E argued the exclusions would preserve financing flexibility and avoid more expensive equity issuances. **ALJ Nojan** finds that PG&E is seeking waiver-equivalent relief under Affiliate Transaction Rule IX-B without meeting the rule's threshold requirements, and that calling it a "limited capital structure adjustment" is semantics. The PD rejects PG&E's request on three separate grounds. The wildfire costs amount to only 0.6% of equity, below the rule's 1% adverse financial event threshold. The PD refuses to aggregate the Kincade and Dixie events (unrelated incidents occurring years apart) to manufacture a qualifying reduction. And the DWR loan fails independently: a forgivable loan is not an adverse financial event. Prior CPUC approvals for PG&E and SCE involved financial shocks of a fundamentally different magnitude: - PG&E's 2020 waiver covered **$8.9 billion** in wildfire costs; and - SCE's approved request would have represented approximately 10% of equity. Neither offers persuasive precedent. On affordability, the PD sides with TURN and EPUC: excess leverage raises borrowing costs, pressures credit ratings, and inflates shareholder returns tied to an authorized equity ratio that already diverges substantially from PG&E's actual capital structure. TURN's record shows PG&E's actual equity has run 7 to 10 percentage points below its authorized 52% since 2021, producing an estimated $2.4 billion in shareholder profits from ratepayers. The earliest the CPUC will consider this item is **July 2**. Comments are due **June 10**. **INSTANT ANALYSIS:** The PD is a denial on every front: threshold, aggregation, and loan classification. The CPUC is not interested in creative labeling as a substitute for meeting the rule's conditions. The affordability section carries the PD's most consequential implications. The ALJ declines to accept PG&E's carrying-cost argument at face value and instead gives weight to TURN's critique: that operating with debt excluded from capital structure calculations allows PG&E to compensate shareholders based on an inflated authorized equity ratio while ratepayers absorb the leverage risk. That theory is now on record and may travel into Cost of Capital proceedings, wildfire financing debates, and affordability dockets. --- ### ERRA COMPLIANCE PG&E, Cal Advocates, and the California Community Choice Association filed a [joint motion seeking CPUC approval of a settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M607/K309/607309916.PDF?ref=calregulatory.com) resolving all disputed issues in PG&E's [2024 Energy Resource Recovery Account compliance](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K607/557607577.PDF?ref=calregulatory.com) proceeding. This proceeding reviewed PG&E's 2024 utility-owned generation operations, fuel procurement, Resource Adequacy accounting, portfolio balancing entries, contract administration, and related activities. Both Cal Advocates and CalCCA initially protested portions of PG&E's application. Both now support approval subject to settlement terms developed through testimony, supplemental testimony, discovery, and negotiations. The settlement resolves four substantive disputes. - On a [Humboldt Bay](https://en.wikipedia.org/wiki/Humboldt%5FBay%5FNuclear%5FPower%5FPlant?ref=calregulatory.com) Unit 3 exhaust valve failure, Cal Advocates withdrew its demand for an outside metallurgical review after PG&E confirmed the failed valve had been recycled. In its place, PG&E agreed to hire an outside consultant to conduct a root-cause analysis and provide findings to Cal Advocates if a repeat exhaust valve failure causes another forced outage. - On balancing account scope, PG&E agreed to include four accounts in future ERRA compliance reviews that Cal Advocates had sought: the New System Generation Balancing Account, Modified Transition Cost Balancing Account, Tree Mortality Non-Bypassable Charge Balancing Account, and BioMat Non-Bypassable Charge Balancing Account. - On Resource Adequacy, CalCCA accepts that PG&E reasonably calculated retained RA using final derated capacity values for monthly compliance filings and does not need to revise its 2024 accounting. - On PCIA customer vintaging, CalCCA accepts PG&E's supplemental testimony regarding customers who opt out of CCA service, later opt back in, and relocate within the same CCA territory, concluding that PG&E's billing assigns vintages consistent with CPUC directives. Of 156 customers meeting those criteria, PG&E identified **one** improperly vintaged customer, attributing the error to human error rather than a system logic defect. **INSTANT ANALYSIS:** The proposed settlement contains no disallowances, no prudency findings against PG&E, and no accounting revisions for the record period. After more than a year of testimony, supplemental testimony, and reopened discovery, Cal Advocates and CalCCA arrive at procedural refinements rather than financial consequences. The most substantive forward-looking change is the expansion of ERRA compliance review scope to four additional balancing accounts. CalCCA effectively accepts PG&E's retained RA accounting methodology and PCIA billing methods, while the Humboldt Bay dispute resolves into a contingent outside-consultant commitment triggered only by a repeat failure. For PG&E, this is a favorable compliance outcome. ### THURSDAY BRIEFING: SDG&E's 2027 ERRA Forecast; Biomethane EITE Exemptions; SoCalGas Line 225 Repairs URL: https://www.calregulatory.com/thursday-briefing-sdg-es-2027-erra-forecast-biomethane-eite-exemptions-socalgas-line-225-repairs/ Last updated: 2026-07-01T23:30:20.000Z Today's briefing looks at SDG&E's 2027 ERRA Forecast submission, with additional updates on biomethane cost allocation, PG&E's natural gas transmission assets, and SoCalGas's latest news on Line 225. --- ### SDG&E 2027 ERRA FORECAST SDG&E filed its [2027 ERRA Forecast Application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K860/606860975.PDF?ref=calregulatory.com) at the CPUC on May 15, seeking approval of an **$893 million** procurement-related revenue requirement, a **1.5%** increase from currently effective levels. New rates would take effect **January 1, 2027**. The ERRA revenue requirement falls **3.3%** to $379.3 million, with a projected $45 million overcollection. The Portfolio Allocation Balancing Account rises **71%** to **$301.4 million**, partially offset by a prior-year balance reduction from $296.7 million to **$144.8 million**. Local Generation rises to **$285.4 million**, reflecting continued recovery of costs tied to Cost Allocation Mechanism-approved peakers, storage facilities, and microgrids. The various account shifts net $**12.9 million** above currently effective levels. Bundled customers see an approximate **1.2%** rate decline, aided by California Climate Credit returns; a typical 400 kWh residential customer sees no bill movement. Unbundled customers face a **1.4%** increase in delivery-plus-PCIA charges. For that audience, SDG&E's October update matters more than the May filing: Track 2 of R.25-02-005 [is still resolving pre-2019 REC valuation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K596/606596794.PDF?ref=calregulatory.com), and any Commission directive flows directly into PCIA rates when 2026 Market Price Benchmarks arrive in October. SDG&E forecasts **$181.4 million** in GHG allowance revenues: $137.8 million returned via California Climate Credits, $2.8 million to EITE customers. The filing also picks up the new Transmission Accelerator Revolving Fund obligation: **5%** of qualifying GHG auction revenues remitted to the state beginning **July 1, 2026**, due within 15 days of receipt. Below are illustrative rates. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/bundled.png) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/unbundled.png) *CRI's coverage of PG&E and SCE's 2027 ERRA Forecast filings is available* [*here*](https://www.calregulatory.com/2027-erra-forecasts-sce-procurement-costs-fall-yet-bills-edge-higher-pg-e-projects-5-7-bundled-increase/). [2027 ERRA Forecasts of PG&E and SCESCE procurement costs fall, yet bills are expected to edge higher; PG&E projects a 5.7% bundled Increase.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-May-05-2026--22--d37af3cd9a96f7a313969e94fca958b66fcfc5e9c6ffb583ed4a281fc86a0584.png)](https://www.calregulatory.com/2027-erra-forecasts-sce-procurement-costs-fall-yet-bills-edge-higher-pg-e-projects-5-7-bundled-increase/) **INSTANT ANALYSIS:** The 1.5% increase and declining bundled rates obscure what is moving in the accounts: a 71% PABA increase tied to above-market portfolio cost recovery, Local Generation growth from previously approved CAM resources, and a new TARF remittance claim on auction proceeds beginning mid-2026\. --- ### BIOMETHANE The ALJ issued a [second supplemental comment ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K860/606860991.PDF?ref=calregulatory.com) in the biomethane cost-allocation proceeding ([R.22-12-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K216/500216057.PDF?ref=calregulatory.com)), reopening two questions tied to who ultimately bears Renewable Gas Standard above-market costs. - The first issue asks parties to reassess prior positions in light of the CPUC's April 30 decision on the Renewable Gas Standard ([D.26-04-044](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K801/605801938.PDF?ref=calregulatory.com)), which revised portions of the program to streamline implementation and constrain above-market ratepayer exposure. Because that decision addressed overlapping topics (including Renewable Thermal Certificate rules and biomethane interconnection costs), the ALJ is asking whether any findings, conclusions, or orders in D.26-04-044 affect positions parties have already taken in this proceeding. [Biomethane Cut, Hydrogen Denied, Transmission FinancingThe CPUC’s April 30 voting meeting featured major moves on biomethane, hydrogen, transmission, electric rates, and risk-based decision-making.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-affaf31a9d8ac42b10288a4198c5db3da6cd79e74a2eba105270a3207644de39.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-30-2026--48--c09d52d4e7cc36cb9923deb9b6157ff57223c394fcbf43190abcd95cdee815f2.png)](https://www.calregulatory.com/april-30-cpuc-voting-meeting-results-biomethane-cut-hydrogen-denied-transmission-financing-opens/) - The second issue carries greater commercial significance for large gas users. The ruling again raises whether Energy Intensive Trade Exposed noncore customers should have a pathway to exemptions if Renewable Gas Standard above-market costs are ultimately allocated to noncore customers. The ALJ is seeking input on whether the CPUC should establish a process for developing such exemptions, what criteria should govern eligibility, and whether exemptions would be necessary to avoid emissions leakage. The issue first surfaced in a [February 5 supplemental ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103216.PDF?ref=calregulatory.com) and now returns for a more focused examination. Opening comments, capped at 10 pages, are due **June 3**. --- ### NATURAL GAS TRANSMISSION ASSETS Commissioner **Matthew Baker** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K807/606807876.PDF?ref=calregulatory.com) in [A.25-12-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com), setting the procedural roadmap for PG&E's proposed acquisition of full ownership of Standard Pacific Gas Line, currently owned six-sevenths by PG&E and one-seventh by Chevron. The transaction involves an asset sale to PG&E, related transportation agreements preserving Chevron's system access, and a 20-year stock purchase agreement for Chevron's remaining stake. --- ### LINE 225 UPDATE SoCalGas provided an [Envoy](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome) update on the force-majeure event affecting Line 225 near the I-5 Freeway and Ridge Route Road in Castaic, indicating that geotechnical work has been completed and engineers have finalized the first phase of a repair plan for the damaged pipeline segment. Construction is expected to begin as early as **May 26** and continue for several months, though the timeline remains subject to change. In the meantime, SoCalGas advises customers to monitor the Envoy Capacity Utilization page for available pipeline capacity by scheduling cycle, a reminder that operational constraints tied to the outage remain relevant for shippers managing nominations and system flexibility. ### The CAISO's 2027 Flexible Capacity Filing: Solar Drives 84% of the Ramp, Battery EFC Methodology Unresolved URL: https://www.calregulatory.com/the-caisos-2027-flexible-capacity-filing-solar-drives-84-of-the-ramp-battery-efc-methodology-unresolved/ Last updated: 2026-05-20T15:00:02.000Z The CAISO filed its [Final 2027 Flexible Capacity Needs Assessment](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K596/606596784.PDF?ref=calregulatory.com) at the CPUC on May 13, providing the technical basis for flexible capacity obligations in the 2027 RA compliance year. The CAISO made no changes from its March draft and the filing drew no stakeholder comments. System-wide needs peak in March at **30,378 MW** and bottom in December at **25,060 MW**. The CAISO retains its three-category framework: base flexibility at **27%** of total need in non-summer months and **42%** in summer, peak at **68%** and **53%** respectively, with super-peak fixed at **5%** year-round. For CPUC-jurisdictional LSEs, monthly obligations run from **23,824 MW** in December to **29,064 MW** in March. Table 4 shows solar driving the maximum three-hour net-load ramp in every month of 2027. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/sunset-2.png) August solar contribution reaches **84.18%**. The ramp is a sunset problem. The CAISO states this plainly and anticipates continued solar dominance as utility-scale and behind-the-meter penetration grows. The battery [Effective Flexible Capacity](https://www.lawinsider.com/dictionary/effective-flexible-capacity?ref=calregulatory.com) methodology is the filing's unresolved question. The CAISO states that battery charging in Effective Flexible Capacity accreditation "may be over-credited" in most months outside spring, because batteries are transitioning from charging to discharging during the same ramp window flexible capacity is designed to address. The CAISO identifies the problem and defers it, citing unresolved Local Regulatory Authority battery-mapping data. --- **INSTANT ANALYSIS:** The CAISO has identified battery over-crediting as a potential problem, and that acknowledgment creates a procedural record. The next questions are whether the CPUC addresses the issue in the [Resource Adequacy docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K934/583934825.PDF?ref=calregulatory.com), whether parties press for methodology revisions in the 2028 cycle, or whether the CAISO's ongoing Flex RA working group moves first. The mapping-data rationale buys one cycle. As storage penetration rises, pressure to reconcile accredited flexibility with actual operational behavior during evening ramps will grow. Last, as solar dominance of the three-hour ramp deepens, procurement pressure continues shifting toward resources that are capable of responding during compressed evening windows. The CAISO's category percentages have moved in that direction for four consecutive years. ### 2027 ERRA Forecasts: SCE Procurement Costs Fall, Yet Bills Edge Higher; PG&E Projects 5.7% Bundled Increase URL: https://www.calregulatory.com/2027-erra-forecasts-sce-procurement-costs-fall-yet-bills-edge-higher-pg-e-projects-5-7-bundled-increase/ Last updated: 2026-05-20T13:44:23.000Z PG&E and SCE filed their 2027 Energy Resource Recovery Account Forecast applications with the CPUC on May 15\. Neither filing is final. October updates will incorporate updated forecast assumptions, year-end balancing account data, and intervening Commission decisions. A major variable is the CPUC's pending **September 17** decision in the ERRA/PCIA Reform docket ([R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com)), which asks whether pre-2019 banked Renewable Energy Credits should carry a value greater than zero when used for bundled service customer compliance under the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com). That decision will flow directly into the fall updates. ### PG&E's 2027 ERRA Forecast PG&E [requests a **$4.409 billion**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K868/606868011.PDF?ref=calregulatory.com) total procurement-related revenue requirement for 2027\. Bundled customers are forecast to see rates rise **5.7%**, from 33.8 cents/kWh to **35.7 cents/kWh**. Direct Access and Community Choice Aggregation customers move in the opposite direction, with average rates forecast to decline **7.3%**, from 23.4 cents/kWh to **21.7 cents/kWh**. The primary driver is a declining PCIA obligation; DA and CCA customers pay cost-responsibility surcharges rather than bundled energy procurement costs, and the PCIA component is forecast lower. PG&E projects a **$530 million** net greenhouse gas revenue return, producing a **$41.74** semiannual [California Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com). Below are PG&E's illustrative rates. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/rates1.png) ### SCE's 2027 ERRA Forecast SCE [requests **$4.350 billion**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K860/606860943.PDF?ref=calregulatory.com), approximately **$360.7 million** below the revenue requirement reflected in current rates, yet customer bills will still rise. SCE acknowledges that this outcome appears counterintuitive. The disconnect between a lower procurement-related revenue requirement and higher rates stems from how costs are allocated in supporting rate calculations. Edison forecasts an overall **1.8%** rate increase, including **1.2%** for residential customers. A typical non-CARE residential customer using 500 kWh per month would see a monthly bill rise from $187.56 to **$189.76**, excluding the semiannual California Climate Credit. SCE's greenhouse gas revenue return totals approximately **$616.7 million**, producing a projected **$54** semiannual Climate Credit. Below are SCE's illustrative rates. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/05/rates2.png) --- Mid-Term Reliability procurement, Central Procurement Entity local RA obligations, Voluntary Allocation and Market Offer implementation, greenhouse gas crediting, tree-mortality charges, and [BioMAT](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) all continue moving through the annual ERRA framework. What began as an electric procurement proceeding increasingly functions as a recovery vehicle for policy-era obligations adopted in other dockets. For large customers, ESPs, and PCIA-sensitive interests, cost-allocation vigilance remains warranted **INSTANT ANALYSIS:** The October updates matter more than the May applications. Commodity prices, RA costs, balancing account swings, and the REC-valuation decision in R.25-02-005 all remain capable of moving the numbers before **January 1** implementation. ### Intervenor CAP Testimony: Parties Challenge Sempra Utilities' Cost-Allocation, BTS Capacity Cuts, and Storage Proposals URL: https://www.calregulatory.com/intervenor-cap-testimony-parties-challenge-cost-allocation-bts-capacity-cuts-and-storage-proposals/ Last updated: 2026-05-19T12:30:06.000Z On May 15, parties served direct testimony in [A.25-09-014](https://www.socalgas.com/a25-09-014-socalgas-and-sdge-2027-cost-allocation-proceeding-cap?ref=calregulatory.com), the SoCalGas/SDG&E 2027 CAP filing, which will allocate natural gas costs and set rates, effective **January 1, 2027** through **December 31, 2029.** Parties' testimony spans: - Storage cost classification and allocation; - The Sempra Utilities' proposed backbone-to-local transmission reallocation; - Weather-design methodology; - BTS nomination and open-season capacity; - Regulatory account treatment of the Firm Access and Storage Rights Memorandum Account and Noncore Storage Balancing Account; - A proposed Rule 23 expansion; and - SoCalGas's proposal to quadruple the residential fixed charge. ### **STORAGE CAPACITY BASIS** - The [Indicated Shippers](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9314/606659356.pdf?ref=calregulatory.com) and the Southern California Generation Coalition both reject SoCalGas's use of median Envoy postings to classify storage costs, arguing that fixed-cost systems must be allocated on design capacity, not typical utilization. SCGC documents that prior cost-allocation proceedings have used maximum available capacities for this purpose. - Cal Advocates attacks the problem differently: the [2024 California Gas Report](https://www.socalgas.com/sites/default/files/2024-08/2024-California-Gas-Report-Final.pdf?ref=calregulatory.com) underlying the core inventory proposal has overstated actual core peak demand across five consecutive winters. Cal Advocates recommends reducing core inventory from 76 Bcf to **60-65 Bcf** and adding a mid-period true-up triggered by a **5%** demand miss. - On the proposed 8-to-12 Bcf Load Balancing inventory increase, the Indicated Shippers note SoCalGas's discovery response was simply "not applicable" when asked to produce supporting analysis, and that core weather-sensitive loads, not noncore industrial loads, drive balancing requirements. ### **LOAD BALANCING COST ALLOCATION** The Indicated Shippers argue that SoCalGas's Average Year Throughput allocator bears no relationship to the actual cost driver for Load Balancing Storage (peak demand) and would assign **47.3%** of those costs to retail noncore customers whose peak-to-average demand ratio is only 1.30, compared to over 3.0 for core. Shifting to a Peak-Day allocator drops noncore's share to **28.9%** and, combined with corrected Local Transmission and High-Pressure Distribution allocations, reduces the noncore's total embedded cost responsibility by approximately **$54.8 million**. ### **BACKBONE-TO-LOCAL TRANSMISSION REALLOCATION** No intervenor fully accepts the proposal as filed. SCGC identifies two methodological errors (using the 69% local transmission fraction rather than the 31% backbone fraction, and using non-cold-year recorded data) that together reduce the defensible reallocation to 8% rather than 20.4%, and recommends no reallocation at all. Indicated Shippers would accept a corrected reallocation of approximately **$91 million** using consistent peak-day demands. Cal Advocates cites a seasonal mismatch: the reallocation factor is derived from summer electric generation conditions but recovered through a winter-peak allocator, routing summer costs onto residential heating bills. TURN also recommends rejection of the backbone-to-local transmission reallocation. ### **WEATHER DESIGN** The Indicated Shippers and Cal Advocates both contest the Sempra Utilities' 2014-2018 warm-weather-regime adjustment, which compresses the Historical Heating Degree Day standard deviation by about **45%** and shifts approximately **$50 million** per year in core reliability costs to other functions, including Load Balancing borne largely by noncore customers. Cal Advocates adds that the utilities possess 75 and 53 years of Historical Heating Degree Day data but use only 20 years, and that the flat dummy-variable correction overcorrects some warm years while under-correcting others. Both parties recommend using unadjusted historical data. ### **FASRMA/NSBA ACCOUNTS** The Indicated Shippers, SCGC, Cal Advocates, and TURN all reject SoCalGas's proposal to use the **$27 million** NSBA over-collection to eliminate the **$4 million** FASRMA under-collection. Their shared argument is that the FASRMA balance: - Reflects a failed Off-System Delivery commercial program that generated only **$30,000** in total revenue against $3.1 million in capital costs; - Has offered no service since 2017; and - Arose from an Off-System Delivery program authorized in [D.11-03-029](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/131989.PDF?ref=calregulatory.com) on an expectation of net positive revenues that never materialized. All four of these parties agree the balance should not fall on ratepayers, though their proposed remedies differ: - The Indicated Shippers and TURN recommend shareholder absorption; - Cal Advocates recommends recovery from Off-System Delivery customers specifically, or if that is not practicable, a finding of imprudence or proportionate shareholder absorption; - SCGC recommends the balance be written off against earnings. On the NSBA side, the Indicated Shippers argue the **$27 million** over-collection arose entirely from the Unbundled Storage program and should be returned to noncore customers by offsetting costs in the Noncore Fixed Cost Account. Cal Advocates conditionally supports eliminating the Enhanced Oil Recovery Account subject to annual reporting requirements to preserve transparency during Enhanced Oil Recovery's continuing decline. ### **BACKBONE TRANSPORTATION SERVICE PROPOSALS** SCGC and the Indicated Shippers both oppose SoCalGas's proposal to reduce open season BTS contracting capacity to **110%** of the minimum backbone design standard (approximately **2,418 MMcfd**). SCGC's compiled five-year Envoy data shows operationally-available capacity has exceeded that threshold every single day since January 2021\. The Indicated Shippers accept the underlying Elapsed Pro-rata Scheduled Quantity leakage problem SoCalGas identifies but propose a phased alternative: applying the Total Net System Capacity cap at Intraday 2 rather than jumping immediately to the Evening cycle, with transparency requirements and transitional protection for shippers holding upstream firm capacity. ### **RESIDENTIAL FIXED CHARGE** TURN, the Sierra Club, and Cal Advocates all recommend rejection of SoCalGas's proposal to raise the non-CARE fixed charge from $5 to **$20** and the CARE charge from $4 to **$10** by 2029 (the same proposal the CPUC rejected less than two years ago). TURN documents that the bottom 40% of non-CARE customers and the bottom decile of CARE customers face bill increases, with low-income, low-usage households bearing the largest percentage hits. Sierra Club makes the electrification economics case: lower volumetric rates reduce the operating cost advantage of switching to electric appliances, precisely counteracting the price signals California needs. Sierra Club also notes that SoCalGas has actively opposed South Coast Air Quality Management District and CARB rules that would produce the electrification it assumes to justify the charge. Sierra Club recommends eliminating the fixed charge and replacing it with a minimum bill. Cal Advocates adds that the SoCalGas/SDG&E asymmetry (SoCalGas seeking a **300%** increase while SDG&E proposes nothing) is internally inconsistent. ### **COST-ALLOCATION METHODOLOGY** TURN challenges multiple aspects of the embedded cost study's construction. Asset Retirement Obligations are improperly included in the net plant figures used to allocate rate base, return, and taxes across functions. This inflates the distribution costs assigned to residential customers for obligations that are future-period liabilities, not plant currently used and useful in providing service. TURN also contests the distribution sub-functionalization methodology, recommends reducing the inventory sub-function allocation for storage wells and lines from 50% to **10%** on the grounds that wells and lines exist primarily to inject and withdraw gas rather than maintain inventory. TURN argues that Administrative & General and General Plant costs (totaling approximately **$853 million**, or 24% of SoCalGas's total revenue requirement) are allocated entirely by a labor factor with no meaningful analytical support for that choice. TURN also identifies a timing problem: the embedded cost study is built on 2024 FERC Form 2 data, but transmission net book value grew **57%** between 2021 and 2024 compared to 26.8% for distribution, and transmission depreciation grew **65.9%** versus 25.6% for distribution. Equal-percentage scaling of all functions to match the current revenue requirement fails to capture the fact that transmission costs are growing at more than twice the rate of distribution costs, understating the transmission share of the authorized revenue requirement during the 2027-2029 period and leaving distribution-level customers to absorb cost increases that properly belong to transmission. On the Long-Run Marginal Cost question, TURN and Cal Advocates both insist it be retained as a binding benchmark, noting the embedded study assigns approximately **$490 million** more to the residential class than LRMC. Clean Energy alone [supports](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2509014/9311/606659350.pdf?ref=calregulatory.com) abandoning Long-Run Marginal Cost, arguing it produces misleading price signals in a declining-load environment where the system is contracting rather than expanding. ### **OTHER ISSUES** The Indicated Shippers challenge SoCalGas's GHG allowance price assumption of **$50-$100/MT** (more than three times the $27-$29/MT at which recent Cap-and-Invest auctions have cleared) arguing it artificially suppresses the EG demand forecast by overstating gas generation's simulated operating cost. Clean Energy contests SoCalGas's Natural Gas Vehicle demand forecast, which uses a two-year average growth rate anchored partly to COVID-recovery-inflated 2023 volumes; actual 2025 growth came in at 2.9% versus the forecasted 6.7%, with under-collection and rate volatility the likely consequence if the overstated forecast is adopted. ### **INSTANT ANALYSIS** The Indicated Shippers, SCGC, Cal Advocates, and TURN frequently arrive at similar critiques through independent analyses, even where their proposed remedies differ. On the fixed charge, TURN, Sierra Club, and Cal Advocates reconstruct much the same case the CPUC accepted when it rejected a nearly identical proposal less than two years ago. The BBT-to-LT reallocation may be the most immediately actionable issue. SCGC identified what appears to be a straightforward arithmetic error (SoCalGas applied the wrong fraction) that cuts the proposed reallocation by more than half without requiring the CPUC to resolve any harder conceptual questions. On core storage allocation, Cal Advocates argues the California Gas Report has overstated actual core peak demand in recent winters and recommends reducing core inventory from 76 Bcf to 60-65 Bcf, paired with a mid-period true-up. A planning figure that five winters of data have already proven wrong, with no mechanism to correct it mid-cycle, is a hard position for SoCalGas to defend. ### SoCalGas Compliance Filing: One Inspection Anomaly Put 90% of San Diego County Gas Supply at Risk URL: https://www.calregulatory.com/socalgas-compliance-filing-one-inspection-anomaly-put-90-of-san-diego-county-gas-supply-at-risk/ Last updated: 2026-05-18T14:52:55.000Z Pursuant to **ALJ Ormond**'s [April 16 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K937/604937767.PDF?ref=calregulatory.com) in [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com), SoCalGas filed a compliance document cataloging a decade of transmission outages across three operational categories: (i) receipt capacity, (ii) system resiliency, and (iii) customer service. [A.26-01-009 SoCalGas Compliance Filing - Within TerritoryA.26-01-009 SoCalGas Compliance Filing - Within Territory.pdf273 KBdownload-circle](https://www.calregulatory.com/content/files/2026/05/A.26-01-009-SoCalGas-Compliance-Filing---Within-Territory.pdf "Download") Below is a summary of the filing. ### **RECEIPT CAPACITY** An October 2017 rupture on Line 235 triggered a parallel shut-in of Line 4000, collapsing Northern Zone firm receipt capacity from 1,590 MMcfd to **550 MMcfd** (a two-thirds reduction). Capacity did not fully recover until the end of 2023, more than six years later. SoCalGas ties that period directly to Aliso Canyon withdrawal restrictions, arguing that constrained storage compounded transmission stress in ways neither problem would have produced alone. ### **RESILIENCY & RELIABILITY** In June 2025, simultaneous stress corrosion cracking on Lines 4000 and 4002 cut Northern Zone capacity by **655 MMcfd** and severed Northern Zone support for the Southern Zone entirely, pushing Southern Zone customers onto Ehrenberg deliveries heading into winter. Following February 2024 atmospheric rivers, a landslide exposed and destabilized a long segment of Line 1005 north of Ventura. SoCalGas shut the line from the slide area to Ventura, and insufficient crossovers with parallel Line 1004 effectively removed Line 1005 from transmission operations until July 2025\. For about 17 months, a single pipeline carried all large gas supplies between Ventura and Goleta. A Line 1004 failure during that window would have left no transmission path to coastal California. In January 2024, a safety condition on Line 5000 (combined with the prior abandonment of a Line 2000 segment across the Morongo Band Reservation) left the Southern System dependent on a single pipeline through a critical corridor, eliminating more than half of Ehrenberg receipt capacity during peak winter demand. A late-October 2025 outage on Line 225 cut Wheeler Ridge Zone receipt capacity to **50 MMcfd** against nominal capacity of 765 MMcfd (approximately 6.5%) while reducing injection and withdrawal capacity at both Honor Rancho and La Goleta. [A December 27 landslide](https://www.socalgas.com/castaic-line-break-repair?ref=calregulatory.com) then severed Line 225 north of Honor Rancho. As of the filing date, the line remains out of service. ### **CUSTOMER SERVICE** SoCalGas identifies three pipelines as critical to entire geographic areas with no meaningful backup: - **Line 3010:** San Diego County - **Line 7000:** San Joaquin Valley communities north of Bakersfield - **Line 247:** coastal communities from Gaviota to San Luis Obispo A routine inspection anomaly on Line 3010 in August 2025 nearly took down the gas supply for California's second-most-populous county. An anomaly on the pipeline carrying about 90% of San Diego County's gas supply triggered a curtailment watch across all of SDG&E's service territory during peak summer demand. Had Line 3010 required shut-in, most of SDG&E's gas-fired generation (nearly 60% of the county's electricity portfolio) would have faced curtailment. Field inspection determined the line could safely remain in service while repairs proceeded. ### HURRICANE HILARY August 2023's [Hurricane Hilary](https://en.wikipedia.org/wiki/Hurricane%5FHilary?ref=calregulatory.com) hit all three categories at once. Storm damage to Lines 2000 and 2001 triggered a force majeure declaration and reduced Southern System receipt capacity by **200 MMcfd**. Flooding severed Line 6916, cutting service to Twentynine Palms (including the Marine Corps base) through November 3, 2023\. Storm exposure of Lines 6902 and 6001 in the Imperial Valley came within an inspection determination of disrupting gas service to the entire regional customer base, including an international wholesale customer in Mexicali. ### **INSTANT ANALYSIS** SoCalGas is asking the CPUC to stop treating transmission outages as isolated maintenance events and start treating them as a recurring operating condition for a large, aging system under mounting integrity and compliance obligations. The Line 3010 example is striking: one inspection anomaly on a pipeline serving about 90% of San Diego County's gas came close to curtailing most of the county's electric generation during August peak demand. The Northern Zone section shows what happens when storage constraints and transmission impairment arrive simultaneously. The Line 1005 and Line 5000 events show what happens when prior infrastructure decisions (Aliso Canyon restrictions, a right-of-way abandonment) eliminate redundancy that a later emergency would have needed. The Wheeler Ridge section shows what a single-pipeline zone looks like when that pipeline fails. The 10-year outage record makes a case that extends beyond A.26-01-009\. By documenting hundreds of events across three categories, SoCalGas is building the predicate for a larger proposition: aging infrastructure operating under heightened compliance demands requires redundancy, storage flexibility, and room to conduct maintenance without converting that maintenance into a reliability crisis. ### SoCalGas Customer Forum: 185 High OFOs, No North-South Expansion, & What 0.5 Bcf/d from Costa Azul Means for Reliability URL: https://www.calregulatory.com/socalgas-customer-forum-185-high-ofos-no-north-south-expansion-what-0-5-bcf-d-from-costa-azul-means-for-reliability/ Last updated: 2026-05-16T17:34:12.000Z SoCalGas hosted its 2026 Annual Customer Forum this morning, detailing the April 2025-March 2026 reporting period, the pending 2024 Cost Allocation Proceeding implementation, and its active 2027 CAP proposal. Notably: - The Southern System reliability strategy the CPUC acknowledged in [D.22-07-002](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M495/K983/495983692.PDF?ref=calregulatory.com) may require reassessment once Energía Costa Azul LNG begins drawing feed gas this summer. - The forum's most consequential exchange involved the long-rejected [Adelanto-to-Moreno North-South pipeline project](https://ia.cpuc.ca.gov/environment/info/ene/n-s/northsouth.html?ref=calregulatory.com). A participant asked whether SoCalGas would revisit that expansion given imminent ECA demand. SoCalGas's answer, that the CPUC has instructed staff to wait until operational data arrives from the liquefaction plant before reconsidering North-South capacity, is the regulatory holding pattern trading desks and large industrial customers should understand heading into Q3 2026. ### OPERATIONAL FLOW ORDERS | | Apr 2024 – Mar 2025 | Apr 2025 – Mar 2026 | | --------- | ------------------- | ------------------- | | High OFOs | 103 | **185** | | Low OFOs | 32 | **16** | High OFO declarations rose about **80%** year over year. The bulk of the increase came at Stage 3.1, with new activity emerging at Stage 3.2\. Cycle 2 declarations climbed from 98 to **172**. Daily imbalance tolerances ranged from **2%** to **15%** during the current period. SoCalGas attributed part of the increase to a relatively warm winter. Storage injection capacity is stressed when system demand runs below normal and excess supply needs to be absorbed. But a relatively warm winter should also have suppressed Low OFOs by less than the 50% reduction the data actually shows. The asymmetry between the two directions suggests other dynamics are in play and is the kind of pattern that should draw questions in the post-forum process. Low OFOs fell from 32 to **16**, with the entire reduction coming from Cycles 2 and 3. ### SOUTHERN SYSTEM RELIABILITY PURCHASES & THE $15 OTAY QUESTION SoCalGas purchased and sold approximately **2,560 MDth** during the reporting period at a net cost of **$1.53/Dth**, generating **$3.9 million** in System Reliability Memorandum Account costs. Of the five tools available for southern system reliability, SoCalGas used only two: spot transactions and the Memorandum in Lieu of Contract. Seasonal baseload purchases, discounted BTS contracts, and RFPs went unused. No BTS discounts were applied. Net volumes are the second-highest in the six-year history shown. 2022–2023 remains the peak at **4,124 MDth** and **$31 million** in SRMA costs. Average net cost per Dth is the lowest of any year with Southern System Reliability activity. Most purchases occurred during summer 2025, with a smaller cluster in February 2026. One trading-side question concerned a specific transaction within that activity: an intraday purchase of **123,000 Dth** at Otay on September Gas Day 3 at **$15/Dth**, about $12 above the Ehrenberg ICE settle for that day. The participant asked how the pricing was justified. SoCalGas identified the personnel responsible for soliciting intraday gas in response to Gas Control requests, and deferred specific justification to the 2026 annual compliance report, Advice No. 6558-G-A. That same advice letter contains SoCalGas's pending request to modify the Rule 41 Safe Harbor Guidelines for baseload purchases, discussed below. The two items are linked: a **$12/Dth** premium over an inter-basis differential is the kind of pricing outcome that would be more difficult to defend if the utility had broader baseload procurement authority. [SOCALGASADVICE LETTER 6558-G-Aab2a1769-6b14-4562-81b1-ec7015fab434.pdf676 KBdownload-circle](https://www.calregulatory.com/content/files/2026/05/ab2a1769-6b14-4562-81b1-ec7015fab434.pdf "Download") [SOCALGASRule 41ec2fed62-ac87-4dc2-8542-0d72bbac0115.pdf435 KBdownload-circle](https://www.calregulatory.com/content/files/2026/05/ec2fed62-ac87-4dc2-8542-0d72bbac0115.pdf "Download") ### THE NORTH-SOUTH PIPELINE A participant asked whether SoCalGas had revisited expanding the Moreno compressor or other North-to-South capacity given Costa Azul's expected demand, rather than relying solely on southern system reliability concerns or warnings. SoCalGas identified the actual constraint: the issue is not really Moreno, but the pipeline capacity to move gas south from the Northern System to Moreno. SoCalGas applied for funding authority over 10 years ago for a pipeline from Adelanto to Moreno to expand its North-South capability. The CPUC [rejected the project](https://www.utilitydive.com/news/california-puc-rejects-proposed-sempra-gas-pipeline/422715/?ref=calregulatory.com). Asked whether the project might be revisited given changed fundamentals, SoCalGas pointed to the Long-Term Gas System Planning docket and suggested that the CPUC has advised to "do nothing" until data on the ECA liquefaction facility and its impacts is available. ECA Phase I is expected in-service summer 2026, with Natural Gas Intelligence [recently reporting](https://naturalgasintel.com/news/sempra-targets-june-for-eca-first-lng-as-startup-begins/?ref=calregulatory.com) that the first volumes of feed gas had entered the plant. SoCalGas expects ECA to take approximately **0.5 Bcfd** from the El Paso Natural Gas South Mainline at full operation, the same supply path that feeds the southern zone. In short: - CPUC policy is to wait on ECA operating data before authorizing capital investment in North-South capacity; and - ECA is poised to reduce southern zone receipts by about half a Bcfd. In the interim, the reliability-tools approach (spot purchases, the Memorandum in Lieu of Contract, the pending Safe Harbor modification for baseload) becomes the operational response to a demand event the CPUC anticipated but did not pre-position infrastructure to address. ### CAP IMPLEMENTATION ON ENVOY OCTOBER 1 [D.24-07-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M536/K491/536491449.PDF?ref=calregulatory.com), the CPUC's 2024 decision authorizing an all-party settlement in the 2024 CAP, is moving into implementation. Three items remain pending: - **G-BTS5 firm volumetric rate** is effective **October 1, 2026** (100% volumetric, no reservation charge); - **G-BTS2 conversion** of existing G-BTS2 contracts reverts to a Modified Fixed Variable structure once G-BTS5 becomes available; and - **The Open Season** is extended by one month, aligning the BTS term with the November–October gas industry seasonal practice SoCalGas filed Advice No. 6626-G in April to implement these changes. Approval is expected ahead of the next Open Season. Envoy will reflect the changes on October 1, including secondary trade of G-BTS2 contracts with negotiable reservation charges, and a buy/exchange rights window opening **September 16, 2026** for contracts beginning October 1. [SOCALGASAdvice Letter 6626-G9688ea41-bfb9-41d7-99f9-a7671fcb2eae.pdf2 MBdownload-circle](https://www.calregulatory.com/content/files/2026/05/9688ea41-bfb9-41d7-99f9-a7671fcb2eae.pdf "Download") ### 2027 CAP (A.25-09-014): THREE PROPOSALS AFFECTING SHIPPERS The [2027 CAP application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K104/582104341.PDF?ref=calregulatory.com), for rates effective **January 1, 2027**, includes three proposals BTS shippers and noncore customers should track: 1. **NSBA-to-FASRMA reallocation:** The proposal would apply the Noncore Storage Unbundled Storage Balancing Account overcollections to the Firm Access Storage Rights Memorandum Account until the current undercollection is fully offset. 2. **BTS sale ceiling:** The proposal would modify BTS to limit the maximum amount of firm BTS available for sale to **110%** of the minimum backbone system design standard, based on the average day quantity in a 1-in-10 cold-and-dry year. 3. **Rule 30 modification:** The proposal would confirm BTS nominations up to Total Net System Capacity for the Evening, Intraday 1, Intraday 2, and Intraday 3 cycles regardless of a Gas Day's OFO status. Proposal 2 is the most consequential for shippers. Today's BTS availability is implicitly bounded by system economics and design. The 110% of 1-in-10 cold-and-dry framework would convert that into an explicit ceiling tied to a planning standard SoCalGas controls. The 1-in-10 cold-and-dry parameterization warrants close attention from industrial coalitions, both for the underlying methodology and for how the design quantity itself gets calculated and refreshed over time. Per the [scoping ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K310/592310495.PDF?ref=calregulatory.com), a CPUC decision is expected in Q4 2026. ### ALISO CANYON: SOCALGAS PUSHES BACK ON INVENTORY REDUCTION The first Biennial Assessment under D.24-12-076, issued by Energy Division on October 1, 2025, recommended reducing Aliso Canyon's maximum inventory by 10 Bcf (from 68.6 Bcf to **58.6 Bcf)** for winter 2025–2026\. The assessment also indicated that a smaller incremental reduction or no reduction at all may be appropriate for winter 2026-2027, given forecasts of higher gas commodity prices. SoCalGas filed an application in January requesting CPUC review, asking the Commission to decline the recommended reduction and to authorize an increase to maximum inventory if necessary to maintain reliability and just-and-reasonable rates. The Biennial Assessment's own caveat about higher winter 2026-2027 gas prices is an interesting analytical point. Energy Division is acknowledging that the cost of holding less inventory at Aliso Canyon becomes increasingly difficult to justify as the commodity environment changes, even before considering ECA's effect on southern zone supply. ### SAFE HARBOR MODIFICATION STILL PENDING SoCalGas's request to modify the Rule 41 Safe Harbor Guidelines for baseload transactions remains pending under Advice No. 6558-G-A. SoCalGas explained the underlying issue: when SoCalGas previously used baseload transactions, firm BTS capacity was available to assign on a day-to-day basis. Current conditions do not permit that, and the existing Safe Harbor framework does not accommodate the type of baseload purchases SoCalGas now needs to make for southern system reliability. A separate question later in the forum addressed the operational consequence: would SoCalGas communicate any shift from daily spot to monthly baseload procurement? SoCalGas confirmed there is a solicitation process for baseload purchases if the company goes that direction. The implication: if the Safe Harbor modification is approved, SoCalGas could move from event-driven spot activity to systematic baseload procurement on the southern system. That would alter the activity profile reflected in the Southern System Reliability cost graph and likely change the pricing dynamics raised in the Otay question earlier in the forum. Trading desks should plan for that possibility in their southern system supply models for 2027. ### RENEWABLES & THE MINIMUM FLOW REQUIREMENT An industrial-side question asked whether the southern system minimum flow requirement might decrease as renewable power capacity grows, citing the SunZia wind project ramping in the Southwest Power Pool. SoCalGas answered in general terms: that depending on grid interconnection, plants outside the southern system get dispatched to cover demand inside it, and that effect is presumably already reflected in current minimum flow requirements. The question is notable. [SunZia](https://patternenergy.com/projects/sunzia/?ref=calregulatory.com) Phase I (**3 GW** transmission, approximately **2.4 GW** of associated wind) has been ramping commercial operation through 2025–2026\. The Southern System minimum flow requirement is a function of gas-fired generation needs in the southern zone. Sustained displacement of southern gas-fired generation by imported renewables would allow the minimum to come down. Whether SoCalGas's planning methodology captures that dynamic on a rolling basis or only at major system planning intervals is a question worth raising in the Long-Term Gas Planning docket, and one the 2027 CAP design quantity calculation should engage with directly. The forum presentation is available [here](https://www.socalgasenvoy.com/ebb/attachments/1778865976515%5F2026%5FCustomer%5FForum%5FPresentation.pdf?ref=calregulatory.com). ### NEXT STEPS SoCalGas will publish draft post-forum report to Envoy by **May 29**. A revised draft will be available by **June 18**. The final post-forum report will be filed via advice letter by **July 14**. Customers with forum proposals should submit them before issuance of the draft post-forum report. ### INSTANT ANALYSIS Today's forum clarified SoCalGas's regulatory trajectory heading into ECA startup. The utility placed three items on the record in the same setting. - First, ECA is expected to take approximately 0.5 Bcfd from the El Paso South Mainline once at full operation. - Second, the CPUC's stance on North-South capacity is to wait for ECA operating data before reconsidering any infrastructure proposal, including the Adelanto-to-Moreno project the Commission rejected more than a decade ago. - Third, the existing Rule 41 Safe Harbor framework does not accommodate the baseload procurement SoCalGas may need under current BTS conditions, and the modification request remains pending under Advice No. 6558-G-A. A demand event the Commission anticipated is about to arrive. The capital response the utility proposed years ago was rejected. The procurement framework the utility now needs has not yet been approved. In the interim, southern system reliability runs on spot purchases, the MILC, and whatever operational latitude the CPUC grants on a case-by-case basis. The Otay transaction discussed at the forum (123,000 Dth at about $12 over Ehrenberg ICE) is the visible cost of that stance. The next 12 to 18 months will be defined by three observables: - How quickly ECA changes actual southern zone flow patterns; - Whether Southern System Reliability activity continues at or above the current $3.9 million annual run-rate; and - Whether the CPUC becomes more receptive to either the Safe Harbor modification or revisiting North-South infrastructure once ECA operating data is on the record. The 2027 CAP's proposed 110% of 1-in-10 cold-and-dry BTS sale ceiling should be read as part of the same arc: a constraint on shipper access to firm capacity at the same moment SoCalGas is asking for additional operational latitude on the procurement side. ### May 14 CPUC Meeting Results: PG&E Reliability Assumptions Shift, Wildfire Costs Repriced, and Diablo Oversight Changes Through 2030 URL: https://www.calregulatory.com/may-14-cpuc-meeting-results-pg-e-reliability-assumptions-shift-wildfire-costs-repriced-and-diablo-oversight-changes-through-2030/ Last updated: 2026-05-15T00:08:47.000Z At today's CPUC voting meeting, the Commission adopted the following items. - A decision authorizing a deal between PG&E and TURN over how much natural gas PG&E needs available during extremely cold winter days through 2027. - A decision authorizing SCE's transformation of significant [Woolsey Fire](https://en.wikipedia.org/wiki/Woolsey%5FFire?ref=calregulatory.com) costs into a long-term bond payment plan. - A decision finding that future [Diablo Canyon Power Plant](https://www.linkedin.com/company/diablo-canyon-power-plant/?ref=calregulatory.com) cost reviews should use final market values instead of earlier forecast estimates when determining whether costs stayed within the law’s 115% review threshold. Full summaries of the CPUC's final, redlined versions of these items are provided below the following housekeeping items. --- ### ***CRI HOUSEKEEPING NOTES*** *California Regulatory Intelligence has moved to a new pricing model*:** [***$75/month***](https://www.calregulatory.com/cri-operations-update-2/#/portal/signup/6a023109c799620001352e52/monthly) *for everyone. If you have benefited from CRI, we encourage you to sign up. For group access, contact* [***info@calregulatory.com***](mailto:info@calregulatory.com) **Also*: We are currently assembling a "Testimonials" page. If CRI has been useful to your work and you would be open to offering a short public testimonial, please reach out to* [***info@calregulatory.com***](mailto:info@calregulatory.com) [CRI Rate Change: $75/MonthCRI is implementing a new pricing model. The goal is simple: fewer emails, less procedural volume, & a greater focus on developments that matter.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-79.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-30-2026--20-.png)](https://www.calregulatory.com/cri-operations-update-2/) --- ### GAS SYSTEM RELIABILITY A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K932/604932014.PDF?ref=calregulatory.com) approves a full [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K724/605724316.pdf?ref=calregulatory.com) between PG&E and TURN resolving PG&E's updated Peak Day Supply Standard for winters 2024-2025 through 2026-2027. The case stems from a 2023 decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)), which directed PG&E to refresh its peak-day demand and supply modeling. TURN challenged three inputs (core demand, electric generation demand, and Redwood Path supply availability) then settled rather than litigate. Thursday's decision finds the resulting standard reasonable, within the evidentiary range, and consistent with its directive to improve methodology. The settlement reworks three inputs across three winters, generating 24 changed cells in PG&E's reliability table. - Core demand and electric generation both drop; - Combined northern-southern supply rises **92 MMcfd**; and - Every settled value falls between the parties' litigated positions. Those changes reduce the pre-investment 2024-2025 shortfall from -380 MMcfd to -**135 MMcfd** and move winters 2025-2026 and 2026-2027 into surplus before any new wells come online (a year earlier than PG&E's filed analysis projected). TURN won the argument that PG&E's peak-day numbers were inflated. **INSTANT ANALYSIS:** PG&E filed an analysis showing a -380 MMcfd shortfall heading into 2024-2025 and a system that would not reach surplus until 2026-2027 even after new wells came online. The settled numbers say something quite different. The 2024-2025 deficit shrank to -135 MMcfd, and the system crossed into surplus in 2025-2026 before any new wells were built. TURN's testimony forced PG&E to accept lower demand forecasts and higher supply availability than it had filed, and the arithmetic followed. The battle now moves to [A.25-05-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com), where PG&E will re-file demand trajectories, electric generation burn, and supply assumptions for winter 2027-2028 forward. Today's decision expressly preserves both parties' freedom to relitigate every input. The settlement closes a three-winter window without forcing a Commission ruling on whether PG&E's underlying methodology produces inflated capacity needs (a question TURN will almost certainly bring back in the General Rate Case). --- ### WOOLSEY FIRE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K621/606621820.PDF?ref=calregulatory.com) in [A.26-01-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com) authorizes SCE to issue approximately **$1.951 billion** in Recovery Bonds to refinance costs arising from the 2018 Woolsey Fire. The total consists of three components: - **$1.639 billion** in Wildfire Expense Memorandum Account costs approved for recovery in the December 2025 Woolsey Fire settlement decision ([D.25-12-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K453/592453458.PDF?ref=calregulatory.com)), representing about 35% of SCE's total WEMA balance through May 2025, net of approximately $1 billion in insurance recoveries; - **$299.2 million** in estimated pre-securitization debt financing costs accrued while the bonds are being arranged; and - **$12.7 million** in estimated upfront bond issuance costs. The remaining 65% of SCE's recorded WEMA costs (approximately $3.663 billion) was permanently disallowed in the prior settlement. Under the financing structure, SCE transfers Recovery Property (its right to collect the Fixed Recovery Charge) to a legally separate, bankruptcy-remote Special Purpose Entity. The Special Purpose Entity issues the bonds, and proceeds flow back to SCE. Bond repayment occurs through the Fixed Recovery Charge, a non-bypassable surcharge on all existing and future electricity consumers in SCE's service territory, regardless of provider. [CARE and FERA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com) customers are exempt by statute. The charge is subject to true-up adjustments at least annually, and more frequently if a shortfall is anticipated, with excess collections credited back through SCE's Base Revenue Requirement Balancing Account. Once the financing order is issued, it becomes irrevocable. SCE estimates that securitization will produce approximately **$811 million** in net present value savings relative to traditional rate-base treatment, measured against the utility's CPUC-authorized **7.59%** return on rate base. The CPUC accepts the savings case while noting that the actual figure will depend on final bond terms, tranche structure, and market interest rates at issuance. The proceeding moved fast. On March 13, 2026, SCE and Cal Advocates filed a joint stipulation resolving all issues in the scoping memo, including financing structure, customer allocation, and the just-and-reasonable findings, eliminating the need for evidentiary hearings. SCE is targeting Q3 2026 for bond issuance. If adopted, this would mark SCE's fifth Recovery Bond authorization under the [Assembly Bill 1054](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201920200AB1054&ref=calregulatory.com) framework, following three wildfire mitigation CapEx securitizations and the Thomas Fire/Montecito debris flow financing order ([D.25-08-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K094/578094182.PDF?ref=calregulatory.com)). **INSTANT ANALYSIS:** The CPUC is running the AB 1054 securitization playbook. A settlement in the underlying cost-recovery case arrived in December, a stipulation resolving the financing application followed in March, and a final decision came on May 14\. The underlying costs have been vetted, and Cal Advocates had little reason to challenge a financing structure built around a straightforward Net Present Value savings case. The practical result is that $1.951 billion in wildfire liability (already negotiated down substantially from SCE's original **$5.635 billion** request) converts into bondholder-grade debt backed by statutory repayment certainty, non-bypassable collection authority, and tranche maturities capped at 33 years. For large customers and load-serving entities, the Fixed Recovery Charge ends up on the bill regardless of provider, sits outside traditional rate base, and remains in place through future rate cases. Importantly, the $811 million savings figure compares securitization to rate-base treatment, not to further cost disallowance. The more relevant question for sophisticated customers is cumulative exposure: how this new Woolsey layer accumulates against existing AB 1054 wildfire mitigation and Thomas Fire securitization charges that are already embedded in bills. Today's decision does not consolidate that picture. --- ### DIABLO CANYON A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K452/606452850.pdf?ref=calregulatory.com) grants in part the [Alliance for Nuclear Responsibility](https://a4nr.org/?ref=calregulatory.com) petition to modify a 2024 decision ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K462/550462685.PDF?ref=calregulatory.com)) approving $722.6 million in cost recovery for extended operations at Diablo Canyon. The sole modification: for purposes of the 115% statutory threshold under the Public Utilities Code, the CPUC will use the final Resource Adequacy Market Price Benchmark rather than the forecast benchmark when evaluating whether Diablo Canyon costs remain insulated from further reasonableness review. The change applies to all Diablo Canyon forecast proceedings through 2030. The threshold matters because costs below 115% of forecast are shielded from additional review under [Senate Bill 846](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220SB846&ref=calregulatory.com)'s expedited framework. The forecast 2025 RA Market Price Benchmark was **$42.54/kW-month**. The final benchmark, recalculated after methodology reforms adopted in a 2025 decision ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)), fell to **$11.21/kW-month**. The Alliance for Nuclear Responsibility argued that embedding the higher forecast value into the statutory baseline artificially widened the cushion beneath the threshold, shielding operating costs from scrutiny the statute did not intend to foreclose. PG&E supported the modification but argued it should apply uniformly across all Diablo Canyon forecast years rather than 2025 alone. The decision adopts PG&E's position. The decision denies everything else. No revenue requirement is revised. No prior findings are reopened. Forecast-to-final benchmark differences have already flowed into rates through the ERRA-style true-up process. **INSTANT ANALYSIS:** By requiring the final RA Market Price Benchmark rather than the forecast benchmark for the 115% statutory threshold test, the decision reduces the forecast-driven cushion between actual costs and the point at which additional scrutiny could return. In 2025, the difference is substantial: $11.21/kW-month final versus $42.54 forecast. Applied to every Diablo Canyon extended-operations forecast proceeding through 2030, this is a standing rule, not a one-year accounting correction. --- ### CRUDE OIL TRANSPORTATION A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K439/606439113.pdf?ref=calregulatory.com) in [A.25-06-026](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M571/K129/571129244.PDF?ref=calregulatory.com) authorizes a **10%** rate increase for Crimson California Pipeline L.P.'s Southern California crude oil system, effective August 1, 2025, while rejecting the company's later attempt to reach a 13.16% increase. Crimson operates about 300 miles of crude oil pipelines connecting Southern California oil fields to Los Angeles Basin refineries. The decision finds the 10% request justified, concluding the higher rates support reasonable, reliable, and safe operations while bringing Crimson's test-year return on equity to 10.82%. The decision also authorizes retroactive recovery to August 1, 2025, allowing Crimson to collect the difference between billed and approved rates plus interest at the 90-day commercial paper rate. The decision denies Crimson's January 2026 miscellaneous filing seeking an additional 3.16%. --- **INSTANT ANALYSIS**: For California refiners and crude shippers, the key takeaway is this: the CPUC will approve a full 10% mid-cycle pipeline rate increase on a basic financial showing when no opposition emerges (no protests were filed in this proceeding). Retroactive recovery to August 2025 preserved Crimson's economics despite the delayed approval, reinforcing Section 455.3 as a workable ratemaking pathway for operators facing rising costs. --- ### DELAYED ITEMS *At the behest of *President John Reynolds*, the CPUC delayed action on a* [*proposed decision*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536932.PDF?ref=calregulatory.com) *that implements California's Shared Renewables Portfolio. CRI's full summary of this item is available* [*here*](https://www.calregulatory.com/may-14-cpuc-voting-meeting-preview-pg-e-ng-peak-day-reset-1-95b-woolsey-securitization-diablo-cost-threshold-shift/)*. The item is now tentatively scheduled for consideration on *June 11*.* ### CAISO Files Final 2027 Local Capacity Technical Report: the Bay Area Enters 2027 With Just 198 MW of Margin URL: https://www.calregulatory.com/caiso-files-final-2027-local-capacity-technical-report-the-bay-area-enters-2027-with-just-198-mw-of-margin/ Last updated: 2026-05-13T20:46:27.000Z The CAISO filed its [Final 2027 Local Capacity Technical Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K453/606453746.PDF?ref=calregulatory.com) in the CPUC's Resource Adequacy docket. *(See CRI's coverage of the Draft Report* [*here*](https://www.calregulatory.com/wednesday-aggregate-20/?ref=california-regulatory-intelligence-newsletter)*.)* [CAISO: LA Basin Capacity Is Getting More ExpensiveTotal local capacity requirements in California will increase by approximately 602 MW (2.6%) from 2026 to 2027, reaching 23,618 MW…![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-78.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/resized.jpg)](https://www.calregulatory.com/wednesday-aggregate-20/?ref=california-regulatory-intelligence-newsletter) The final report makes no modifications to the draft document. The most notable number is **23,618 MW** in statewide local capacity requirements for 2027, a net increase of **602 MW**, or **2.6%**, from the 2026 requirement of 23,016 MW. The largest increases concentrate in four areas. - The LA Basin climbs from 5,812 MW to **6,823 MW**, a **1,011 MW** increase driven by load growth and the re-rating of bulk transmission facilities. - The Bay Area rises from 7,558 MW to **8,315 MW**, leaving only 198 MW of margin between local reliability needs and available qualifying capacity. - The Sierra increases from 1,354 MW to **1,892 MW**, while Humboldt edges up from 136 MW to **149 MW**. The Bay Area and LA Basin account for most of the statewide increase. Elsewhere, requirements move lower. - Big Creek/Ventura drops from 1,369 MW to **704 MW**, a **665 MW** decline tied to revised load forecasts and changes to the limiting contingency. - San Diego/Imperial Valley falls from 2,631 MW to **2,006 MW**, while North Coast/North Bay declines from 848 MW to **592 MW**. - Stockton, Kern, and Greater Fresno post smaller reductions. Five areas remain resource-deficient: Sierra; Stockton; Greater Bay; Greater Fresno; and Kern. Under a 1-in-10-year summer peak, these regions could face immediate load shedding following a first contingency if sufficient local resources are unavailable. These are not new vulnerabilities, but the long-term trajectory worsens. By 2031, the CAISO projects statewide local capacity needs rising to **26,271 MW**, an increase of **2,653 MW** over 2027 levels. Greater Fresno stands out, with requirements increasing **46%** to **3,060 MW**. The Bay Area remains fixed at 8,315 MW through 2031, but the margin against available resources stays narrow enough that any retirement or qualifying-capacity downgrade could carry immediate reliability consequences. The LA Basin rises further to **8,017 MW** by 2031, an **18%** increase in four years. The battery storage discussion carries a forward-looking message. The CAISO again warns that storage is not a one-for-one substitute for thermal local reliability unless charging constraints are properly accounted for. The CAISO is demonstrating a continued willingness to invoke backstop procurement authority if load-serving entity portfolios rely too heavily on storage resources that cannot reliably recharge under stressed transmission conditions. For storage developers, aggregators, and LSEs structuring local Resource Adequacy contracts, duration assumptions and charging access during contingencies are as consequential as nameplate MW. On flexible capacity, CAISO published its draft 2027 Flexible Capacity Needs Assessment on March 31, held a stakeholder meeting on April 2, and received no comments. The final filing is targeted for **May 15**, completing the flexible Resource Adequacy obligations that will sit alongside these local procurement requirements for 2027. **INSTANT ANALYSIS:** This filing tells a procurement story with three figures: +1,011 MW in the LA Basin; +757 MW in the Bay Area; and -665 MW in Big Creek/Ventura. Those numbers point to a market where Southern California obligations continue to climb while select constrained areas elsewhere loosen, creating increasingly different contracting conditions by local area. The LA Basin increase deserves particular attention because part of the change stems from transmission re-ratings rather than load growth alone. Higher demand can be addressed through procurement. Reduced import capability is different. It limits what the system can rely on from outside the basin, increasing dependence on local resources and narrowing the room for procurement alone to solve the problem. The Bay Area may be the most exposed position in the study. A **198 MW** buffer between the LCR requirement and available qualifying capacity is thin by any standard. Any thermal retirement, qualifying-capacity revision, or resource reclassification between now and **June 1, 2027** falls directly on that margin. For planning purposes, LSEs with Bay Area obligations should treat the current margin as effectively zero. Greater Fresno also deserves more attention. A **46%** increase in local reliability needs by 2031 is not a marginal shift. It suggests a region moving toward significantly greater procurement dependence while already operating in a resource-deficient condition. Lead times for local resource development in the San Joaquin Valley are measured in years, not months. Decisions being made for 2027 will likely be revisited under considerably tighter conditions by the end of the decade. On storage, the CAISO has now repeated its charging-constraint warning through multiple study cycles. At some point repetition becomes policy intent. LSEs and developers counting local RA value from storage resources without contingency-constrained recharge assumptions are building portfolios that CAISO has already indicated it may not accept as sufficient. The backstop authority reference is not theoretical. CAISO is laying out the circumstances under which it may use it. ### WEDNESDAY AGGREGATE: An Electric Rate Reset Begins; New Diablo Canyon Cost-Recovery Disputes; and LSE Over-Procurement? URL: https://www.calregulatory.com/wednesday-aggregate-26/ Last updated: 2026-05-13T18:29:06.000Z In today's briefing: - Multiple parties react to the CPUC's ambitious new rate-design docket; - PG&E responds to a stern letter from CPUC **President John Reynolds**; - PG&E responds to protests of its latest Diablo Canyon cost-recovery request; - CalCCA asks the CPUC to consider whether staff is understating excess RA capacity under the Slice-of-Day framework and forcing LSEs into unnecessary over-procurement; and - A new proposed decision resolves Phase 2 of [I.19-06-014](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M306/K870/306870841.PDF?ref=calregulatory.com), the CPUC's examination of whether safety failures at SoCalGas (beginning with the [2015 Aliso Canyon leak](https://en.wikipedia.org/wiki/Aliso%5FCanyon%5Fgas%5Fleak?ref=calregulatory.com)) stem from organizational deficiencies. _This post is for subscribers only._ ### Rule 30: Partial Settlement Opens Early View Into Large Loads as Parties Push Data-Center Cost Responsibility URL: https://www.calregulatory.com/rule-30-partial-settlement-opens-early-view-into-large-loads-as-parties-push-data-center-cost-responsibility/ Last updated: 2026-05-12T20:22:33.000Z ## **Rule 30 Settlement** PG&E, Cal Advocates, CalCCA, and Sierra Club filed a [joint motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K273/606273116.PDF?ref=calregulatory.com) asking the CPUC to approve a partial settlement in [PG&E's Electric Rule 30](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com) proceeding, which governs transmission-level retail electric service for large customers seeking direct transmission interconnection. _This post is for subscribers only._ ### MONDAY NEWS CODEX: EDAM Launch; Golden State Wind; Carbon-Free Pasadena URL: https://www.calregulatory.com/monday-news-codex-edam-launch-golden-state-wind-carbon-free-pasadena/ Last updated: 2026-05-12T00:09:53.000Z - **Battery Array as Powerful as 12 Nuclear Plants Hits Major Milestone in California:** "While Californians were getting ready for spring break in late March, the state quietly broke an energy grid record: For the first time, its battery fleet discharged more than 12,000 megawatts of power, roughly the output of 12 large nuclear plants." [**YAHOO NEWS**](https://www.yahoo.com/news/articles/battery-array-powerful-12-nuclear-033000047.html?ref=calregulatory.com) - **CAISO Picks California Grid Holdings to Build 500-kV Tx Line:** "The ISO estimates the project will cost $500 million to $700 million and will be online by June 1, 2034, according to its 2024/2025 transmission [*plan*](https://www.caiso.com/documents/appendix-i-description-and-functional-specifications-for-transmission-facilities-eligible-for-competitive-solicitation.pdf?ref=calregulatory.com)." [**RTO INSIDER**](https://www.rtoinsider.com/131814-caiso-chooses-california-grid-holdings-building-700m-tx-line/?ref=calregulatory.com) - **California Seeks Preliminary Injunction to Stop Sable Pipeline Restart:** "California [filed a motion for a preliminary injunction](https://oag.ca.gov/news/press-releases/attorney-general-bonta-seeks-halt-trump-administration%E2%80%99s-illegal-greenlight-oil?ref=calregulatory.com) to stop Sable Offshore Corp.’s restart of the Las Flores Pipeline System serving the offshore Santa Ynez Unit. California Attorney General Rob Bonta filed the [motion](https://oag.ca.gov/system/files/attachments/press-docs/Sable%20PI.pdf?ref=calregulatory.com) on May 1, 2026, asking the court to revoke the [federal order](https://www.californiaenergytransition.com/p/trump-administration-directs-sable?ref=calregulatory.com) to restart the pipeline and to block the transportation of oil through the pipeline system. The pipeline, which was shut down following the 2015 Refugio oil spill, is critical to restarting oil production in the Santa Ynez Unit." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-seeks-preliminary-injunction?ref=calregulatory.com) - **California Subpoenas Golden State Wind Over Trump Lease Deal:** "The California Energy Commission is investigating the deal that Golden State Wind made with the U.S. Department of the Interior to [surrender a wind lease off the coast of California](http://www.energy.ca.gov/sites/default/files/2026-05/CEC%5FSubpoena%5Fto%5FGolden%5FState%5FWind.pdf?ref=calregulatory.com) in exchange for a payment from the federal government, and it anticipates litigation, according to letters and a subpoena the commission released..." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-subpoenas-golden-state-wind-over-trump-lease-deal/819329/?ref=calregulatory.com) - **Trump Administration Gets Strategic With Offshore Wind:** "...How much were these projects going to cost the taxpayers in tax credits over their lifetimes? There would have been an investment tax credit of 30% on the amount invested. At a reported investment amount of about $3 billion for Bluepoint Wind and as much as $20 billion for Golden State Wind, investment tax credits could have been as much as about $7 billion. Production tax credits at 2.6 cents per kWh could have been additional billions. And this for intermittent power that could not have replaced any of the existing dispatchable capacity." [**MANHATTAN CONTRARIAN** ](https://www.manhattancontrarian.com/blog/2026-5-10-trump-administration-gets-strategic-with-offshore-wind?ref=calregulatory.com) - **Trump's Wasteful Deal to Abandon California Offshore Wind Project Undermines Clean, Homegrown Power:** "California is the only West Coast state with offshore wind leases. One of those five leases, the Golden State Wind project, was expected to generate enough power for [about 1.1 million homes](https://goldenstatewind.com/?ref=calregulatory.com). Canceling it does not just remove a major source of clean electricity — it also puts significant economic benefits at risk. The project was set to deliver $24 million for workforce training and to build out a domestic supply chain — funding the state has already committed — with the offshore wind industry in California projected to [create roughly 8,000 high road jobs](https://slcprdwordpressstorage.blob.core.windows.net/wordpressdata/2023/07/AB525-Workforce-Readiness-Plan%5Facc.pdf?ref=calregulatory.com)." [**ENVIRONMENTAL DEFENSE FUND**](https://www.edf.org/media/trump-administrations-wasteful-deal-abandon-california-offshore-wind-project-undermines-clean?ref=calregulatory.com) - **Can Oil Industry Lawsuits Compel Rational Energy Policy?** "The most consequential of the cases filed by oil industry interests are those that challenge [Senate Bill 1137](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220SB1137&ref=calregulatory.com), which requires oil wells to be located at least 3,200 feet from any human occupied structure, what they deem to be a 'sensitive receptor.' Within these 'health protection zones,' no new wells may be drilled, and only minimal work may be done to maintain existing wells. This effectively kills oil production in all but the most remote and uninhabited areas of the state. It is also an exercise in absurdity, since California’s oil wells are strictly regulated and emit negligible quantities of methane and volatile organic compounds, whereas upwelling reserves of underground gas and oil [leak naturally to the surface](https://californiainsider.com/california-news/videos/california-insider-show/berkeley-professor-reveals-that-drilling-oil-in-california-might-be-good-for-the-environment-james-rector-5895717?ref=calregulatory.com) in prodigious quantities thanks to California’s seismically active geology. The *only* way to stop this leakage is to deplete the reservoirs with drilling and extraction." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-can-oil-industry-lawsuits-compel-rational-energy-policy/?ref=calregulatory.com) - **EDAM is "Solid and Stable" So Far, Says CAISO:** "EDAM launched with a single participant, PacifiCorp, with its second participant Portland General Electric set to join the market in October. On Monday, all EDAM areas passed 100% of the market’s resource sufficiency evaluation, and the regional energy transferred increased to 600 MW..." [**UTILITY DIVE**](https://www.utilitydive.com/news/edam-is-solid-and-stable-so-far-says-caiso/819579/?ref=calregulatory.com) - **"Just the Beginning" – CAISO's Mainzer Talks About EDAM Launch:** "EDAM will be the first day-ahead market to start operations in a Western Interconnection that has long resisted the development of organized electricity markets. [SPP](https://www.rtoinsider.com/category/rto/rto-spp/?ref=calregulatory.com)’s Markets+ is scheduled to follow in fall 2027." [**RTO INSIDER**](https://www.rtoinsider.com/130940-just-the-beginning-caiso-mainzer-talks-about-edam-launch/?ref=calregulatory.com) - **Electric Truck Fleets Could Push Down Residential Rates by 2035 - Report:** "Electrified medium- and heavy-duty trucking fleets could [reduce residential electric rates](https://www.pactcoalition.org/news-resources/electric-rate-impacts-of-medium-and-heavy-duty-vehicle-electrification-investments?ref=calregulatory.com) up to $20 per year in northern California by 2035, according to a new report funded by Powering America’s Commercial Transportation and the Edison Electric Institute." [**UTILITY DIVE**](https://www.utilitydive.com/news/electric-truck-fleets-could-push-down-residential-rates-by-2035-report/819590/?ref=calregulatory.com) - **Electric Rate Impacts of Medium- and Heavy-Duty Vehicle Electrification Investments:** "In the main scenario using ACC-based marginal costs, MHDV electrification applies downward pressure on average residential rates in both 2028 and 2035, as increased sales outweigh incremental costs. However, when higher distribution costs derived from PG&E’s Electrification Impact Study (EIS Part 2) are applied, electrification produces upward rate pressure in 2028 and in 2035 under unmanaged charging, while managed charging returns downward pressure by 2035." [**PACT**](https://static1.squarespace.com/static/654ac8c6868b1b03737e37dd/t/69f8b9ef8f8b946e8f199df4/1777908207762/E3+Electric+Rate+Impacts+of+MHD+Vehicle+Electrification+Investments+%282%29.pdf?ref=calregulatory.com) - **For California Farmers, a Clean-Energy Dilemma:** "After a battery-storage fire last year, farmers are raising concerns about a new facility in Watsonville, California, near prime farmland. " [**CIVIL EATS**](https://civileats.com/2026/05/11/for-california-farmers-a-clean-energy-dilemma/?ref=calregulatory.com) - **Industry Groups Seek Greater Role in Alternative Western RA Program:** "Development of the alternative resource program is picking up pace and stakeholders want to ensure they have a say in how the effort evolves." [**RTO INSIDER**](https://www.rtoinsider.com/131900-industry-groups-seek-greater-role-alternative-western-ra-program/?ref=calregulatory.com) - **Pasadena's Path to 100% Carbon-Free Electricity:** "Pasadena’s system presents a distinctive planning challenge. The City relies heavily on energy imports through a single transmission interconnection with the broader California grid and so has local generation to maintain reliability during peak demand or during grid contingencies. Physical space for new infrastructure within the city is limited, so distributed solutions rather than more centralized projects play a big role in meeting the city’s local generation needs. These constraints make Pasadena a useful case study in how local conditions shape the clean energy transition." [**E3**](https://www.ethree.com/pasadena-carbon-free/?ref=calregulatory.com) - **Refinery Closures Increase California's Reliance on Fuel Imports**: "While imports are increasing the cost of gasoline in California, most of the difference between U.S. average national gas prices and California’s average price is due to policies and regulations that lawmakers in the state have instituted, many in the name of climate change. They include the highest state gas tax in the nation at [$0.709 per gallon](https://taxfoundation.org/data/all/state/gas-taxes-state/?ref=calregulatory.com) and [hidden fees](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/gasoline-prices-are-generally-lower-in-red-states/?ref=calregulatory.com) that result from a cap-and-trade program to lower greenhouse gas emissions, a low-carbon fuel program, underground gas storage fees, and a state and local sales tax, which all add to the price of gasoline." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/international-issues/refinery-closures-increase-californias-reliance-on-fuel-imports/?ref=calregulatory.com) ### CRI Rate Change: $75/Month URL: https://www.calregulatory.com/cri-operations-update-2/ Last updated: 2026-05-11T20:12:22.000Z CRI is implementing a new pricing model of[**$75/month**](https://www.calregulatory.com/#/portal/signup/6a023109c799620001352e52/monthly) for everyone. **The goal is simple:** fewer emails, less procedural volume, and a greater focus on developments that matter. We will continue to analyze consequential developments in the California regulatory sector, including: - Major rate changes affecting core and noncore customers; - General Rate Case filings and cost-allocation proceedings; - Significant proposed decisions and draft resolutions; - Final decisions and resolutions with major operational or financial implications; - Framework changes involving areas such as Demand Response, Resource Adequacy, Integrated Resource Planning, and Long-Term Gas Planning; and - Actions that move markets. If you have benefited from CRI, we encourage you to **sign up** at the new [**$75/month**](https://www.calregulatory.com/#/portal/signup/6a023109c799620001352e52/monthly) rate. Thank you to everyone who has followed the project over the past seven months. For firm or group access, please contact [**info@calregulatory.com**](mailto:info@calregulatory.com). Sincerely, [**Michael Cade**](https://www.linkedin.com/in/mikecade/?ref=calregulatory.com) *CRI Founder/Principal Analyst* ### FRIDAY AGGREGATE: Direct Access Conflicts Reignite as California Load Growth Accelerates URL: https://www.calregulatory.com/friday-aggregate-4/ Last updated: 2026-05-08T19:39:33.000Z Today's briefing: - A new Direct Access battleground has emerged; - The Sempra Utilities unveil a $348 million enterprise system migration; - Winter gas bill shocks have become a cost-deferral exercise; - The fee structure for Core Transport Agents is affirmed; and - Fixed avoided-cost rates are proposed for small renewable generators. --- ### DIRECT ACCESS On May 6, parties filed responses to a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K025/604025685.PDF?ref=calregulatory.com) filed by the Alliance for Retail Energy Markets et al on April 6\. The petition seeks to reverse a 2021 CPUC decision ([D.21-06-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K215/390215673.PDF?ref=calregulatory.com)) and have the CPUC recommend the Legislature lift the statutory cap on non-residential Direct Access enrollment. Recall that D.21-06-033 recommended that the Legislature **not** expand Direct Access any further. The decision reasoned that “*expansion of Direct Access to all non-residential customers would present an unacceptable risk to the state’s long-term reliability goals.*” --- Utilities, Cal Advocates, and Community Choice Aggregators oppose the PFM but competitive suppliers and large energy users support it. Supporters argue that the CPUC's original reliability and greenhouse gas concerns no longer apply because Electric Service Providers are now subject to the same Resource Adequacy, Integrated Resource Planning, and Renewables Portfolio Standard obligations as other load-serving entities. Opponents argue the petition is procedurally improper, unsupported by sufficient evidence, and risks reliability and cost-shifting if DA load migration accelerates. - Cal Advocates [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K263/606263273.PDF?ref=calregulatory.com) a petition for modification is not the proper vehicle for reversing a major policy determination built on a lengthy evidentiary record. Cal Advocates warns that removing the DA cap could increase procurement uncertainty, complicate long-term resource financing, and shift costs onto remaining bundled customers if lower-cost customers migrate to DA providers. - The three large investor-owned utilities take similar positions. - SDG&E [argues the petition is untimely](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K281/606281534.PDF?ref=calregulatory.com) because the load-based procurement allocation methodology cited as the triggering "new fact" ([D.26-02-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K777/601777006.PDF?ref=calregulatory.com)) is not new at all, tracing directly to [D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com) (issued one day after the DA Decision) and [D.19-11-016](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M319/K825/319825388.PDF?ref=calregulatory.com) (issued six months before it). - SCE [similarly argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K259/606259842.PDF?ref=calregulatory.com) that the impacts of the 2021 decision were foreseeable at the time it was issued and says the petition fails to justify reopening the matter through a modification request rather than a new rulemaking with a full evidentiary record. - PG&E [advances the strongest legal argument](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215403.PDF?ref=calregulatory.com): that [Assembly Bill 1373](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202320240AB1373&ref=calregulatory.com) repealed [Section 365.1(f)](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-365-1/?ref=calregulatory.com) of the Public Utilities Code in 2023, extinguishing the CPUC's statutory authority to issue a new DA recommendation to the Legislature. PG&E also argues the petition improperly seeks new factual determinations on issues (including cost-shifting) that the original decision expressly declined to reach. SCE independently raises the same AB 1373 point. - CalCCA [leads with the same jurisdictional argument](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K259/606259843.PDF?ref=calregulatory.com), contending the CPUC has no further role in making DA recommendations to the Legislature now that Section 365.1(f) is inoperative, and that authority to modify the DA cap rests with the Legislature under current Section 365.1(a). - CalCCA also disputes claims that ESPs are uniquely suited to serve emerging large loads such as data centers, noting that IOUs and CCAs already serve those customers and can structure dedicated contracts in the same way. CalCCA further argues that ESPs continue to lag behind utilities and CCAs in clean energy procurement and new resource development despite now operating under equivalent procurement frameworks. Supporters framed the issue as a mismatch between modern procurement obligations and outdated enrollment limits. - CLECA [argues that California's load-growth outlook has shifted fundamentally since 2021](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K263/606263274.PDF?ref=calregulatory.com) (driven by data centers, electrification, and EV charging) and that the DA cap now constrains industrial customer siting decisions, accelerates emissions leakage as energy-intensive businesses locate outside California, and imposes costs on existing DA customers for load they are legally barred from serving. CLECA cites EIA data showing California's industrial electricity rates have diverged dramatically from neighboring states since 2021, giving the affordability argument an evidentiary foundation the other supporters lacked. - [Commercial Energy of California](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215436.PDF?ref=calregulatory.com) and [3 Phases Renewables](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K259/606259844.PDF?ref=calregulatory.com) support lifting the cap on the same IRP-mismatch theory: ESPs now carry procurement obligations tied to anticipated load growth while remaining legally prohibited from serving most of that load. Both characterize this as an improper cost shift onto existing DA customers and argue the reliability and emissions concerns underlying the original decision are outdated given current regulatory oversight and compliance performance. **INSTANT ANALYSIS:** The proceeding is evolving into a battleground over who gets to serve California's next wave of load growth and who pays for the procurement tied to it. The DA parties are reframing Direct Access from a legacy deregulation issue into a modern load-accommodation tool for data centers, electrification, and industrial expansion. Their main argument is simple: ESPs now carry the same procurement and reliability obligations as utilities and CCAs, yet remain legally constrained from serving much of the load driving those obligations. The underlying concern of the opposing parties is migration risk. If the DA cap disappears during a period of accelerating load growth and rising bundled-service rates, large industrial and commercial customers could increasingly seek competitive supply arrangements, leaving utilities and CCAs with a more expensive residual customer base and more difficult procurement planning assumptions. The developing flashpoint is significant: will California's future large-load growth remain utility-and-CCA anchored or become more contestable? --- ### UTILITY OPERATIONS/ENTERPRISE SYSTEMS SoCalGas and SDG&E filed a **$348 million** [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K875/605875125.PDF?ref=calregulatory.com) seeking CPUC authorization to migrate their enterprise resource planning systems to [SAP S/4HANA](https://www.sap.com/products/erp/s4hana/trial.html?ref=calregulatory.com) before SAP terminates support for the legacy platform at the end of 2027\. The utilities frame the request as non-discretionary, characterizing Enterprise Resource Planning as the "central nervous system" of operations supporting more than 11,000 users, 57 million monthly transactions, and over 400 business processes spanning finance, procurement, inventory, and emergency response. The proposal builds on $51.2 million already authorized in the Sempra Utilities' prior General Rate Case for Phase 1A, which migrates the core platform and is expected to complete by **May 2027**. Phase 1B adds O&M activities, including data migration and organizational change management. Phase 2 migrates connected systems, analytics platforms, and FERC reporting infrastructure. Total program cost reaches approximately $348.1 million through 2030\. Peak residential bill impacts are estimated between **0.2%** and **0.8%**. An [accompanying motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874947.PDF?ref=calregulatory.com) requests immediate establishment of SAP Migration Memorandum Accounts to track approximately **$13.7 million** in Phase 1B O&M costs before a final Commission decision, which is not expected until mid-2027\. The utilities request retroactive effectiveness to the May 1 application filing date. Illustrative rate changes for SoCalGas customers are noted below. | Customer Class | Proposed Rate Increase (¢/th) | Percentage Rate Increase (%) | | --------------------------------------------- | ----------------------------- | ---------------------------- | | Residential | 1.133 ¢ 1.133 ¢ 1.133¢¢ | 0.8% | | Commercial | 0.665 ¢ | 0.7% | | Natural Gas Vehicles | 0.223 ¢ | 0.6% | | Large Industrial (distribution level service) | 0.142 ¢ | 0.5% | | Large Industrial (transmission level service) | 0.042 ¢ | 0.5% | | System Average Rate | 0.414 ¢ | 0.6% | Illustrative SDG&E electric rates are noted below, followed by illustrative SDG&E gas rates. | Customer Class | Proposed Rate Increase ( ¢ / kWh ¢ / kWh ¢//kWh¢ ) | Percentage Rate Increase (%) | | ----------------------------- | -------------------------------------------------- | ---------------------------- | | Residential | 0.117 ¢ | 0.3% | | Small Commercial | 0.101 ¢ | 0.3% | | Medium Commercial | 0.058 ¢ | 0.2% | | Large Commercial & Industrial | 0.055 ¢ | 0.1% | | Agricultural | 0.053 ¢ 0.053 ¢ 0.053¢¢ | 0.2% | | Lighting | 0.046 ¢ | 0.2% | | System Total | 0.079 ¢ | 0.2% | | Customer Class | Proposed Rate Increase (¢/th) | Percentage Rate Increase (%) | | --------------------------------------------- | ----------------------------- | ---------------------------- | | Residential | 2.314 ¢ | 1.1% | | Commercial | 0.674 ¢ 0.674 ¢ 0.674¢¢ | 0.8% | | Natural Gas Vehicles | 0.225 ¢ | 0.7% | | Large Industrial (distribution level service) | 0.246 ¢ | 0.6% | | Large Industrial (transmission level service) | 0.042 ¢ | 0.5% | | System Average Rate | 0.954 ¢ | 1.0% | Protests are due **June 4**. **INSTANT ANALYSIS**: This is a back-office reliability case built to survive a Commission that is nominally hostile to discretionary spending. The retreat from transformation to migration is deliberate, scoped to the minimum necessary to avoid operating an unpatched platform after **January 1, 2028**. The memorandum account motion is revealing. The migration timeline has outrun the regulatory calendar and the utilities need retroactive ratemaking protection before Phase 1B spending begins. Authorization does not guarantee recovery; every dollar will face prudence and reasonableness review --- ### NATURAL GAS PRICE SPIKES PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5212-G.pdf?ref=calregulatory.com) implementing [D.26-02-058](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K862/601862088.PDF?ref=calregulatory.com)'s mandate to cap monthly Core Procurement Charges for all five core customer classes: Residential; Residential NGV; Small Commercial; Large Commercial; and Natural Gas Vehicles, when winter gas prices exceed 150% of the 10-year average for the same month (November through March). The cap operates by freezing the Weighted Average Cost of Gas component across all classes at the level that holds the Core Procurement Charge increase to that threshold. Any undercollection must be amortized into rates within nine months and cannot carry into the following winter season. The cap itself cannot exceed three months. Two benchmark design rules prevent the 10-year average from drifting upward: prior spike-event months and prior undercollection amortizations are both excluded from the rolling calculation. Within one business day of identifying a qualifying event, PG&E will notify customers through its monthly Gas Core Procurement Rate Change advice letter. Protests are due **May 21**. **INSTANT ANALYSIS**: The CPUC has converted winter gas bill shock into a managed cost-deferral exercise. Extreme procurement costs no longer flow through to customers in real time during crisis months. They get redistributed across the following nine months instead. The benchmark exclusions are the mechanism's critical design choice. Without them, repeated volatility events would ratchet the 10-year average upward and weaken the protection over successive winters. The filing ultimately expands PG&E's administrative discretion. PG&E determines when a qualifying event has occurred, when the cap activates, and how deferred balances amortize. These are questions D.26-02-058 does not resolve and this advice letter does not address. The more macro takeaway: California's gas system remains acutely exposed to winter commodity volatility, electrification trajectory notwithstanding. A formal emergency Core Procurement Charge cap is institutional acknowledgment that severe winter price dislocation is a recurring credible risk, not a resolved one. --- ### CORE TRANSPORT AGENTS A [proposed CPUC resolution](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K217/606217134.PDF?ref=calregulatory.com) (Draft Resolution G-3621) reaffirms the annual fee structure for California Core Transport Agents, the non-utility gas suppliers serving residential and small commercial customers. The draft resolution retains the framework from a previous resolution ([Resolution G-3597](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M509/K545/509545115.PDF?ref=calregulatory.com), 2023) without introducing new fee design. Each registered CTA pays a **$5,000** base fee, with variable fees assessed only against companies that generated complaints or faced unauthorized enrollment investigations and enforcement activity in 2025. The CPUC grounds the structure in [Senate Bill 656](https://www.leginfo.ca.gov/pub/13-14/bill/sen/sb%5F0651-0700/sb%5F656%5Fcfa%5F20130628%5F170107%5Fasm%5Fcomm.html?ref=calregulatory.com) and a 2018 decision ([D. 18-02-002](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M209/K856/209856533.pdf?ref=calregulatory.com)), which expanded CTA oversight after years of deregulated gas procurement. With 39 registered CTAs and 36 active participants, the CPUC argues the market is mature enough that higher fees pose no meaningful barrier to entry. Fixed administrative costs rose **34%** in 2025 but remain within the tolerance band established in G-3597, so the base fee remains at $5,000\. The more notable development is complaint volume, which surged **75%** over the prior year. Unauthorized enrollment complaints reviewed by the CPUC's Utility Enforcement Branch rose nearly as much, even as formal enforcement actions fell by more than half. The complaint surge produces wide fee dispersion. [Wave Energy](https://waveenergyservices.com/?ref=calregulatory.com) faces the largest total assessment at approximately $206,000\. [SFE Energy](https://www.sfeenergy.com/california/?ref=calregulatory.com) exceeds $118,000\. BP Energy, Shell, and Calpine each pay only the $5,000 base fee, having generated no complaints or enforcement activity. The earliest the CPUC will consider this matter is **June 11**. **INSTANT ANALYSIS:** This draft resolution further embeds complaint-driven cost allocation as the basis of California's retail gas oversight regime. CTAs with persistent enrollment and marketing problems are funding a growing share of CPUC enforcement infrastructure, while operators with clean complaint records pay only the administrative floor. The draft resolution does not propose market reforms or stricter registration standards, but the staffing expansion suggests that the CPUC expects elevated oversight demands to persist. --- ### ReMAT PRICE UPDATE The CPUC issued a draft resolution updating fixed avoided-cost rates for California's [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), a feed-in tariff for small renewable generators at (or below) **3 MW**. PG&E, SCE, and SDG&E would have 30 days from the effective date to amend their tariffs. The 2026 rates reflect a weighted average of Renewable Portfolio Standard contracts executed 2020–2025 for projects 20 MW or smaller: | Product Category | 2025 | 2026 | Change | | ------------------------ | ------ | ------ | ------- | | As-Available Non-Peaking | $52.85 | $58.38 | +$5.53 | | As-Available Peaking | $67.99 | $67.40 | \-$0.59 | | Baseload | $75.96 | $92.33 | +$16.37 | The 43-contract pricing dataset is heavily weighted toward CCA-procured solar PV in Los Angeles County, including a substantial [Prologis](https://www.prologis.com/?ref=calregulatory.com) rooftop portfolio. The baseload category draws almost entirely on Nevada geothermal. A confidential geothermal contract executed in 2025 is the only new baseload entry (the most plausible driver of the $16.37 increase, though the draft resolution does not say so explicitly). As of February 2026, the program totals **65 contracts** and approximately **112 MW** since inception. **INSTANT ANALYSIS:** The baseload rate eclipsing **$92/MWh** confirms that firm renewable capacity (geothermal above all) commands a widening premium over intermittent resources in California's small-scale procurement market. The near-flat peaking price tells the opposite story: CCA solar has saturated that category to the point where new contracts move the weighted average almost nothing. CCAs now dominate the RPS contract dataset that sets these rates. The avoided-cost benchmark for small QFs is increasingly a CCA-derived number, not a utility one (a shift with long-term implications for how ReMAT prices reflect actual utility procurement costs). ### PG&E Reports $4.05 Billion Above Capital Forecast in Risk-Spending Accountability Filing URL: https://www.calregulatory.com/pg-e-reports-4-05-billion-above-capital-forecast-in-risk-spending-accountability-filing/ Last updated: 2026-05-07T19:33:56.000Z PG&E filed its 2025 Risk Spending Accountability Report in three dockets: its 2023 General Rate Case ([A.21-06-021](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M389/K956/389956574.PDF?ref=calregulatory.com)), 2024 RAMP ([A.24-05-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M531/K552/531552896.PDF?ref=calregulatory.com)), and pending GRC ([A.25-05-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com)). The 362-page filing compares CPUC-authorized spending against actual 2025 spending, with cumulative comparisons across 2023-2025. The numbers are very large. 2025 expenses ran **$650 million** (10%) above adopted; capital ran **$4.05 billion** (57% ) above adopted in a single year. At the 2/3 mark of the four-year cycle, cumulative capital spending now stands **$6.55 billion** above the amount the CPUC authorized. Electric Distribution drives the expense overrun (**$294 million**) on Major Emergency response, overhead maintenance, vegetation management, and inspections. Companywide Items overran **$550 million** on employee benefits and incentive compensation that PG&E argues were under-funded in the 2023 GRC. Customer & Communications was **$55 million** over. Capital is dominated by three concentrations. - Electric Distribution capital ran **$2.43 billion** over on emergency work, pole replacements, overhead maintenance, and SB 410 customer connections. - Shared Services and IT capital ran 191% over (**$1.33 billion**) driven by the final purchase price for the Oakland General Office campus, the Propel program modernizing PG&E's enterprise resource planning system (SAP), and unplanned Oakland General Office physical security. - Power Generation capital ran **64%** over on emergent and rescheduled hydro work concentrated at Fordyce, Pit 3, Spaulding, Helms, and other named facilities, partly masked by FERC license renewal delays at Drum-Spaulding and McCloud-Pit. Gas operations moved in the opposite direction: PG&E underspent **$148 million** on Gas Distribution expenses and **$101 million** under on Gas Transmission and Storage. Meter protection moved from expense to capital, leak detection shifted activity codes, and Transmission Integrity Management Program work shifted to alternative assessment methods. PG&E's High-Pressure Regulator replacement program received zero 2023 GRC funding but Gas Operations spent **$56 million** on it cycle-to-date because it was deemed important. ### INSTANT ANALYSIS The GRC envelope has decoupled from actual spending. What a GRC authorizes increasingly functions as the floor; what gets spent is determined by balancing-account flexibility. The Oakland General Office concentration is the clearest example. Ratepayers are simultaneously funding the building purchase, SAP modernization, and unplanned physical-security investments, none of which were accurately presaged by the 2023 GRC. The High-Pressure Regulator program carries the same implication. The CPUC authorized zero funding, yet millions were spent anyway after Gas Operations deemed the work important. Power Generation overruns tell a parallel story inside the hydro fleet: aging facilities are generating emergent capital needs that are partially masked by delayed FERC license renewals. PG&E's stance is that the 2023 GRC was underfunded across multiple categories, including employee benefits that the CPUC reduced in the last case. Every cost overrun documented here becomes evidence in the 2027 GRC that prior forecasts were insufficient. ### RELATED LINKS - [PG&E's RSAR](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K266/606266330.PDF?ref=calregulatory.com) - [The CPUC's new Risk-Based Decision Making OIR](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com) CRI's coverage of the new RDF rulemaking: [Biomethane Cut, Hydrogen Denied, Transmission FinancingThe CPUC’s April 30 voting meeting featured major moves on biomethane, hydrogen, transmission, electric rates, and risk-based decision-making.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-30-2026--48-.png)](https://www.calregulatory.com/april-30-cpuc-voting-meeting-results-biomethane-cut-hydrogen-denied-transmission-financing-opens/) ### WEDNESDAY AGGREGATE: 957 MMcfd or 2,700 MMcfd — Whose Aliso Canyon Supply Numbers are Correct? URL: https://www.calregulatory.com/wednesday-aggregate-25/ Last updated: 2026-05-06T20:56:38.000Z Today's briefing looks at: - A continuing round of conflict in the Aliso Canyon Biennial Assessment proceeding; - A new document from SoCalGas that champions underground gas storage as long-duration strategic infrastructure rather than a legacy fossil burden; - Opening briefs on utilities' hydrogen blending demos; - Utility reports suggesting that biomethane remains a compliance artifact with no value as a reliability or decarbonization resource; and - The CAISO's summer outlook assessment. --- ### **ALISO CANYON** Parties filed reply comments in the Aliso Canyon Biennial Assessment proceeding ([A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com)), following a workshop on April 15\. For context, see CRI's summary of parties' April 28 opening comments [here](https://www.calregulatory.com/aliso-canyon/). (Additionally, CRI's briefing on SoCalGas's external outages report is available [here](https://www.calregulatory.com/socalgas-filing-shows-upstream-constraints-keep-pushing-southern-california-to-the-curtailment-edge/).) Reply comments continue a battle over whether California's gas reliability risks are being overstated to preserve storage inventories or understated through optimistic modeling assumptions. The dispute organizes around three variables: peak demand assumptions, Receipt Point Utilization (RPU), and the economic consequences of reducing storage inventories. - Sierra Club continues to push for reduction of Aliso Canyon inventories to approximately **30 Bcf**, arguing Energy Division's workshop analysis showed that 19 of 27 modeled winter 2025-2026 reliability scenarios could maintain service at 44% of current capacity. - Sierra Club attacks SoCalGas's proposal to extend the biennial assessment cycle to five years, pointing to more than **16.8 GW** of expected renewable and battery additions in 2026-2027 and the 2025 biennial assessment's finding that most scenarios no longer require Aliso Canyon inventory by winter 2030-2031\. - On RPU, Sierra Club's key move is citing the CPUC's own [FTI consultant](https://www.fticonsulting.com/?ref=calregulatory.com), whose 2021 analysis concluded that the [Winter Storm Uri](https://en.wikipedia.org/wiki/February%5F13%E2%80%9317,%5F2021%5FNorth%5FAmerican%5Fwinter%5Fstorm?ref=calregulatory.com) RPU drop "is not related to availability of takeaway capacity" and reflected price-driven market behavior rather than physical supply constraint. FTI recommended 95% RPU for its own modeling. Sierra Club argues SoCalGas is improperly redefining RPU as a supply availability metric to manufacture a reliability case that the Commission's own consultant doesn't support. - SoCalGas counters that Energy Division's modeling understates reliability risks through unrealistic RPU assumptions and insufficient outage accounting. SoCalGas cites RPU of **47%** during the 2021 Arctic Blast, **36%** during the 2024 Arctic Blast and 2025 Southwest Winter Storm combined, and **25%** system-wide during[ 2026 Winter Storm Fern](https://www.calregulatory.com/may-14-cpuc-voting-meeting-preview-pg-e-ng-peak-day-reset-1-95b-woolsey-securitization-diablo-cost-threshold-shift/), with Northern Zone supplies hitting **9%** of available capacity during Fern. - SoCalGas argues these figures reflect physical supply constraints, not market behavior, and that Energy Division's assumption of 2,700 MMcfd minimum pipeline supply was contradicted by actual deliveries that fell as low as **957 MMcfd** during the relevant winter. - SoCalGas also defends its maintenance record as compliance-driven rather than evidence of systemic unreliability, and argues that [CalGEM](https://www.conservation.ca.gov/calgem?ref=calregulatory.com) and the CPUC already determined Aliso Canyon is safe to operate in their 2017 Comprehensive Safety Review. - The Indicated Shippers align with SoCalGas's reliability critique while emphasizing two points the summary record tends to underweight. - First, the 44% capacity finding applied to only 19 of 27 modeled scenarios; in the remaining eight scenarios (nearly 30%) more than 44% is required. Standard reliability engineering sizes to worst-case modeled need, not central tendency. - Second, the 2025 Assessment contains no analysis of Unbundled Storage Program consequences from an inventory reduction. The Shippers argue this omission alone makes the assessment methodology insufficient for decision-making on just and reasonable rates. **INSTANT ANALYSIS:** This proceeding is developing around two incompatible frameworks. Sierra Club's position is legal and methodological: it argues that the Commission's own consultant confirmed RPU drops are price phenomena, not capacity constraints, so SoCalGas's attempt to redefine RPU as a supply availability metric is unsupported in the record. If that redefinition fails, the 85% RPU assumption (adopted through prior stakeholder process and embedded in [D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)) holds, and Sierra Club's inventory reduction case becomes substantially stronger. SoCalGas's actual field data (957 MMcfd actual deliveries against a 2,700 MMcfd modeling assumption, 9% Northern Zone utilization during Fern) is serious and not answered in Sierra Club's reply. The question the CPUC will have to resolve is whether those events represent physical supply constraints that invalidate the FTI framework, or extreme pricing events that the FTI framework already accounts for by design. SoCalGas's secondary move (converting inventory reduction into quantified ratepayer harm through probabilistic price analysis) is also significant. Once the proceeding contains a CPUC-vetted dollar estimate for storage reductions, the debate may shift from conceptual reliability to measurable ratepayer exposure. Sierra Club's opposition to that framework is procedurally coherent but strategically risky: if the CPUC allows even a limited economic analysis, the ensuing numbers will take precedence in the next round of arguments. The Unbundled Storage Program matter identified by the Shippers is the least-developed but potentially most impactful discussion. An assessment that cannot quantify Unbundled Storage Program impacts from inventory reductions is incomplete by the CPUC's own just-and-reasonable-rates standard. --- ### **AFFORDABILITY** SoCalGas recently published "[The Affordable Way for California](https://www.socalgas.com/sites/default/files/2026-04/Affordable%5FWay%5FCA%5FReport.pdf?ref=calregulatory.com)," a report that makes a coordinated affordability argument against accelerated natural gas displacement. Using Bureau of Labor Statistics data, the report establishes that average California households spend **$47/month** on natural gas, which is less than electricity (**$143**) or gasoline (**$308**), and that inflation-adjusted residential gas rates fell about **25%** between 2000 and 2023\. Meanwhile, electricity rates rose **60%** over the same period. The report's most substantive empirical claim concerns natural gas storage and grid balancing. California's underground gas storage system can deliver **1,597 GWh/day**, which dwarfs current battery (63 GWh/day) and pumped hydro (46 GWh/day) capacity. During [Winter Storm Fern](https://en.wikipedia.org/wiki/January%5F23%E2%80%9327,%5F2026%5FNorth%5FAmerican%5Fwinter%5Fstorm?ref=calregulatory.com) in January 2026, natural gas storage supplied nearly **60%** of peak system demand and avoided over **$120 million** in customer costs. On renewable integration, CAISO data shows that between 2018 and 2024, noon solar generation rose about 6,500 MW while natural gas generation fell only 1,500 MW. The non-one-for-one displacement ratio is the most consequential number in the document. The equity argument frames accelerated electrification as a cost-shift risk: if higher-income customers exit the gas network, fixed infrastructure costs concentrate on lower- and middle-income ratepayers least able to electrify. SoCalGas residential bills currently represent **0.6%** of household income, the lowest among its major U.S. gas peers. **INSTANT ANALYSIS:** This is a strong PR document that might help SoCalGas's optics with the general public. The document also repositions underground storage as long-duration strategic infrastructure rather than a legacy fossil burden, which is a useful argument in an era of affordability and reliability crises. However, the report doesn't engage methane leakage accounting, stranded asset liabilities, or the trajectory of battery storage costs. --- ### **UTILITY HYDROGEN BLENDING DEMO PROJECTS** Parties filed opening briefs in the utilities' [hydrogen blending pilot proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M496/K875/496875149.PDF?ref=calregulatory.com), highlighting a fundamental conflict over whether the utilities' proposed pilots represent legitimate scientific inquiry or an expensive effort to extend the gas system's relevance. The utilities argue their projects generate real-world operational data that modeling cannot replicate. Intervenors argue that hydrogen blending is a dead-end strategy and the pilots are imprudent regardless of design quality. - [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874479.PDF?ref=calregulatory.com)'s closed transmission test loop in Lodi makes the strongest incremental-knowledge case. - [Southwest Gas](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874841.PDF?ref=calregulatory.com)'s Truckee pilot offers credible geographic differentiation. - [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215358.PDF?ref=calregulatory.com)'s polyethylene pipe testing is credibly characterized as duplicative. - [SoCalGas](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215359.PDF?ref=calregulatory.com)'s Orange Cove project (an open distribution system serving thousands of residential customers) faces a threshold legal question on closed-system compliance under a 2022 CPUC decision ([D.22-12-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K055/500055657.PDF?ref=calregulatory.com)) and community opposition so severe that 27 of 33 residents who testified opposed or raised safety concerns. Cal Advocates [recommends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K266/606266372.PDF?ref=calregulatory.com) dismissing all five projects. [Sierra Club](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215360.PDF?ref=calregulatory.com), the [Environmental Defense Fund](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K215/606215361.PDF?ref=calregulatory.com), [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K266/606266369.PDF?ref=calregulatory.com), the [Utility Consumers Action Network](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M606/K206/606206096.PDF?ref=calregulatory.com), and [Orange Cove intervenors](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K875/605875496.PDF?ref=calregulatory.com) align behind the same conclusion. **INSTANT ANALYSIS:** The intervenor coalition has made pilot design largely irrelevant by arguing that no version of hydrogen blending in residential and commercial distribution systems produces ratepayer benefits sufficient to justify the cost when electrification is available and cheaper. The CPUC cannot approve these applications without confronting that argument directly, and the utilities have not made a clean showing on prudency. The Commission's ultimate decision will reveal whether the CPUC is adjudicating on the prudency standard or managing the bigger political question of what role gas infrastructure plays in California's decarbonization future. --- ### **BIOMETHANE** PG&E and the Sempra Utilities (SoCalGas/SDG&E) recently filed their annual biomethane compliance reports. - PG&E [reports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874434.PDF?ref=calregulatory.com) no biomethane procurement in 2025 under the terms of a 2022 CPUC decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)), rendering most of the CPUC's expanded reporting categories inapplicable. The filing defaults to legacy Phase II requirements, which run through 2027\. Within that scope: there is one interconnected project, a development timeline exceeding five years, and a **$3 million** incentive payment issued last year. There is no new procurement and no scaling. - SoCalGas and SDG&E [executed](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874495.PDF?ref=calregulatory.com) two biomethane contracts in 2025 but recorded no flows for the year, leaving the expanded D.22-02-025 reporting categories inapplicable. Phase II reporting covers three CalBioGas projects in the Central Valley (North Visalia, South Tulare, and Buttonwillow) with interconnection timelines ranging from 1,044 to 1,457 days and incentive payments between **$2.96 million** and **$5 million**, all disbursed in July 2025. Contracts are being signed, incentives are being paid, but gas is not flowing. The program has produced no delivered volumes under the newer regulatory framework. **INSTANT ANALYSIS:** Interconnection timelines in the four-to-five year range and zero post-contract flows suggest a development pipeline that functions more like custom infrastructure than a scalable fuel supply. Until project execution risk comes down and molecules start moving, biomethane remains a compliance artifact with no demonstrated value as a reliability or decarbonization resource. --- ### **CAISO SUMMER ASSESSMENT** The CAISO published its [2026 Summer Loads and Resources Assessment](https://www.caiso.com/documents/2026-summer-loads-and-resources-assessment.pdf?ref=calregulatory.com). The system is better positioned than in 2024 or 2025\. The CAISO enters summer 2026 with a modeled surplus of **2,547 MW** against its 1-in-10 loss-of-load target, the fourth consecutive year meeting that standard. Peak demand is forecast at **46,844 MW** on September 2, hour ending 18. The surplus relies on assumptions that deserve scrutiny. The portfolio includes all RA-eligible capacity regardless of contracting status, a methodology CAISO acknowledges may overstate available supply. Known Loads, approximately **1,569 MW** of potential additional demand from distribution-level energization requests, are excluded from stochastic modeling. Hydro is constrained to a low-water analog year; snowpack as of April 1 was the second-lowest on record at **18%**. [SunZia Wind](https://en.wikipedia.org/wiki/SunZia%5FWind%5Fand%5FTransmission?ref=calregulatory.com) counts toward the net import limit during peak hours only up to **1,009 MW**, not the full 3,167 MW CAISO share. September evenings are still a problem. Loss-of-load events in the probabilistic model concentrate in hours ending 19 and 20, when solar output has dropped and batteries are discharging. July carries similar load but benefits from about **3.6 GW** more solar during the peak hour. The multi-hour stack analysis requires a **25%** planning reserve margin to hit the 0.1 LOLE standard; the load-weighted average LSE obligation sits at **17.5%**, a **3,250 MW** gap that emergency resources are expected to bridge. That emergency backstop totals approximately **3,379 MW**, drawn from the state's [Strategic Reliability Reserve](https://www.energy.ca.gov/data-reports/california-energy-planning-library/reliability/strategic-reliability-reserve?ref=calregulatory.com) and intertie assistance. None of it is in the core RA stack. The CAISO's model does not account for coincident extreme events (regional heat waves, drought, wildfires, or forced outages across neighboring balancing authorities). Those remain the primary risks. **INSTANT ANALYSIS**: For the refiners and utilities reading this: the surplus is less comfortable than it looks. The 3,250 MW gap between what load-serving entities are obligated to hold and what the CAISO says is actually needed tells you where the risk resides. That gap gets filled by emergency resources outside the RA stack, resources that are slower to dispatch and not guaranteed to be available when a regional heat event is stressing neighboring balancing authorities at the same time. For trading desks, September hours 19 and 20 are where the model breaks. That is not new information, but the assumptions propping up the surplus (excluded known loads, a capped SunZia contribution, low-hydro analog conditions) all move against the model at once. When supply runs short in those hours, prices move fast. ### May 14 CPUC Voting Meeting Preview: PG&E NG Peak-Day Reset, $1.95B Woolsey Securitization, Diablo Cost Threshold Shift URL: https://www.calregulatory.com/may-14-cpuc-voting-meeting-preview-pg-e-ng-peak-day-reset-1-95b-woolsey-securitization-diablo-cost-threshold-shift/ Last updated: 2026-05-06T00:03:54.000Z The CPUC's **May 14** voting meeting [agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M606/K201/606201347.pdf?ref=calregulatory.com) features a potential reset of PG&E’s natural gas peak-day supply outlook, $1.951 billion in SCE's Woolsey Fire securitization, and a stricter Diablo Canyon cost threshold. --- ### GAS SYSTEM RELIABILITY A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K932/604932014.PDF?ref=calregulatory.com) approves a full [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K724/605724316.pdf?ref=calregulatory.com) between PG&E and TURN resolving PG&E's updated Peak Day Supply Standard for winters 2024-2025 through 2026-2027\. The case stems from a 2023 decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)), which directed PG&E to refresh its peak-day demand and supply modeling. TURN challenged three inputs (core demand, electric generation demand, and Redwood Path supply availability) then settled rather than litigate. The PD finds the resulting standard reasonable, within the evidentiary range, and consistent with its directive to improve methodology. The settlement reworks three inputs across three winters, generating 24 changed cells in PG&E's reliability table. - Core demand and electric generation both drop; - Combined northern-southern supply rises **92 MMcfd**; and - Every settled value falls between the parties' litigated positions. Those changes reduce the pre-investment 2024-2025 shortfall from -380 MMcfd to -**135 MMcfd** and move winters 2025-2026 and 2026-2027 into surplus before any new wells come online (a year earlier than PG&E's filed analysis projected). TURN won the argument that PG&E's peak-day numbers were inflated. **INSTANT ANALYSIS:** PG&E filed an analysis showing a -380 MMcfd shortfall heading into 2024-2025 and a system that would not reach surplus until 2026-2027 even after new wells came online. The settled numbers say something quite different. The 2024-2025 deficit shrank to -135 MMcfd, and the system crossed into surplus in 2025-2026 before any new wells were built. TURN's testimony forced PG&E to accept lower demand forecasts and higher supply availability than it had filed, and the arithmetic followed. The battle now moves to [A.25-05-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com), where PG&E will re-file demand trajectories, electric generation burn, and supply assumptions for winter 2027-2028 forward. The PD expressly preserves both parties' freedom to relitigate every input. The settlement closes a three-winter window without forcing a Commission ruling on whether PG&E's underlying methodology produces inflated capacity needs (a question TURN will almost certainly bring back in the General Rate Case). --- ### WOOLSEY FIRE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K577/604577373.PDF?ref=calregulatory.com) authorizes SCE to securitize approximately **$1.951 billion** in Woolsey Fire Wildfire Expense Memorandum Account (WEMA) costs through Recovery Bonds, with projected ratepayer savings of **$811 million** on a Net Present Value basis versus traditional utility financing. The underlying just-and-reasonable determination was made in a 2025 decision ([D.25-12-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K453/592453458.PDF?ref=calregulatory.com)), which approved approximately $1.972 billion in WEMA cost recovery (35% of SCE's gross request, net of $1 billion in insurance and third-party recoveries) and disallowed the remaining 65% (approximately $3.663 billion). The $1.951 billion reflects that approved recovery, adjusted for upfront costs and a revised pre-securitization accrual window. The PD's just-and-reasonable finding on the bond issuance traces to a joint stipulation between SCE and Cal Advocates. Woolsey is SCE's fifth [Assembly Bill 1054](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201920200AB1054&ref=calregulatory.com) securitization, after three capex financing orders ([D.20-11-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M350/K707/350707656.PDF?ref=calregulatory.com), [D.21-10-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M418/K526/418526095.PDF?ref=calregulatory.com), [D.23-02-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956389.PDF?ref=calregulatory.com)) and the **$1.629 billion** Thomas/Montecito financing order ([D.25-08-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K094/578094182.PDF?ref=calregulatory.com)). Cumulative AB 1054 issuances for Edison will reach approximately **$5.2 billion** once Woolsey closes. SCE transfers recovery property (principally the right to collect a non-bypassable Fixed Recovery Charge) to a bankruptcy-remote Special Purpose Entity that issues the bonds and repays investors from Fixed Recovery Charge revenues. The [cash-flow model](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541828.PDF?ref=calregulatory.com) runs in three steps each payment period. - First, the bond payment obligation (principal, interest, ongoing costs) is converted to a billing requirement adjusted for uncollectibles and days-sales-outstanding. - Second, that requirement is allocated by the General Rate Case Allocation Factor from the Marginal Cost and Revenue Allocation Settlement Agreement ([D.22-08-001](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K425/496425527.PDF?ref=calregulatory.com)). The [CARE/FERA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com) portion is reallocated to non-exempt classes via the existing CARE discount allocation, placing the full revenue requirement on non-exempt customer classes. - Third, per-kWh clearing rates are calculated against forecast sales. The model runs over two payment periods, adopts the higher clearing rate, and nets prior Trustee-held collections and projected revenues under current rates against the next requirement. Over- and under-collections roll into the subsequent true-up. **INSTANT ANALYSIS:** The Woolsey Fire revenue requirement was decided last year and is not relitigated here. Moving $1.951 billion off rate base produces approximately $811 million in Net Present Value savings versus traditional financing. The trade is a long-lived, non-bypassable surcharge engineered for payment certainty, with true-ups that adjust as needed to keep collections aligned with debt service regardless of load volatility. Cumulative SCE AB 1054 issuances reach approximately $5.2 billion across five securitizations, though concurrent Fixed Recovery Charge exposure on customer bills at any given moment depends on the amortization schedules of the earlier CapEx orders. Each financing order produces its own Fixed Recovery Charge running on its own schedule. The GRC Allocation Factor carries through to each Fixed Recovery Charge, the CARE/FERA portion is reallocated through the existing CARE discount allocation, and the full revenue burden falls on non-exempt customer classes. For large C&I, each new financing order layers on top of whatever earlier-vintage Fixed Recovery Charges remain outstanding. --- ### DIABLO CANYON COST RECOVERY A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545283.PDF?ref=calregulatory.com) grants in part the Alliance for Nuclear Responsibility (A4NR)'s petition to modify the December 2024 Diablo Canyon cost-recovery decision ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K462/550462685.PDF?ref=calregulatory.com), as modified by [D.25-07-041](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K498/574498036.PDF?ref=calregulatory.com)). Going forward, when the CPUC evaluates whether PG&E's actual costs come in below **115%** of forecast under [Section 712.8(h)(1)](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-712-8/?ref=calregulatory.com), it will now use the final Resource Adequacy Market Price Benchmark rather than the forecast value to calculate RA substitution capacity costs. This change follows a 2025 decision ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)) in the ERRA/PCIA Reform docket, which overhauled the benchmark methodology and brought the 2025 final value down to $11.21/kW-month against a $42.54 forecast, with a parallel correction on the 2024 side from $28.65 to $26.26\. Inside a $722.6 million revenue requirement that includes a **$210 million** RA substitution line item, the distance between forecast and final determines whether the threshold imposes meaningful review or absorbs almost anything. The PD accepts A4NR's argument that an inflated forecast benchmark widens the 115% buffer and shields operating costs from the review the statute contemplates, and agrees that the final benchmark better tracks how the statute measures cost performance. The PD declines to restate the approved revenue requirement or rewrite prior findings, reasoning that ERRA-style true-ups already in place have moved the corrected benchmarks into rates without anyone needing to reopen the decision. The modification runs through 2030 rather than applying only to 2025, a scope PG&E supported and the PD adopts because the same reasoning recurs every year. **INSTANT ANALYSIS:** The PD closes an opening in the Diablo Canyon cost-recovery framework that would have let a meaningful slice of operating costs pass the 115% threshold without scrutiny. A bigger problem sits in the benchmark framework itself. The CPUC already concluded in D.25-06-049 that the prior methodology was vulnerable to manipulation and inconsistent with the statutory indifference requirement, and this PD keeps that diagnosis from carrying through into a separate statutory test where the consequences are heavier because the cutoff on reasonableness review is absolute. --- ### SHARED RENEWABLES A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536932.PDF?ref=calregulatory.com) implements California's Shared Renewables Portfolio without the funding that was intended to support it. Federal Solar for All money is gone, terminated by the Environmental Protection Agency in August 2025\. A **$33 million** state appropriation reverted to the General Fund in June 2025\. The program will proceed anyway. The PD ties the new Community Renewable Energy tariff to the [Renewable Market Adjusting Tariff program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com). Proposals for capacity adders, expanded project sizes, time-of-delivery adjustments, and above-avoided-cost compensation were all rejected as inconsistent with the Public Utilities Code. Nonparticipating customers will not pay above avoided costs. **INSTANT ANALYSIS:** The basic concept of this program survives. The economics that would have driven participation do not. --- ### CRUDE OIL TRANSPORTATION A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K483/603483090.PDF?ref=calregulatory.com) approves Crimson California Pipeline’s request to increase crude oil transportation rates on its Southern California system by 10%, effective **August 1, 2025**. The PD rejects a late attempt by Crimson to push the increase higher. The 10% increase is supported by Crimson’s revenue requirement and a projected 10.82% return on equity. Crimson’s additional 3.16% request is denied on procedural grounds. The PD authorizes retroactive recovery of the approved 10% back to August 1, 2025, with interest at the 90-day commercial paper rate. Costs will fall on large commercial shippers. **INSTANT ANALYSIS:** No shipper protested the application, no safety disputes were raised, and no ESJ friction materialized. The approved rates land within an acceptable commercial band for refinery-linked counterparties. Crimson has been billing at pre-August 2025 rates for about nine months; retroactive recovery with interest creates a meaningful cash collection against an approximate **$30 million** test-period revenue base. ### MONDAY NEWS CODEX: CAISO Summer Loads Assessment URL: https://www.calregulatory.com/monday-news-codex-caiso-summer-loads-assessment/ Last updated: 2026-05-04T22:54:31.000Z - **2026 Summer Loads and Resources Assessment:** "2,127 MW of resource adequacy eligible nameplate capacity have been added to the CAISO grid from September 1, 2025 through April 1, 2026 and an additional 6,194 MW of new resources are expected through June 30, 2026, which includes CAISO’s share (3,167 MW) of SunZia Wind project in New Mexico." [**CAISO**](https://www.caiso.com/documents/2026-summer-loads-and-resources-assessment.pdf?ref=calregulatory.com) - **A New Bill Would Help VPPs Replace Peaker Plants in California:** "[Senate Bill 913](https://sd13.senate.ca.gov/news/press-release/march-24-2026/becker-introduces-sb-913-to-make-better-use-customer-owned-clean?ref=calregulatory.com), introduced by state **Sen. Josh Becker**, a Democrat, would allow VPPs to ​'compete on a level playing field with traditional power sources to provide grid reliability at the lowest cost.' The bill, which lays out a slew of policy changes, passed out of the California Senate Energy, Utilities, and Communications Committee earlier this month, a first step on the way to a potential vote before the full state Senate and Assembly." [**CANARY MEDIA**](https://www.canarymedia.com/articles/virtual-power-plants/new-bill-vpp-california?ref=calregulatory.com) - **A Stress Test for California Carbon Pricing:** "California is trying to finalize a major redesign of its carbon market. The timing is not great. Gasoline prices are pushing $6 a gallon. Two refineries have now closed. And the federal government has shifted from subsidizing clean energy investment to openly undermining state-level climate action. Into this fraught territory steps the California Air Resources Board, the agency tasked with translating a [sweeping legislative](https://lao.ca.gov/Publications/Report/5097?ref=calregulatory.com) mandate into workable regulations." [**ENERGY at HAAS**](https://energyathaas.wordpress.com/2026/04/27/a-stress-test-for-california-carbon-pricing/?ref=calregulatory.com) - **California's Electric Bills Would Be Much Lower Without State's Program Fees:** "A study released last summer found these [fees add nearly 37%](https://raterealities.com/wp-content/uploads/2025/08/IOU-Bill-Stack-Analysis-06.30.25-FINAL.pdf?ref=calregulatory.com) to the average Californian’s electricity bill. In addition to paying for power generation and delivery to households, electricity customers foot the bill for a collection of hidden “public purpose” programs and state mandates. Customers who get their power from investor-owned [utilities](https://calmatters.org/tag/utilities/?ref=calregulatory.com) such as Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric pay about $820 a year for these programs." [**CAL MATTERS**](https://calmatters.org/commentary/2026/05/electric-bills-california-fees/?ref=calregulatory.com) - **California's Energy Evolution:** "PG&E has a goal to serve 3 million EVs by 2030\. We’re on our way with about 775,000 now. If we time their charging right, they can use affordable, excess solar energy during the day. In fact, with the next million EVs connecting to the grid, we see a potential reduction in customers’ bills of 2 to 3 percent, simply by making more efficient use of the grid." [**POLITICO**](https://www.politico.com/sponsored/2026/01/californias-energy-evolution/?ref=calregulatory.com) - **California's Self-Destructive War on Oil:** "According to the [Statistical Review of World Energy](https://www.energyinst.org/statistical-review?ref=calregulatory.com), in 2024, oil, natural gas, and coal contributed 87 percent of the world’s primary energy supply. Two years ago, that number was quietly revised upwards by the Review from the more commonly cited 82 percent, because they decided to start converting terawatt-hour electricity production from non-combustible sources to the actual exajoules of primary energy they represented. This new method abandons their previous misleading practice of grossing that number up artificially, under the assumption more energy would have been expended if natural gas or coal had been utilized to generate the electricity." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-californias-self-destructive-war-on-oil/?ref=calregulatory.com) - **California Sets Precedent by Overriding Local Blockade for Soda Mountain:** "The California Energy Commission has [approved](https://www.energy.ca.gov/news/2026-04/cec-approves-soda-mountain-solar-and-battery-storage-project-san-bernardino?ref=calregulatory.com) the 300 MW Soda Mountain Solar Project, marking the first time a major solar development has successfully used a state-level 'opt-in' procedure to bypass local opposition to an energy project. The decision provides a roadmap for utility-scale developers to overcome local land-use restrictions that have historically [stalled the project](https://pv-magazine-usa.com/2026/01/05/california-reclaims-authority-to-move-stalled-soda-mountain-solar-project-toward-approval/?ref=calregulatory.com) and others like it." [**PV MAGAZINE**](http://pv-magazine-usa.com/2026/04/29/california-sets-precedent-by-overriding-local-blockade-for-soda-mountain/?ref=calregulatory.com) - **I Have a Confession:** "... there are examples in a state like California where expressing unease with a results-oriented approach to regulation is not acceptable. Most recently this came when many of my member companies considered whether to spend significant money to challenge a California Public Service Commission’s decision that did not (in our view) follow the law on a procurement standard. Every law firm we approached told us not to waste our money. There was no chance of successfully challenging the CPUC. It must be bad if law firms are turning down legal fees. The *zeitgeist* in California has been decidedly anti-competition for many years. One gets the feeling this is mostly a staff preference for central planning over competition but a point on the general direction of CPUC seems a waste of breath and won’t make the next filing for those who express such a view very welcome. In both these instances – both in federal and state venues – one is left with a feeling of *ennui* that due process was being undermined. But what to do?"[**WESTERN POWER TRADING FORM**](https://www.wptf.org/i-have-a-confession/?ref=calregulatory.com) - **Phillips 66 – Renewable Fuel Segment Currently Producing at Above Nameplate Capacity:** "During a first quarter earnings call, **Brian Mandell**, executive vice president of marketing and commercial at Phillips 66, said the company profited from a long renewable identification number position during the quarter, including RINs that were generated at the Rodeo complex. The company was also able to roll some lower-cost RINs from prior year into this year, he added. Mendall noted that current RIN values are more than twice what they were during the same time last year. The credit value alone is boosting margins right now, he indicated." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/phillips-66-renewable-fuel-segment-currently-producing-at-above-nameplate-capacity?ref=calregulatory.com) - **Pipeline Construction Will Follow Natural Gas Demand Growth:** "Saguaro Connector Pipeline LLC has asked the Federal Energy Regulatory Commission for [a three-year extension](https://pgjonline.com/news/2026/april/oneok-seeks-extension-for-us-mexico-gas-pipeline-segment-tied-to-lng-project?ref=calregulatory.com) to complete a cross-border pipeline segment that would feed an LNG project in Mexico. The project, which was originally to be completed by February 15, 2027, under FERC’s 2024 authorization, was to construct and place into service a 1,000-foot, 48-inch-diameter pipeline crossing the Rio Grande in Hudspeth County, Texas. The pipeline is to supply natural gas from the Permian Basin to a proposed LNG export terminal in Mexico. The delay was caused by prolonged litigation, ongoing commercial negotiations, and the timing of a planned LNG export facility on Mexico’s west coast." [**INSTITUTE for ENERGY RESEARCH** ](https://www.instituteforenergyresearch.org/fossil-fuels/pipeline-construction-will-follow-natural-gas-demand-growth/?ref=calregulatory.com) - **SoCalGas Customers Spared Paying $266M for Hydrogen Pipeline Project:** "...it’s far from clear that hydrogen can provide an environmentally or economically viable route to meeting those goals — either in California or across the country. Over the past three years, a boom in clean hydrogen investment has [largely evaporated in the U.S.](https://www.canarymedia.com/articles/hydrogen/green-industry-trump-tax-credits?ref=calregulatory.com) Billions of dollars meant to spur projects to generate, store, and transport hydrogen have been canceled or put on hold." [**CANARY MEDIA**](https://www.canarymedia.com/articles/hydrogen/socalgas-customers-spared-hydrogen-pipeline-plans?ref=calregulatory.com) - **Trump Directs Federal Financial Support to Increase Energy Production:** "President Donald Trump invoked the Defense Production Act to direct federal support toward oil, gas, coal, and electric grid infrastructure through a series of presidential determinations on April 20, 2026." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/trump-directs-federal-financial-support?ref=calregulatory.com) - **Two California Bills Would Push Utilities to Get More Out of Their Grids:** "Could California’s major utilities control their rapidly rising electricity rates by using their power grids more efficiently? State lawmakers want to find out. A set of bills introduced this year would order Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric to measure and improve how they’re utilizing the hundreds of thousands of miles of power lines that carry electricity to customers." [**CANARY MEDIA**](https://www.canarymedia.com/articles/distributed-energy-resources/two-california-bills-utilities-grids?ref=calregulatory.com) - **Understanding California Refineries – the "Turnaround":** "Refineries are very complex operations. They are the backbone of our economy; indeed, our very survival as a society depends on them."[ **CALIFORNIA GLOBE**](https://californiaglobe.com/fr/understanding-california-refineries-the-turnaround/?ref=calregulatory.com) - **Wildfires Weigh on PG&E as California Sees Modest Large Load Demand**: "California must spread the word that it is 'open for business,' CEO **Patti Poppe** said of recent interactions with data center developers. State officials expect just 1.8 GW of data center load by 2030...The utility continues to reckon the significant financial impact of past wildfires. It assigned an aggregate liability estimate of $1.325 billion for the 2019 Kincade fire; $2.15 billion for the 2021 Dixie fire; and $400 million for the 2022 Mosquito fire, according to its [quarterly report to the Securities and Exchange Commission](http://d18rn0p25nwr6d.cloudfront.net/CIK-0001004980/8f03bd99-bdd9-42bb-a54e-d913e3414c37.pdf?ref=calregulatory.com)." [**UTILITY DIVE**](https://www.utilitydive.com/news/wildfires-weigh-on-pge-as-california-sees-modest-large-load-demand/818715/?ref=calregulatory.com) - **Without Wildfire Reform, California Utilities Could See Credit Impacts – Edison International:** "SCE announced on Wednesday that it has so far offered more than $500 million to nearly 3,800 parties that have filed claims under the company’s [Wildfire Recovery Compensation Program](http://newsroom.edison.com/releases/relief-offered-from-sce-to-community-members-impacted-by-eaton-fire-exceeds-500-million?ref=calregulatory.com), set up to provide those affected by the 2025 Eaton Fire with an alternative to litigation. Claimants have accepted about 1,000 of those offers, according to a company news release. The company has to date received 3,200 claims from more than 9,500 individuals, trusts and other entities." [**UTILITY DIVE**](https://www.utilitydive.com/news/eix-california-utilities-credit-rating-wildfire-earnings/819026/?ref=calregulatory.com) ### SoCalGas: Upstream Constraints Drive Curtailment Risk in Southern California URL: https://www.calregulatory.com/socalgas-filing-shows-upstream-constraints-keep-pushing-southern-california-to-the-curtailment-edge/ Last updated: 2026-05-04T20:52:54.000Z On May 1, SoCalGas complied with **ALJ Ormond**'s [April 16 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K937/604937767.PDF?ref=calregulatory.com) in [A.26-01-009](https://www.socalgas.com/a26-01-009-aliso-canyon-biennial-assessment-application?ref=calregulatory.com) by providing information on outages and concerning events that occurred outside of SoCalGas's service territory over the past decade. Related coverage is available at the following links. [April 15 Aliso Canyon Biennial Assessment Workshop SummaryThe first Aliso Canyon Biennial Assessment Workshop exposed a conflict over whether reliability depends on storage or on optimistic assumptions.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/iterograph_Tue-Mar-31-2026--16-.png)](https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/) [Aliso Canyon Goes ProceduralSoCalGas filed a response on April 16 urging the CPUC to deny a Sierra Club motion to compel additional discovery in A.26-01-009.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-16-2026--20-.png)](https://www.calregulatory.com/friday-aggregate-2/) [New Challenges for SoCalGas/Aliso CanyonALJ Jamie Ormond issued back-to-back rulings April 16-17 in SoCalGas’s D.24-12-076 compliance application.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-16-2026--1--1.png)](https://www.calregulatory.com/monday-aggregate-new-friction-for-aliso-canyon-new-transmission-questions-for-pg-e/) [Aliso Canyon Workshop Comments: Demand, Supply Risk, & CostThe CPUC is deciding how much gas must remain in storage at Aliso Canyon to maintain reliability without imposing unnecessary costs on ratepayers.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-16-2026--3-.png)](https://www.calregulatory.com/aliso-canyon/) [Reliability Data Reinforces Aliso Canyon’s ImportanceSoCalGas published its Seventeenth Annual Report on System Reliability, covering April 2025 through March 2026.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-30-2026--31-.png)](https://www.calregulatory.com/annualreport/) ### BACKGROUND SoCalGas notes that California imports more than 95% of its natural gas from out-of-state sources. The SoCalGas system sits at the terminus of several interstate pipelines, making it the last node in the western gas network. When upstream conditions tighten (freeze-offs in producing basins, compressor failures, infrastructure outages, or continental cold that diverts supply to higher-priced markets) California has no meaningful alternatives. Local underground storage, led by the Aliso Canyon facility, absorbs the shortfall. Reliability risk is driven outside California, not within it. ### WEATHER EVENTS SoCalGas documents eight discrete upstream disruption events from 2017 through January 2026\. A recurring pattern emerges: upstream stress reduces Receipt Point Utilization (RPU) below normal levels, which forces large storage withdrawals, and this triggers Operational Flow Orders and curtailment watches. - **January - February 2017: Atmospheric River Events** *.* Three back-to-back atmospheric river events, combined with cold Rockies temperatures, reduced system RPU to **68%** during the most intense period. SoCalGas withdrew 14 Bcf from storage across the full January - February window and declared **18 Low OFOs**. A system-wide curtailment watch ran January 23 - 26\. No curtailments were required. - **January 2018: Arctic Outbreak** *.* A widespread arctic air mass covering the western, central, and eastern U.S. from late December 2017 through mid-January 2018 caused well freeze-offs and interstate pipeline operational failures. System RPU fell to **72%** during the peak period of January 1 - 9, with 1.2 Bcf withdrawn from storage. SoCalGas declared **14 Low OFOs**. - **January - February 2019: Polar Vortex**.A major polar vortex displacement drove arctic air into the central U.S., constraining national markets and east-west gas flexibility. Southern California temperatures were relatively mild, but upstream pipeline operators experienced constrained flow rates and lost supply to price-insensitive Midwest demand. System RPU fell to **88%** during the peak period, with 7.3 Bcf withdrawn across the full event. SoCalGas implemented a curtailment for electric generation customers under Rule 23 from February 6 - 8, 2019 (the only end-use curtailment documented in the external outage record). A system-wide curtailment watch ran concurrently. - **February 2021: Winter Storm Uri** *.* Uri was the most operationally severe weather event in the filing. Arctic air moving into the central and southern U.S. beginning February 10 produced freeze-offs eliminating approximately 5 Bcfd of Permian Basin supply (20 Bcf over four days) caused widespread Texas power failures, and knocked out compressor stations along upstream interstate pipelines. System RPU fell to **46%** during the February 14 - 19 peak, the lowest system-wide reading to that point in the record, with the Northern Zone reaching **26%**. SoCalGas withdrew 4.4 Bcf from storage. A Southern System curtailment watch ran February 14 - 19. - **December 2022: Winter Storm Elliott** *.* An extreme arctic outbreak simultaneously affecting nearly all U.S. regions produced well freeze-offs, electric system failures, and pipeline stress. System RPU fell to **65%** during the December 22 - 25 peak, with 1.2 Bcf withdrawn from storage. Core procurement costs reached an unprecedented **$34/Dth**, more than **300%** above the prior year. A Southern System curtailment watch preceded the storm from December 13 - 17. - **January 2024: Winter Storm Heather** *.* A cross-continental storm originating as an extratropical cyclone in the northeastern Pacific made landfall in the Pacific Northwest before driving extreme cold and elevated heating demand across the South and Southeast. Southern California was not directly affected by cold, but upstream demand diverted supply eastward. System RPU fell to **36%** during the January 14 - 17 peak (the Northern Zone reached **19%**, and 5.8 Bcf was withdrawn from storage). This was the first winter event since 2016 in which SoCalGas operated without Aliso Canyon restrictions. A system-wide curtailment watch ran January 15 - 17. - **January 2025: Western Arctic Events**. A month-long North American cold wave produced multiple arctic intrusions over a four-week period rather than a single cold snap. The duration, not the magnitude, was the critical factor. System RPU fell to **36%** during the January 19 - 26 peak, with the Northern Zone reaching **16%**, and 8 Bcf was withdrawn from storage. Concerns intensified when the [Honor Rancho Storage Field](https://www.socalgas.com/sustainability/pipeline-and-storage-safety/storage-facility-safety/honor-rancho?ref=calregulatory.com) was temporarily shut January 22 - 24 due to its proximity to the Hughes Wildfire. **Eight Low OFOs** were declared across the event. - **January 2026: Winter Storm Fern** *.* A multi-day arctic outbreak affecting approximately 230 million people across Northern Mexico, the South, Plains, and eastern U.S. produced heavy snowfall, widespread ice accumulation, more than one million electric customer outages, and over 10,000 flight cancellations. System RPU fell to **25%** during the January 24 - 26 peak — the lowest system-wide reading in the filing, with the Northern Zone reaching **9%**. SoCalGas withdrew 8.2 Bcf across the January 22 - 28 window. Fern coincided with a pre-existing infrastructure constraint: a December 27, 2025 landslide had ruptured Transmission Line 225, reducing Wheeler Ridge receipt capacity by 650 MMcfd to 115 MMcfd. A system-wide curtailment watch ran January 26 - 28. ### CURTAILMENT RECORD Fifteen curtailment watches are documented between December 2016 and January 2026, ranging from one day to 19 days in duration. Several summer 2021 and 2022 watches on the Southern System ran for weeks, driven by [El Paso Natural Gas](https://en.wikipedia.org/wiki/El%5FPaso%5FNatural%5FGas?ref=calregulatory.com) constraints, which were compounded by heat-driven demand. The sole actual end-use curtailment (electric generation customers under Rule 23) ran February 6 - 8, 2019. ### NON-WEATHER INFRASTRUCTURE RISKS - **EPNG Line 2000** *.* A force majeure outage beginning August 15, 2021 removed approximately **600 MDthd** of supply capacity (about 20% of combined SoCalGas and SDG&E average daily winter demand) and was not resolved until February 14, 2023, an 18-month duration. Additional EPNG maintenance reductions on the North Main Line and at Cadiszou and Ehrenberg from November 2022 through January 2023 compounded the constraint, with reductions ranging from **194** to **739 MDthd** across the affected points. - **Energía Costa Azul LNG Terminal** *.* SoCalGas's filing identifies Energía Costa Azul (ECA) as a forward-looking structural risk that the CPUC's current reliability modeling does not capture. ECA's expected export capacity of up to 425 MMcfd would reduce available supply to the Southern System from 1,210 MMcfd to 785 MMcfd (65% of nominal Southern System capacity). The CPUC's [Biennial Assessment](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/2025%5Faliso%5Fcanyon%5Fbiennial%5Fassessment.pdf?ref=calregulatory.com) assumes an 85% RPU floor. SoCalGas argues the gap between that assumption and the ECA-constrained reality would require increased reliance on Aliso Canyon withdrawals to maintain Southern System reliability, since Aliso Canyon cannot physically serve the Southern System directly but preserves Northern System supplies that can be redirected southward. ### **INSTANT ANALYSIS** SoCalGas is building its case to defend Aliso Canyon. The quantitative record assembled here (RPU lows, storage withdrawal volumes, OFO counts, curtailment watch durations across eight events) is designed to resist any proposal to further restrict storage operations or reduce capacity targets. The near-miss argument runs through every event: in most cases, Southern California was not experiencing unusual cold, yet national demand and upstream constraints pushed the system toward curtailment anyway. The filing states that a coincidence of upstream stress, local cold, low storage inventories, and high electric generation demand has not yet occurred simultaneously. The implication is that **it will**. The ECA section warrants particular attention from intervenors in both this proceeding and any future Southern System infrastructure docket. If SoCalGas's supply compression numbers hold up, the CPUC's reliability baseline is understated and the case for maintaining Aliso Canyon strengthens into the next decision cycle. ### FRIDAY AGGREGATE: SoCalGas Report Tracks Storage Dependence During High-Stress Conditions URL: https://www.calregulatory.com/annualreport/ Last updated: 2026-05-04T20:54:38.000Z Today's briefing includes updates on SoCalGas's system reliability for the period of April 2025 - March 2026 plus a stern letter from CPUC **President John Reynolds** to PG&E, which is being folded into the record of two separate proceedings. --- ### SOCALGAS SYSTEM RELIABILITY SoCalGas published its [Seventeenth Annual Report on System Reliability](https://www.socalgasenvoy.com/ebb/attachments/1777665305568%5FSeventeenth%5FAnnual%5FReport%5Fof%5FSystem%5FReliability%5FIssues%5F5.1.26.pdf?ref=calregulatory.com), covering April 2025 through March 2026. SoCalGas declared **185** High Operational Flow Orders over the reporting year, an **80%** increase from the prior period, against just 16 Low OFOs. Gas Control issued 29 requests for additional supply to maintain minimum flow on the Southern System. The utility purchased **2.57 MMDth** and sold **3.05 MMDth** in the spot market, with a net cost of **$3.9 million**, or **$1.53** per Dth blended. Recall that a High OFO is called when forecasted injections exceed the storage capacity allocated for balancing. A Low OFO is the inverse: forecasted withdrawals exceed withdrawal capacity. Gas Control builds the sendout forecast from weather, market data, and demand inputs from the CAISO, the Los Angeles Department of Water and Power, and the Imperial Irrigation District. OFOs are called by 8 p.m. the day prior on the Evening or Intraday 1 cycle. All 16 Low OFOs occurred in winter, from November through March. The 29 minimum flow requests tell a different seasonal story. More than half came in August alone, with individual shortfalls running from **12,000 Dth** on a quiet day to **341,000 Dth** at the peak of the summer stress. SoCalGas ended the year having sold more gas than it bought. The $3.9 million net cost reflects higher purchase prices relative to sale prices needed to move gas to constrained delivery points. What SoCalGas *didn't do* is also worth noting: - No Emergency Flow Orders; - No Provider of Last Resort calls to Gas Acquisition; - No baseload purchases; and - No discounted interruptible backbone transportation offered to bring more gas in from Ehrenberg. The utility managed an 80% increase in High OFOs without reaching for any of the extraordinary tools available to it. Some regulatory takeaways are highlighted below. - Energía Costa Azul will draw roughly half a billion cubic feet a day from the same pipeline that supplies the Southern System. The terminal received its first feed gas on April 28, and commercial service is expected this summer. The CPUC has already said it may revisit minimum flow tools once ECA is running, which means the current toolkit predates it. - Aliso Canyon inventory levels are a contested topic. An October 2025 Energy Division assessment recommended cutting the facility's storage cap from 68.6 to **58.6 Bcf**, while finding the field needs to deliver at least **550 MMcfd** on a cold winter day. SoCalGas filed in January to reject the cut. - Although SoCalGas does not make this argument explicitly, the 185 High OFOs are consistent with a system that needs **more** injection capacity, not less. The CPUC's eventual action on this matter is the biggest single reliability variable heading into next winter. - Backbone rates will change on **October 1**. A new firm volumetric option called G-BTS5 will become available, and existing G-BTS2 contracts will convert to fully volumetric. The Seventh Memorandum in Lieu of Contract between SoCalGas's System Operator and Gas Acquisition department runs through October 2027 at the latest. **INSTANT ANALYSIS:** The reporting period closed March 31, but the most consequential data point in the entire document arrived after it. Energía Costa Azul received its first feed gas on April 28, three days before SoCalGas filed this report. Every reliability number in the document describes a system that has not yet absorbed the supply diversion it was built without. On Aliso Canyon, SoCalGas would not be fighting a 10 Bcf inventory cut so hard if its modeling showed the existing storage envelope holding under ECA-era flows. The 550 MMcfd peak day floor is a public number. The company's internal number is almost certainly higher. The blended $1.53 per Dth annual cost hides what actually happened. January spot purchases ran **$15-to-$17** on the days SoCalGas needed gas at constrained delivery points. The reliability cost for the entire year concentrates on a small number of days when weather, routing, and intraday scheduling break the wrong way at the same time. The open question is whether the absence of Emergency Flow Orders, Provider of Last Resort calls, baseload purchases, and discounted backbone transportation reflects a utility that does not need those tools or a utility that has not been forced to use them. Winter 2026-27 will provide a big test, and the CPUC's action on Aliso Canyon is the most crucial variable. - [Detailed OFO Calculations](https://www.socalgasenvoy.com/ebb/attachments/1777665542682%5FAttachment%5F1.pdf?ref=calregulatory.com) - [Requests for Additional Supplies](https://www.socalgasenvoy.com/ebb/attachments/1777665542744%5FAttachment%5F2.pdf?ref=calregulatory.com) - [Spot Purchase/Sale Summary ](https://www.socalgasenvoy.com/ebb/attachments/1777665542810%5FAttachment%5F3.pdf?ref=calregulatory.com) --- ### ELECTRICAL UNDERGROUNDING On April 30, the CPUC placed a letter from **President John Reynolds** to PG&E into the record of two proceedings. - **ALJ Regina DeAngelis** [inserted the letter into A.26-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874874.PDF?ref=calregulatory.com), the joint utility application seeking approval of a Benefit-Cost Ratio calculation methodology, audit methodology, and cost recovery conditions under [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K953/589953368.pdf?ref=calregulatory.com). - Commissioner **Matthew Baker** followed by [placing the same letter into the PG&E 2027 General Rate Case docket](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874464.PDF?ref=calregulatory.com) (A.25-05-009). Reynolds [wrote to both **Patti Poppe** (CEO, PG&E Corporation) and **Sumeet Singh** (CEO, PG&E Company)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K874/605874437.PDF?ref=calregulatory.com), with the full Commission copied. He frames [Senate Bill 884](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220SB884&ref=calregulatory.com) as the preferred undergrounding vehicle (due to its 10-year planning horizon, expedited review, better financing, lower ratepayer costs) and acknowledges PG&E's intent to use it beginning in 2028\. His concern is the Electric Undergrounding Plan filing date. PG&E announced plans to underground 10,000 miles of infrastructure in July 2021\. SB 884 became law 14 months later. PG&E has had nearly five years to file an Electric Undergrounding Plan. It has not. Reynolds finds PG&E's explanation unpersuasive: the company claimed it sought to file an Electric Undergrounding Plan since 2022 while admitting it didn't begin working on one until March 2024\. The result is that funding that belongs in SB 884 now sits in a GRC extension mechanism. Reynolds closes with an encouragement, not a directive: *file as soon as possible*. **INSTANT ANALYSIS:** Reynolds is irritated. PG&E claimed urgency on wildfire risk while taking five years to begin work on the one filing the program requires. He calls the contradiction out directly. PG&E built a GRC extension mechanism because it knows the SB 884 timeline may not hold. Reynolds is telling PG&E the Commission noticed and that it cannot escape scrutiny by letting undergrounding drift into the GRC. The Commission will apply the same prudency standard regardless of forum, and the burden is on PG&E to meet it. ### April 30 CPUC Voting Meeting Results: Biomethane Cut, Hydrogen Denied, Transmission Financing Opens URL: https://www.calregulatory.com/april-30-cpuc-voting-meeting-results-biomethane-cut-hydrogen-denied-transmission-financing-opens/ Last updated: 2026-05-01T15:10:49.000Z The CPUC's **April 30** voting meeting featured major moves on RNG, hydrogen, transmission financing, electric rates, and risk-based decision-making. --- ## BIOMETHANE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K801/605801938.PDF?ref=calregulatory.com) rebuilds the CPUC's Renewable Gas Standard around a hard cap on what ratepayers can be charged, not the volume targets that drove the original program. Two tests now gate every new contract: - Above-market costs can't exceed 1% of core customer revenue requirements on a running-average basis; and - They can't grow more than 3% in any single year. Failure of either test means the CPUC won't approve the procurement. Procurement volume targets are halved and stretched. What was 72.8 Bcf by 2030 is now **36.4 Bcf** by 2035\. The 17.6 Bcf Diverted Organic Waste (DOW) target survives intact and shifts to the same 2035 deadline. Non-DOW procurement absorbs the entire reduction. Contracts can now extend past 2040, though the 15-year length cap stays. Every feedstock is eligible immediately, and co-digestion projects have to attribute biomethane to each component feedstock separately rather than count the full output as DOW. Elsewhere, open landfills can now participate in the program, pending a utility proposal that addresses the incentive to accept more organic waste once a landfill is earning biomethane revenue. Wastewater treatment plants taking Diverted Organic Waste get a combustion exception for existing capacity, with filtration and full lifecycle carbon accounting required. Utilities can buy plain old biomethane from RGS-eligible projects at market rate while developers keep the environmental attributes (those volumes don't count toward targets or the cap). Broader unbundling will be examined in the future. The decision denies interconnection ratebasing, but a workshop and application pathway are on the calendar. ### Commissioner Comments from the Dais - **President John Reynolds** framed the decision as a course correction, noting that California's biomethane market remains nascent and that current affordability pressures require stronger cost containment. - **Commissioner Christine Harada** argued that climate impact alone cannot be the sole lens for evaluating the program; the Commission's role as economic regulator requires that costs be allocated fairly and sustainably. - Harada pointed to rising utility bills driven by the financing of safety and climate investments through rates, and stated that ratepayers cannot serve as an open-ended funding source. She described the procurement target reduction as a calibration to present market conditions, arguing that advancing procurement ahead of market development would impose higher costs without efficiency gains. - Harada added that biomethane produced in-state from existing waste streams reduces dependence on Permian and Rockies imports and mitigates exposure to price volatility and supply disruptions. - Harada acknowledged party concerns about double-counting under the original unbundling framework and explained the reversal: utilities must now purchase and retire environmental attributes to receive full credit, with future proposals on separately valuing upstream avoided emissions to come back via the advice-letter process. - **Commissioner Darcie Houck** articulated the Cost Containment Mechanism in operational terms: the 1% cap measures average customer cost increases from the program's 2022 inception. The 3% cap prevents rate shock by limiting any single year's increase. - Houck cited the high variance between market cost and current Renewable Gas Standard contract costs as the reason the containment measure is necessary. - Houck identified the interconnection ratebasing sequence as a meaningful ratepayer protection: utilities must first secure approval of a Tier 3 advice letter via resolution before they can file an application to ratebase interconnection costs. And any application must demonstrate meaningful cost reductions to ratepayers. **INSTANT ANALYSIS:** In essence, this decision admits that the CPUC's original 2022 program design didn't take ratepayer impact seriously enough. For utilities and large gas buyers, the threat of being forced into expensive contracts to hit unreachable targets is gone. The DOW target held while the overall target was cut in half. That's the CPUC saying [Senate Bill 1383](https://www.replate.org/sb1383?ref=calregulatory.com) waste diversion is what this program is actually for, and the rest of the volume was aspiration the CPUC is willing to abandon. --- ## HYDROGEN/ANGELES LINK A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com) denies SoCalGas's request to recover **$266 million** from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the [Angeles Link](https://www.socalgas.com/sustainability/innovation-center/angeles-link?ref=calregulatory.com) hydrogen pipeline project. The project entails dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. The decision finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision ([D.22-12-055](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K167/500167327.PDF?ref=calregulatory.com)) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers. - The record shows significant opposition from consumer advocates, environmental groups, and shippers, who argue that the project's benefits are indirect and uncertain, and that shifting early-stage development costs onto ratepayers would violate core cost-causation principles. Phase 2 cost estimates have nearly tripled since the project was initially proposed, rising from $92 million to $266 million. - SoCalGas declined federal [IIJA](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com) funding through [ARCHES](https://archesh2.org/?ref=calregulatory.com) ( funding the CPUC had specifically directed the utility to pursue in D.22-12-055 to offset ratepayer exposure) arguing that federal compliance costs would not serve ratepayer interests. The decision notes this means no federal offset exists for the proposed costs. - The decision concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise sharply, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. The decision does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational. - The decision declines to resolve jurisdictional questions around whether the project would qualify as a pipeline under Public Utilities Code Section [227](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-227/?ref=calregulatory.com)/[228](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-228/?ref=calregulatory.com) or a gas plant under Section [221](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-221/?ref=calregulatory.com)/[222](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-222/?ref=calregulatory.com), finding such determinations both premature (because the project is not constructed or dedicated to public use) and unnecessary given the denial of cost recovery. The application is denied in full and the proceeding is closed, leaving SoCalGas to pursue the project, if at all, without ratepayer-backed funding for Phase 2. **INSTANT ANALYSIS:** The CPUC is rejecting the idea that speculative, pre-construction hydrogen infrastructure can be funded by legacy gas ratepayers, though it is not permanently foreclosing ratepayer recovery if the project is eventually constructed and demonstrated to be used and useful. For now, the decision is pushing hydrogen out of the mainstream utility cost-recovery model and into a merchant or contract-backed lane. The refusal of federal funding compounds the problem: SoCalGas eliminated the one mechanism the CPUC itself identified to cushion ratepayer impact, then asked ratepayers to absorb the full cost anyway. Developers will need anchor customers, bilateral deals, or external capital. --- ## TRANSMISSION A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K782/605782986.PDF?ref=calregulatory.com), which carried 4-1 (**Commissioner Darcie Houck** dissented) conditionally authorizes PG&E to lease transmission "entitlements" to a Citizens Energy subsidiary but approves no specific transaction. PG&E may file up to five Tier 3 Advice Letters over a five-year window, each covering a tranche of defined transmission projects and each tested against traditional utility financing. Within each tranche, Citizens prepays for up to a **49.9%** leasehold share, collects CAISO transmission revenues over 30 years, then returns the assets. The five tranches are capped at **$1 billion** in aggregate, averaging **$200 million** each. PG&E builds, owns, and operates throughout. The decision applies a heightened public-interest standard given the scale and undefined nature of the projects. Energy Division can refer any Advice Letter to a full application proceeding. PG&E must also file Tier 1 Advice Letters when FERC approves a new formula rate, showing how the updated model would differ from Citizens' locked-in terms. Citizens commits an escalating share of net after-tax profits to direct bill assistance (**50%** on the first tranche scaling to **90%** on the fifth) projected above **$450 million** total. Citizens also forgoes recovery of its own administrative costs, a concession the decision distinguishes from the Sycamore deal (a 2019 Citizens-SDG&E transmission lease that serves as the closest precedent). Each Advice Letter must name delivery organizations, targeting criteria, demographic reach, and 501(c)(3) channeling, with retrospective accounting before later tranches. Attached data-field appendices require tranche-level disclosures on cost evolution, ratepayer allocation, and revenue-requirement modeling. ### Commissioner Comments from the Dais - **Commissioner Matthew Baker** characterized the deal as PG&E exchanging decades of future transmission revenues and profits for upfront capital that is useable today. Baker cited PG&E's low share price and below-investment-grade ratings as making traditional market access "very, very difficult," and noted that Citizens' payments are not recorded as debt or equity and consequently do not affect PG&E's capital structure or credit profile. - Baker pointed to wildfire costs as the main driver pushing PG&E toward novel financing, and cited the legislature's recently enacted Transmission Infrastructure Accelerator as part of a longer-term solution. - **Commissioner Christine Harada** acknowledged PG&E's progress since bankruptcy but described the company's financial position as "structurally fragile" relative to its peers, and explicitly disclaimed any view that this decision constitutes bailing out PG&E. - Harada framed the approval as a one-time, fact-dependent framework specific to PG&E's unique and "hopefully temporary" financial situation, not a model for future requests. - **President John Reynolds** tied his support to the ratepayer benefit story, noting the escalating profit-share structure (50% on Tranche One, rising to 90% on Tranche Five) and the over $450 million in projected bill assistance. In dissent, Commissioner Houck argued that the Public Utilities Code and General Order 173 require a formal application for utility property transactions exceeding $5 million, and that approving roughly $1 billion of leases through five Tier 3 Advice Letters does not meet the required legal standard. Houck cited TURN's estimate that ratepayers could save roughly **$740 million** across the five tranches by financing through securitized debt instead of the proposed lease structure, and argued the proceeding lacks any real assessment of ratepayer cost. She recommended denying the application without prejudice, or holding the proceeding open for a supplemental application. **INSTANT ANALYSIS:** This decision opens a new transmission financing lane under strict supervision, but the economics are contested. TURN placed Citizens' implied annual return above 9% versus PG&E's projected 6.0%-to-6.5% cost of new long-term debt. Citizens itself conceded a 6.93% return would clear lender requirements. The decision does not cap the return, but the concession is preserved and will reappear at every tranche review. $450 million in bill assistance is what makes the deal politically viable. Without it, the CPUC would be approving an above-market return for a non-utility investor during an affordability crisis. Two provisions give the CPUC room to reverse course. The CPUC may revisit necessity if PG&E's credit rating returns to investment grade. And Cal Advocates has formally contested the premise that PG&E cannot self-fund, meaning intervenors can reopen the necessity question at every tranche. --- ## SCE GENERAL RATE CASE PHASE 2 A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K740/605740663.PDF?ref=calregulatory.com) resolves SCE's 2024 rate-design case. The decision approves nine of 10 settlements that parties negotiated and rejects the tenth, a Vehicle-to-Grid rate proposal. The decision also rejects three contested proposals that didn't make it into settlements: - SCE's PRIME Plus rate; - A baseline allowance increase pushed by TURN; and - A transmission marginal cost methodology pushed by [the solar industry](https://seia.org/about/?ref=calregulatory.com). New rates take effect no earlier than **October 1**. The settling parties get a four-year transition that lifts residential Time-of-Use price differentials to **80%** of marginal cost, except PRIME, which goes to **100%**. Recall that PRIME is the rate aimed at households running heat pumps, electric vehicles, and storage. Its seasonal differential jumps from **2.4 cents** to **6 cents** per kilowatt-hour, and its peak-to-off-peak price ratio reaches full marginal cost by year four. Generation capacity costs are set at **$132.72** per kilowatt-year. Generation energy values are taken from the 2024 [Avoided Cost Calculator](https://www.cpuc.ca.gov/dercosteffectiveness?ref=calregulatory.com). Wildfire cost recovery is the most consequential piece for class-allocation work. About three-quarters of the wildfire revenue requirement is allocated to customer classes in proportion to the revenue they already pay, meaning residential picks up a residential-sized share, large power picks up a large-power-sized share, etc. The remaining quarter is allocated based on each class's actual use of the distribution system, where most wildfire mitigation spending occurs. The allocation gets redone every year using updated sales, customer counts, and class revenue shares, so the percentages each class pays will drift over the term of the settlement. Large power customers receive continuity. The settlement keeps Option D and Option E intact across voltage tiers and sets the monthly customer charges directly: **$1,140.50** for TOU-GS-3, **$2,514.50** for TOU-8 secondary, **$313.25** for primary, **$8,512.50** for subtransmission. On electric vehicles, the settling parties agree that any rate changes taking effect after 2030 should be decided in a different proceeding, and that proceeding should ideally cover PG&E and SDG&E too so the three utilities don't end up with three different EV rate structures. **INSTANT ANALYSIS**: The CPUC is using the Avoided Cost Calculator selectively. It accepted the calculator as the source for generation energy values in the main settlement, then two settlements later rejected using it to set EV export compensation, agreeing with Cal Advocates that forecasted averages can't capture real-time or locational grid conditions. The CPUC seems comfortable using the calculator for embedded cost recovery but unwilling to use it as a price signal for customers selling power back. The list of evaluations the CPUC wants done first on Vehicle-to-Grid tells you where it's heading on export compensation generally. Three of the four rejections aren't substantive losses, they're forum punts. PRIME Plus moves to the rate rulemaking the CPUC just opened ([R.26-04-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K677/604677976.PDF?ref=calregulatory.com)). The transmission marginal cost question moves to the cost study already underway, aimed at the 2028 update cycle. TURN's baseline argument got a genuine concession buried in the rejection: the decision agrees that, as more customers install rooftop solar, SCE's measure of average residential usage keeps dropping, which shrinks the baseline allowance for everyone else (even though their actual energy needs haven't changed). The decision says a solution belongs in a rulemaking encompassing all three electric utilities. --- ## RISK-BASED DECISION-MAKING FRAMEWORK A [successor docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com), launched today, will continue refining the [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com) that governs how utilities propose safety spending in General Rate Cases. The proceeding has four objectives: - Incorporating a formal risk tolerance standard into the framework; - Modifying the [Risk Assessment & Mitigation Phase](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/risk-assessment-and-mitigation-phase?ref=calregulatory.com) schedule to give the CPUC's [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) more review time; - Updating the Benefit-Cost Ratio methodology; and - Assessing whether small gas utilities [Alpine Natural Gas](https://alpinenaturalgas.com/?ref=calregulatory.com) and [West Coast Gas](https://www.westcoastgas.com/?ref=calregulatory.com) should be required to file annual [Risk Spending Accountability Reports](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/risk-spending-accountability-reports?ref=calregulatory.com). The docket's risk tolerance track picks up where [D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com) left off. That decision defined risk tolerance but declined to adopt a formal standard, delegating the work here. The CPUC will seek party proposals on both a formal tolerance standard and a benchmark tied to everyday risks Californians already accept. The RAMP schedule track responds to a documented pattern: the CPUC's Safety Policy Division has received deadline extensions on every RAMP filed since 2020, running about two months each time. The new rulemaking proposes formalizing additional review time, starting with PG&E's 2028 RAMP. The Benefit-Cost Ratio track addresses two gaps: - Inconsistent utility treatment of O&M expenses; and - A Present Value Revenue Requirement field that is currently optional but may be made mandatory. A parallel joint application ([A.26-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101196.PDF?ref=calregulatory.com)) on Benefit-Cost Ratio methodology for the [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) may inform this work. ### Commissioner Comments from the Dais - **President John Reynolds** highlighted four focal areas: a risk tolerance standard, extended RAMP review timelines, standardized O&M treatment/data requirements, and expanded RSAR reporting. He noted that a 2025 decision ([D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com)) deferred the risk tolerance question, making this proceeding the vehicle to resolve it. Reynolds also connected the framework directly to future cost recovery, including programs like [Senate Bill 884 undergrounding](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). - **Commissioner Darcie Houck** warned against "risk reduction at any cost,” noting that zero risk is unattainable. She encouraged the integration of existing affordability metrics into Benefit-Cost Ratio analyses for more granular ratepayer impact assessment. - **Commissioner Christine Harada** broadened the risk landscape beyond wildfires to include floods, cybersecurity threats, and pipeline failures. - Harada supported the concept of a risk-tolerance standard, drawing parallels to engineering disciplines that operate within defined “risk envelopes." - Harada emphasized that limited budgets require explicit tradeoffs rather than implicit escalation of spending. - Harada suggested the Risk-Based Decision-Making framework can improve decision-making by defining acceptable risk ranges rather than pursuing absolute minimization. **INSTANT ANALYSIS:** Framework proceedings move slowly and attract less attention than contested rate cases, but their outputs are load-bearing. The risk-tolerance track is where the hardest policy question will surface: California has spent a decade building tools for quantifying utility risk without ever specifying how much unmitigated risk is acceptable. --- ## CLIMATE CREDIT A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K823/605823091.PDF?ref=calregulatory.com) orders interim, timing-only changes to the residential Climate Credit, reserving amount, eligibility, and calculation for Phase 1B of [this proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com). The statutory basis for the decision is [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com)'s amendment to Public Utilities Code, which requires distribution in no more than four high-billed months annually. PG&E, SCE, and SDG&E will distribute the electric credit in August and September beginning in 2026\. A March decision ([D.26-03-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K306/603306591.PDF?ref=calregulatory.com)) paused the April distribution to enable this. The Small and Multi-Jurisdictional Utilities will distribute the credit in November 2026, then October and November in 2027 (one credit is retained in October because seasonal load variation in those territories is less pronounced). Gas utilities will move to a single February distribution, beginning in 2027. The decision also redirects 5% of allowance auction revenues from ratepayer return to transmission financing, implementing AB 1207's Transmission Accelerator Revolving Fund provision. Remittances to the State Treasury run from July 1, 2026 through July 1, 2031. **INSTANT ANALYSIS:** The Climate Credit is no longer a complete pass-through to ratepayers. Five percent being redirected to transmission financing for five years is modest in dollars but precedential. AB 1207 extended [Cap and Invest](https://ww2.arb.ca.gov/our-work/programs/cap-and-invest-program?ref=calregulatory.com) through 2045, and the CPUC has established that allowance revenues are available for appropriation toward adjacent purposes. Distribution upgrades, wildfire mitigation, and DER buildout are the obvious next targets. The timing change supplants the price-signal rationale with a bill-offset rationale. The CPUC's 2014 and 2018 designs placed credits in shoulder months to preserve conservation incentives and maximize per-bill visibility. But now, immediate affordability takes precedence. --- ## ERRA COMPLIANCE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K456/605456157.pdf?ref=calregulatory.com) approves SDG&E's 2023 ERRA compliance application, finding the utility's procurement, dispatch, contract administration, and accounting practices reasonable and consistent with CPUC standards, with a net undercollection of **$214.6 million**. The decision adopts three negotiated corrections developed with intervenors: - Updates the valuation of retained Resource Adequacy; - Corrects the Renewables Portfolio Standard position; and - Books 2023 revenues from the Miguel Vanadium Redox Flow and Ramona Air Attack Base battery systems to the Electric Distribution Fixed Cost Account, rather than a generation balancing account that would have flowed only to bundled customers. Most issues were resolved without dispute. Cal Advocates secured one operational directive: SDG&E must consult with intervenors on data-request quality from its new settlement system, a requirement likely to carry over to other utilities operating new settlement platforms. The decision declines to resolve allocation of stranded costs from the failed [Green Tariff Shared Renewables](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-rates/green-tariff-shared-renewables-program?ref=calregulatory.com) programs, finding the record insufficient to determine whether costs should be borne by all ratepayers, former participants, or shareholders. This marks a reversal from the [original February 13 proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com), which would have authorized recovery from all ratepayers via the Public Purpose Program charge. Following Rule 14.3 comments from San Diego Community Power and Clean Energy Alliance, an [April 22 revised PD](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K454/605454958.PDF?ref=calregulatory.com) removed all GTSR findings and substituted an "insufficient record" determination. In a subsequent [ex parte communication](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K521/605521799.PDF?ref=calregulatory.com), SDG&E sought reinstatement of the original approach, arguing the record supported socialized recovery and that the revision deleted supported findings without explanation. Thursday's final decision adopts the revised treatment and leaves the issue open for further proceedings. **INSTANT ANALYSIS:** This decision punts on GTSR cost allocation. SDG&E loses both a clean recovery path and the underlying prudence findings that would have shaped future GTSR cycles, while the CCAs secure removal of adverse findings without yet winning on the merits. The cost-allocation dispute now resets on an open record, with a statutory question (whether the CPUC can socialize GTSR costs to non-participants at all) back in play. All three pathways remain viable: recovery from all ratepayers, recovery from former program participants, or absorption by shareholders. This will return as a focused dispute with real rate impacts. --- ### DISTRIBUTED GENERATION [Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K799/605799271.pdf?ref=calregulatory.com) raises the [DGStats](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) budget from $990,000 to **$2.6 million** per three-year cycle and delegates annual inflation adjustment to Energy Division. The existing $990,000 remains in current General Rate Cases; the $1.61 million increment will be tracked through memorandum accounts and recovered in each utility's next rate case (SDG&E Test Year 2028, SCE TY 2029, PG&E TY 2031). PG&E, SCE, and SDG&E must update their online interconnection application interfaces with: - Validated drop-down menus for generators, inverters, and batteries; - Auto-calculated System Size (DC) values in [Photovoltaics for Utility Scale Applications](https://www.sciencedirect.com/science/article/abs/pii/0379678789900343?ref=calregulatory.com) Test Condition; and - Standardized language and data validation rules for the Total Cost field. Applicants will provide the inputs; the utilities will implement the interface controls. The resolution is emphatic that utilities are not responsible for verifying cost data accuracy. Decommissioning is a new focus area. The utilities must begin reporting standardized decommissioning reasons (Replaced, Retired-functional, Retired-non-functional, Destroyed, Abandoned, Other) to DGStats. Energy Division is authorized to publish a limited set of [CSLB](https://www.cslb.ca.gov/?ref=calregulatory.com) Disclosure Document fields on DGStats: ownership structure (Power Purchase Agreement/lease vs. purchase), total system cost for cash and loan transactions, and battery capacity. These were selected because they already appear in the public interconnection dataset, which is also why the CPUC concluded a Primary Purpose declaration under [D.11-07-056](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/140369.PDF?ref=calregulatory.com) was unnecessary. The CPUC, not the utilities, will rename the DGStats platform after SDG&E argued branding falls within Commission jurisdiction. **INSTANT ANALYSIS:** The utilities lost. They tried to push data-quality directives into [R.25-08-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M576/K867/576867418.PDF?ref=calregulatory.com), the distribution-level interconnection rulemaking, where they would have years to litigate them. SCE argued the CPUC can't even do staff resolutions like this. PG&E said its IT team needed more time. SDG&E said the cost field changes overstepped Rule 21's purpose. Resolution E-5436 rejects the venue argument, gives PG&E a 60-day extension, and adopts the data-quality directives, decommissioning workshop, and CSLB publication authority over utility objections. Interconnection interfaces (long treated by utilities as their own technical territory) are now subject to Energy Division specification on equipment lists, cost field language, and system size calculation methods. The Commission's hope is that future data will become cleaner, more standardized, and harder to argue about, which changes who has the better numbers in debates about NEM cost shifts, DER penetration, and procurement need. ### WEDNESDAY AGGREGATE: LOLE Inputs, Capacity Screens, and Industrial Load Delays URL: https://www.calregulatory.com/wednesday-aggregate-24/ Last updated: 2026-04-29T23:57:25.000Z Today's briefing covers the following matters. - **RESOURCE ADEQUACY:** Analysis of work that the CPUC's Energy Division is doing to inform a 2028 [Loss of Load Expectation](https://docs.energytransitionmodel.com/main/loss-of-load-expectation/?ref=calregulatory.com) Study. - **ENERGIZATION:** PG&E's tariffed response to new energization mandates. - **INFRASTRUCTURE**: Slow regulatory movement on a tariff meant to incentivize industrial load. Additionally, see our **April 30** CPUC voting meeting preview, which is available [here](https://www.calregulatory.com/april-30-cpuc-voting-meeting-preview-rng-retreat-hydrogen-denial-pg-e-financing-test/). We will provide full results following the meeting tomorrow afternoon. [RNG Retreat, Hydrogen Denial, PG&E Financing TestAn April 30 meeting could produce decisions touching utility finance, hydrogen, RNG mandates, wildfire cost allocation, and retail bill relief.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Apr-16-2026--13-.png)](https://www.calregulatory.com/april-30-cpuc-voting-meeting-preview-rng-retreat-hydrogen-denial-pg-e-financing-test/) --- ### RESOURCE ADEQUACY Parties filed comments in the CPUC's Resource Adequacy docket in response to Energy Division's [April 9 Draft Inputs and Assumptions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K617/604617992.PDF?ref=calregulatory.com), which will inform a 2028 Loss of Load Expectation Study. Energy Division runs the LOLE study using SERVM, the [Strategic Energy Risk Valuation Model](https://www.pnm.com/documents/28767612/29099013/Astrape+IRP+Presentation%5Fv4%5F11%5F10%5F16%5Fpost.pdf/0f477641-9bf4-474d-baa5-a6ca857bf7d0?t=1683712292782&ref=calregulatory.com). Parties' comments will shape the Planning Reserve Margin that is eventually adopted for 2028-2029 Resource Adequacy compliance. - No party supports the draft as filed. Four parties ([SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K311/605311421.PDF?ref=calregulatory.com), the [Alliance for Retail Energy Markets](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K320/605320620.PDF?ref=calregulatory.com), [Middle River Power](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K267/605267278.PDF?ref=calregulatory.com), and the [California Environmental Justice Alliance/Sierra Club](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K521/605521779.PDF?ref=calregulatory.com)) object to Energy Division tuning model inputs to hit the 0.1 LOLE target, which represents the standard of one loss-of-load event every ten years. - CEJA-Sierra Club go further, asking the study to report unserved energy and loss-of-load hours alongside the headline LOLE number. CEJA-Sierra Club note that prior-cycle results showed the 0.1 LOLE standard was met even as loss-of-load hours remained near zero. They also identify more than 3,000 MW of resources, including over 2,000 MW of storage, that came online between the August 2025 data cutoff and March 2026 (already operating but excluded from the model). - On imports, parties take three positions. - CalCCA [defends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K320/605320632.PDF?ref=calregulatory.com) the draft's 4,000 MW import assumption using seven years of actual CAISO showings (minimum summer imports never fell below 3,125 MW even during the tight 2022 conditions). - SCE accepts the 4,000 MW floor but objects to applying it across all 12 months, noting that overnight imports averaged 6,800 MW in September 2025 and 8,700 MW in January 2026\. - The [Western Power Trading Forum](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K311/605311425.PDF?ref=calregulatory.com) and [American Clean Power-California](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K578/605578332.PDF?ref=calregulatory.com) push the opposite direction: the 2024-vintage [Western Electricity Coordinating Council](https://www.wecc.org/?ref=calregulatory.com) dataset that Energy Division relies on misses the multi-gigawatt capacity shortfalls now visible in the Pacific Northwest, Nevada, Arizona, and PacifiCorp planning documents. - American Clean Power-California adds that California-internal capacity may start flowing outward to neighboring regions as new Western reliability programs take effect. - The treatment of Unforced Capacity (UCAP), which is the convention that derates resources for forced outages, draws aligned support with one objection. SCE, [NextEra Energy Resources](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K311/605311412.PDF?ref=calregulatory.com), Middle River, and American Clean Power-California back implementation; SCE and Middle River want a backup Planning Reserve Margin available in case the parallel Track 1 proceeding doesn't deliver a timely UCAP framework. NextEra argues that combining UCAP with Energy Division's separate assumption that batteries discharge only 90% of nameplate capacity double-penalizes storage. NextEra says the solution is to either raise the discharge assumption or apply UCAP to only that 90%. - On load forecasting, SCE argues SERVM assumes too wide a range of forecast error. Applied as a flat hourly adjustment, the assumption produces 600 MW of phantom overnight load (periods when no real-world economic shock would occur). CalCCA challenges the assumption at its source. Energy Division's forecast error distribution comes from a [2010 paper on European GDP forecasting](https://www.oecd.org/en/publications/oecd-journal-journal-of-business-cycle-measurement-and-analysis/volume-2010/issue-2%5Fjbcma-v2010-2-en.html?ref=calregulatory.com), with no documentation that European GDP forecasting is a reasonable proxy for California peak demand. CalCCA tested it against nine years of actual California forecast errors. The test could not reject the assumption, but the sample was too small to confer confidence either way. CalCCA proposes a Bayesian framework that would update the distribution as new error data accumulates. - CalCCA and American Clean Power-California want additional workshops before the August 14 study deadline. The prior cycle ended with adopted Planning Reserve Margins described only as directionally consistent with study results, and both parties want to avoid a repeat. To shape the study rather than the post-hoc PRM translation, workshops would need to occur well before mid-July. - CEJA-Sierra Club challenge SERVM's loss-of-load trigger definition itself. California declares a loss-of-load event the moment operating reserves erode, while every other major Western grid operator credits operating reserves and demand response before declaring one. CEJA-Sierra Club also point to resources the model omits entirely: the Strategic Reliability Reserve at approximately 3,079 MW, emergency demand programs, and the post-cutoff additions noted earlier. **INSTANT ANALYSIS:** These filings form [a pincer](https://en.wikipedia.org/wiki/Pincer%5Fmovement?ref=calregulatory.com). CalCCA, CEJA-Sierra Club, and SCE present evidence that SERVM treats California more pessimistically than reality justifies. The Western Power Trading Forum and American Clean Power-California present evidence that it treats the broader West more optimistically than reality justifies. Both critiques cannot be dismissed simultaneously, and they offset only by accident. A defensible path is disaggregation: the CPUC should publish reliability metrics for external regions under the no-calibration baseline, publish the resources excluded from the internal model, and let the offsetting errors sit visibly in the record rather than hidden inside a single Planning Reserve Margin number. An August 14 deadline makes that harder, which is why the workshop request matters. Without intermediate process, the translation from study results to adopted PRM will again be opaque, as it was in a 2025 decision ([D.25-06-048](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K237/571237404.PDF?ref=calregulatory.com)). Storage has the most at stake on UCAP. If Track 1 produces a framework in time, the battle worth watching is whether batteries get penalized twice (once by the 90% discharge cap, once by UCAP). If not, the CPUC will end up running two Planning Reserve Margins in parallel and will need to explain why that does not amount to two reliability standards. --- ### ENERGIZATION PG&E filed [Advice Letter 7899-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7899-E.pdf?ref=calregulatory.com) to formalize a Preliminary Capacity Assessment, as directed by a recent decision ([D.26-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K715/598715449.PDF?ref=calregulatory.com)) in the CPUC's Timely Energization rulemaking. (*See CRI's summary of that decision* [*here*](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/)*.*) [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/02/iterograph_Tue-Feb-03-2026.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) - The Preliminary Capacity Assessment is an optional, customer-initiated screen that estimates whether distribution capacity exists at a specific location to serve a proposed load before a formal application for service. Any prospective customer can request one. The customer submits project details and a **$3,000** non-refundable fee, and PG&E delivers a standardized report within 30 days. This clock begins when PG&E deems the request complete, payment is received, and the study starts (not at submission). Reports categorize the result as full capacity available, partial, or none until a later date, with constraints and timing where feasible. - The Preliminary Capacity Assessment does not reserve capacity, does not guarantee service, cannot be converted into a formal application, and is limited to the distribution system. In the interim, distribution planning engineers perform the assessments manually. PG&E plans to migrate the backend to its Automatic Capacity Evaluator, expected operational in 2027, which will compare customer load against Load Integration Capacity Analysis values at the point of connection. The customer-facing intake form, report format, and fee are designed to remain stable through that transition. PG&E and SCE coordinated the filings but differ on two points. SCE accepts requests through its existing [Building, Renovation, and Project Planning Portal](https://www.sce.com/projectportal?ref=calregulatory.com); PG&E will build a new intake interface. SCE's Preliminary Capacity Assessment can include sub-transmission (66 kV and 115 kV); PG&E's distribution system has no comparable tier and routes transmission-level requests elsewhere. The $3,000 fee matches SCE's Engineering Analysis Report fee. **INSTANT ANALYSIS:** PG&E is creating a tariffed, repeatable front-end with defined timelines, defined outputs, and a fee that mirrors SCE's. Customers gain a clearer read before committing capital and PG&E gains an intake that holds its shape as the backend migrates. The Automatic Capacity Evaluator ties capacity screening to Load Integration Capacity Analysis data, the dataset authorized through [AL 7490-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7490-E.pdf?ref=calregulatory.com) and a 2024 CPUC decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)). Once operational in 2027, distribution capacity screening will become faster, more scalable, and more visible. That can expedite site evaluation cycles for developers and standardize what was previously a relationship-dependent process. Fee adjustments are anticipated at full deployment. --- ### INFRASTRUCTURE TIMELINES The CPUC issued [Draft Resolution E-5388](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K723/605723623.PDF?ref=calregulatory.com), proposing to extend the timeline for [Pacific Steel Group](https://pacificsteelgroup.com/?ref=calregulatory.com) to begin receiving a discounted [Economic Development Rate](https://www.sce.com/sites/default/files/inline-files/EDR%5FFact%5FSheet.pdf?ref=calregulatory.com) (EDR-A) from SCE. Under existing tariff rules, customers must start taking service within 24 to 36 months of executing an agreement. SCE’s Method of Service study concluded that serving Pacific Steel would require a new 50 MW substation with a three- to five-year construction timeline. The draft resolution does not approve Pacific Steel’s participation in the EDR program. Pacific Steel has filed only a Letter of Intent for a **$630 million** steel recycling mill in Mojave, which is projected to create 400 jobs. It must still apply, secure SCE approval, pass a Governor’s Office of Business and Economic Development review, and execute a formal agreement before receiving the **12%** EDR-A discount. The earliest the CPUC will consider this item is **May 14**. **INSTANT ANALYSIS:** SCE told the CPUC it needs three to five years to build a 50 MW substation for Pacific Steel. Anyone siting industrial load in SCE territory now has a Commission-accepted benchmark for interconnection timelines. The 60-month window is not a new policy. The existing tariff already allows 36 months when infrastructure must be built. This draft adds two more years for substation-scale work. If the next large applicant seeks similar relief, this starts to look like a repeatable template. Note the timing here. SCE filed its request in August 2024\. The tentative vote date for Draft Resolution E-5388 is May 14, 2026\. There are no protests to address. Twenty-one months for uncontested relief under a tariff meant to attract industrial load tells quite a story. ### Aliso Canyon Workshop Comments: Demand, Supply Risk, and Cost URL: https://www.calregulatory.com/aliso-canyon/ Last updated: 2026-04-29T22:59:15.000Z Three parties filed April 28 opening comments following an Aliso Canyon Biennial Assessment Workshop earlier this month. (*See CRI's workshop report* [*here*](https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/)*.*) [April 15 Aliso Canyon Biennial Assessment Workshop SummaryThe first Aliso Canyon Biennial Assessment Workshop exposed a conflict over whether reliability depends on storage or on optimistic assumptions.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/iterograph_Tue-Mar-31-2026--16-.png)](https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/) **At issue:** The CPUC is deciding how much natural gas must remain in storage at Aliso Canyon to maintain reliability without imposing unnecessary costs on ratepayers. There are three main variables at play: how much demand should be assumed, how much supply can fail at once, and how to measure the cost of getting the levels wrong. - Sierra Club [presses for an inventory level of 30 Bcf](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K854/605854339.PDF?ref=calregulatory.com). - SoCalGas [opposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K853/605853788.PDF?ref=calregulatory.com) any reduction to the field's inventory level and proposes a new economic framework designed to quantify ratepayer harm. - The Indicated Shippers [anchor the record](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K521/605521833.PDF?ref=calregulatory.com) with Commission-validated cost figures and push to slow the timeline. ### Sierra Club Sierra Club advances the most aggressive inventory position. Its 30 Bcf figure traces to a workshop exchange where [**Dr. Issam Najm**](https://www.linkedin.com/in/issam-najm-208a0718/?ref=calregulatory.com) got Energy Division staff to confirm that 19 of 27 winter 2025-2026 reliability scenarios required only 44% of capacity (about 30 Bcf against the 68.6 Bcf maximum). Those scenarios already use SoCalGas's 1-in-10 peak day forecast, which actual demand has exceeded once in 22 years. Sierra Club attacks SoCalGas's peak demand forecast at the input level instead of assessing its mathematical structure. SoCalGas uses temperature data back to 1950 despite acknowledging warming trends in [2024 California Gas Report](https://www.socalgas.com/sites/default/files/2024-08/2024-California-Gas-Report-Final.pdf?ref=calregulatory.com) Workpapers. Sierra Club argues this selection of data inflates demand and pushes to replace SoCalGas's forecast with the California Energy Commission's independent forecast (year-ahead now, with 5- and 10-year products incorporated as the CEC develops them). On Receipt Point Utilization (RPU), Sierra Club aligns with Energy Division and uses SoCalGas's workshop slides against it. SoCalGas concedes on one slide that 100% RPU is reasonable when pipeline capacity is reduced, then on another applies low RPU values on top of outage assumptions. The two positions contradict each other. At its core, Sierra Club's safety argument is an appeal to statute. [Public Utilities Code §451](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-3/article-1/section-451/?ref=calregulatory.com) and [Senate Bill 380](https://calmatters.digitaldemocracy.org/bills/ca%5F201520160sb380?ref=calregulatory.com) (which references "safety" more than 20 times) place safety above reliability. Sierra Club argues that the following instances are not mere facts, they support a claim that the CPUC must prioritize safety over reliability. - The [2015 Aliso Canyon blowout](https://en.wikipedia.org/wiki/Aliso%5FCanyon%5Fgas%5Fleak?ref=calregulatory.com) - A [2017 Line 235 explosion](https://www.sandiegouniontribune.com/2019/07/11/after-aliso-canyon-a-gas-pipeline-exploded-costing-californians-1-billion/?ref=calregulatory.com) - A [December 2025 Castaic landslide](https://www.socalgas.com/castaic-line-break-repair?ref=calregulatory.com) - A peer-reviewed UCLA study on adverse pregnancy outcomes - Ongoing emissions, including carcinogens On economics, Sierra Club defends the current threshold framework (a simple comparison that notes inventory reductions when SoCal Citygate forward prices exceed 50% above Henry Hub and historical levels). SoCalGas wants to replace this framework. Sierra Club's filing concedes that the framework's analysis is basic but argues more complexity would only delay biennial reviews. Sierra Club also notes that existing triggers were adopted in the CPUC's 2024 Biennial Assessment decision ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)) over party objections they were biased toward keeping Aliso open. Sierra Club's argument, distilled to its purest form: if a framework that is geared toward retention still supports reduction, the case for reduction is stronger, not weaker. ### SoCalGas SoCalGas criticizes the idea of any inventory reduction and proposes a replacement framework designed to produce the first quantified ratepayer harm number. SoCalGas's RPU critique points to actual conditions: - **46%** during 2021 Winter Storm Yuri; - **36%** during the 2024 Arctic Blast; - **36%** during the 2025 Southwest Winter Storm; and - **25%** during 2026 Storm Fern. SoCalGas's pipeline critique is specific. Energy Division reduced pressure while maintaining full receipt capacity, left constrained assets in the model, and averaged outage impacts. SoCalGas counters with event data: - A **655 MMcfd** loss on Line 4000/4002; - **150 MMcfd** capacity loss on Line 5000 maintenance; and - **650 MMcfd** lost during the December 27, 2025 Line 225 force majeure at Wheeler Ridge. SoCalGas also argues that Energy Division chose the wrong outage scenario for winter 2030-2031 (Line 235 West, east of Quigley) because parallel paths like Line 335 readily reroute that flow. Further, reliability for 2030-2031 depends on upgrades that are not complete: - Quigley; - Honor Rancho; and - Ventura (which is necessary to refill La Goleta every summer). Until these projects are proven under peak conditions, SoCalGas says, any reduction is premature. SoCalGas's economic critique attacks a logical flaw in Energy Division's analysis. ED's threshold comparison uses forward prices as evidence that storage reductions are economically safe, but those forward prices already assume Aliso Canyon stays open at current inventory levels. This analysis cannot measure what would happen to prices if Aliso were cut, because the prices it relies on assume Aliso **isn't** cut. [**Jean Spencer**](https://www.linkedin.com/in/jean-spencer-13068a18/?ref=calregulatory.com) conceded this point at the April 15 workshop. In response, SoCalGas offers a new framework: a Predictive Price Impact Analysis and Storage Behavior and Price Volatility Analysis, which combines multi-basin price spreads and simulation-based modeling. This design would isolate the storage premium and output a "theoretical premium to ratepayers of reduced storage capacity." SoCalGas ties that value to a real mechanism. The Unbundled Storage Program is fully subscribed at 25 Bcf and returns 100% of net revenues to ratepayers. A 10 Bcf reduction would be borne entirely by the Unbundled Storage Program, removing a price-mitigation tool and its associated revenues. Strategically, SoCalGas proposes replacing the current biennial cycle with a cycle that examines projected reliability conditions five years forward. SoCalGas proposes to: - Apply RPU after accounting for outages (rather than relative to nominal capacity); - Replace the biennial assessment methodology's **101.5 MMcfd** unplanned outage figure with a per-cycle determination; and - Model outages by asset removal. SoCalGas is looking to place the first authoritative ratepayer harm number into the evidentiary record under a method the CPUC has invited it to develop. ### Indicated Shippers The Indicated Shippers take no inventory position and mostly adopt SoCalGas's critique. They lay the groundwork for slowing the proceeding. The Shippers frame Aliso Canyon as critical to regional reliability and extend that argument beyond SoCalGas's territory. The state's August 2020 rotating outage (the first such event in nearly two decades) showed how gas storage backs generation when imports fall and renewables underperform. This expanded geography widens the affected ratepayer base to CAISO Northern Zone customers, whom the refiner clients don't serve. The Shippers' strongest evidence is historical. A 2021 CPUC decision ([D.21-11-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M421/K086/421086399.PDF?ref=calregulatory.com)) attributes approximately **$599 million** in excess costs to CAISO south-zone customers and **$317 million** to north-zone customers due to constrained Aliso inventories. These are Commission-validated figures, not modeled outputs. ### INSTANT ANALYSIS The economic analysis that everyone agrees is inadequate is going to be replaced (or supplemented). SoCalGas has proposed the only specific replacement, and if the CPUC adopts any version of it, SoCalGas will produce the first dollar estimate of ratepayer harm associated with a reduction in Aliso inventory. Sierra Club’s counterargument is that safety sits above all else. Its case is factual and legal, not expressed in a comparable numerical framework. SoCalGas is producing numbers, but Sierra Club is saying those numbers are largely irrelevant. The 2030–2031 reliability picture remains unsettled. SoCalGas ties any reduction to completion of Quigley, Honor Rancho, and Ventura. Energía Costa Azul diversions of 425–440 MMcfd and Line 225 vulnerability at Wheeler Ridge compound the risk regardless of how RPU is resolved. Reply comments are due **May 5.** ### MONDAY AGGREGATE: PG&E GRC Judges Challenge Forecasts, Capitalization, Undergrounding Costs URL: https://www.calregulatory.com/monday-aggregate-pg-e-grc-judges-challenge-forecasts-capitalization-undergrounding-costs/ Last updated: 2026-04-27T20:14:05.000Z Today's briefing covers the following matters. - **PG&E GENERAL RATE CASE**: In a new ruling, CPUC judges tell PG&E to show its math. They note potential problems in cost forecasts, spending assumptions, and accounting treatment, and are forcing the utility to defend its calculations before hearings. - **NATURAL GAS SAFETY:** More safety oversight is coming for utilities and storage operators, and companies that get organized now may face fewer mandates later. - **SDG&E ERRA COMPLIANCE:** SDG&E is trying to recover leftover costs from a renewable energy program that did not work out as planned. There is a dispute on who should pay those costs: all customers, former participants in the program, shareholders, or someone else. --- ## **PG&E GENERAL RATE CASE** A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K438/605438851.PDF?ref=calregulatory.com) in PG&E's 2027 General Rate Case adds three documents to the evidentiary record and puts more than 40 questions across 14 topic areas to PG&E in advance of hearings. The added documents: - PG&E's [data-request responses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K267/605267272.PDF?ref=calregulatory.com); - PG&E's 2026 Natural Gas Leak Abatement Compliance Plan, and - Its responses to **President Reynolds**' PHC questions in A.26-02-005, the joint utility application for approval of the remaining cost-recovery mechanics under the [Senate Bill 884 ten-year undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). The subject of MAT 50A gas pipe replacement inspires the most detailed questioning. The judges computed unit costs from PG&E's own workpapers and put the results in the ruling: 2023 actuals exceeded forecast by **182%**, 2024 actuals by **22%**, and PG&E completed only **26%** of planned 2024 MAT 50A units. The ALJs direct PG&E to recalculate the unit cost forecast on a five-year base that includes the COVID years PG&E excluded, and to produce the Excel workpaper. Gas operations draw parallel scrutiny, e.g., cost-Benefit Ratio discrepancies across about 30 line items between the 2027 General Rate Case and the 2024 Risk Assessment Mitigation Phase filing. The ruling also issues a direct challenge to PG&E's 2.4414 station oil inflation factor, which the ALJs read as a compounded **25%** annual increase over four years. ### **Capitalization** The ALJs ask whether PG&E shifts authorized expense dollars into capital after a revenue requirement is set, placing more in rate base. The judges direct PG&E to calculate an expense-to-capital conversion factor for each of six proposed accounting policy changes: - Gas transmission pipe; - Electric distribution pole treatment; - Pole reinforcement; - Gateway/Colusa long-term service agreements; - Prepaid IT contracts; and - One-time IT-related O&M. Separately, the ALJs require present-value modeling of long-run earned returns on capitalized Administrative & General amounts under two or three discount rate assumptions. ### **Wildfire Undergrounding** PG&E must answer the wildfire undergrounding questions orally by a sponsored witness, and PG&E must identify the witness by **April 27**. The ALJs want answers on four points: - Cost recovery for post-2027 undergrounding if a SB 884 plan is not approved before 2028; - How to prevent double recovery if GRC funding overlaps with future SB 884 years; - Whether outcomes in A.26-02-005 should govern cost review here; and - Support for proposed costs and recovery mechanisms for 2027 and 2028-2030. A separate written question requires 2025 recorded capital expenditures for the wildfire system hardening MAT codes in the format of the existing workpaper. PG&E's proposed bridge (2027 GRC funding plus an annual extension mechanism) will get tested at hearing. ### **Other Areas** New business and EV forecasting draw scrutiny of the two-year historical average for residential Plug-In Electric Vehicle connects, the reliance on California Energy Commission data over PG&E's own actuals for non-residential forecasts, and which lessons from the [Public Utilities Code Section 938 ](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-4/article-14-5/section-938/?ref=calregulatory.com)third-party auditor have been incorporated. **INSTANT ANALYSIS**: The ALJs did more than ask PG&E to explain its work. They ran arithmetic from PG&E’s own workpapers, put the results in the ruling, and are now asking PG&E to defend positions the bench has already tested. The paired capitalization directives deserve close attention. A conversion-factor calculation across six accounting policy changes, alongside present-value modeling of earned returns under multiple discount rates, asks PG&E to translate accounting treatment into ratepayer dollars and shareholder earnings. Numbers like those are hard to argue around once they're in the record. For intervenors, the ruling is a prioritized list of where the ALJs see vulnerability, in writing, before hearings begin. For PG&E, execution risk compounds. The company must defend not just what it asked for, but the logic of how dollars move, why forecasts missed, and how capitalization changes affect ratepayer recovery and shareholder earnings. --- ## **SAFETY CULTURE ASSESSMENTS** A [new ALJ ruling in R.21-10-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K576/605576021.PDF?ref=calregulatory.com) seeks party comments on a Safety Policy Division [Phase 2 staff proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K320/605320642.PDF?ref=calregulatory.com) for implementing safety culture assessments for small and multi-jurisdictional utilities and independent gas storage operators. Recall that this proceeding began in 2021 under [Senate Bill 901](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201720180SB901&ref=calregulatory.com). The CPUC adopted [a Phase 1 framework](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M555/K500/555500176.PDF?ref=calregulatory.com) for large investor-owned utilities in January 2025 and held Phase 2 open for these smaller entities. The ruling poses policy questions on three fronts: - How assessments should treat contractors performing safety-critical functions; - Whether Phase 2 entities should get an advice-letter mechanism mirroring Phase 1's; and - How confidentiality concerns intersect with peer-review versus independent third-party assessment models. On confidentiality, the ALJ presses parties to specify which categories of information need protection, from whom, whether the assessment model changes the answer, what mechanisms already exist, and what role the CPUC should play in enforcement. Opening comments are due **May 25**. **INSTANT ANALYSIS:** Phase 1 covered the large IOUs where wildfire, gas safety, and organizational culture risks are most visible. Phase 2 extends the framework to small and multi-jurisdictional utilities and storage operators. The contractor question shows the CPUC looking past direct employees to outsourced safety-critical work, a known weak point in accountability chains. The confidentiality questions read as the ALJ pushing back on parties who raised concerns without specifying what they actually want protected. Phase 2 entities that build credible internal safety processes now may avoid more prescriptive mandates later. --- ## SDG&E ERRA COMPLIANCE In SDG&E's 2023 ERRA compliance case (A.24-06-001), the utility filed [a written ex parte communication](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K576/605576020.PDF?ref=calregulatory.com), urging the CPUC to restore an earlier proposed decision that would have allowed recovery of stranded [Green Tariff Shared Renewables ](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-rates/green-tariff-shared-renewables-program?ref=calregulatory.com)costs from all ratepayers through the Public Purpose Program charge. For context, an [April 22 revised proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K454/605454958.PDF?ref=calregulatory.com) removed those findings and said the record was insufficient to determine who should bear the remaining costs. SDG&E [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K521/605521799.PDF?ref=calregulatory.com) that the [original February 13 PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com): - Was supported by the record and correctly found SDG&E administered the program reasonably; - Correctly identified design flaws as the cause of the stranded balances; and - Properly rejected retroactive charges on former participants nearly a decade after they left. SDG&E adds that the revised PD pulls the entire factual foundation (findings, conclusions, and ordering paragraphs alike) without explanation, and asks commissioners to restore the original version before the **April 30** voting meeting. **INSTANT ANALYSIS:** This ex parte communication also functions as a response to a March 4 ex parte from San Diego Community Power and the Clean Energy Alliance, the two Community Choice Aggregators serving SDG&E territory. Those parties drove the mismanagement and statutory-bar arguments throughout the proceeding. The revised PD appears more favorable to the CCAs than the original version; it doesn't adopt their affirmative case, but it pulls the utility-favorable findings rather than ratifying them. California clean-energy cost allocation remains contested long after programs unwind. If the CPUC declines to restore the original outcome on April 30, it would suggest reluctance to socialize legacy program balances without explicit statutory cover. Such a position would matter beyond this docket for future voluntary tariff design, CCA-IOU cost-shift disputes, and any proceeding where stranded program costs must be reassigned after subscription falls short. ### FRIDAY AGGREGATE: CPUC Staff Move to Collapse Gas Carbon Value in ACC, IOUs Note DR Capacity Cliff, PG&E Breaches Backbone Floor URL: https://www.calregulatory.com/friday-aggregate-3/ Last updated: 2026-04-25T15:42:19.000Z Below are items in today's briefing. - **AVOIDED COST CALCULATOR**: The CPUC is updating the calculator that sets the dollar value of rooftop solar exports, batteries, and energy-efficiency programs. The current proposal would significantly cut the carbon credit for gas-displacing measures like building electrification, while shifting hourly value away from summer afternoons (and toward winter and weekday peaks). - **DEMAND RESPONSE**: PG&E and SCE filed annual reports on how their DR programs are performing and how much they expect to deliver through 2036. - **DIABLO CANYON:** The IRS ruled that a special Diablo Canyon customer fee counts as PG&E's taxable income, meaning about 29% of every dollar collected goes to taxes instead of the energy programs the fee was designed to fund. This is a loss for consumer advocates who pushed for the ruling and hoped for the opposite result. - **GAS LINE EXTENSION ALLOWANCE:** SoCalGas says a garbage hauler needed new gas service because electric trucks aren't sufficient for the job. An ALJ ruling offers the company a chance to provide evidence. - **NATURAL GAS BACKBONE TRANSMISSION**: On April 23, PG&E dipped below the state's mandated pipeline capacity minimum because three pipeline stations were all shut down for maintenance simultaneously. The shortfall was small and PG&E fixed it the same day by rerouting more gas through a different pipeline coming from Arizona. --- ### AVOIDED COST CALCULATOR A [new ruling in R.22-11-013 issues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K325/605325688.PDF?ref=calregulatory.com) Energy Division's [2026 Avoided Cost Calculator Staff Proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K267/605267261.PDF?ref=calregulatory.com) for party input. The ACC sets Net Billing Tariff export credits, DER program screens, and storage and electrification portfolio economics across the state, so these routine updates deserve close attention. Staff want to collapse the gas-sector carbon value onto the electric-sector value from the [Integrated Resource Planning framework](https://www.cpuc.ca.gov/irp/?ref=calregulatory.com). Three pieces move together: - A single cross-sector value; - Removal of the Rebalancing adjustment; and - A cap at the high societal cost of carbon. Energy Division is pushing for all three to be adopted as a set. The table below shows that by 2054 the gas carbon value runs near **$1,200/tonne** while the electric and societal values sit near **$550**. Collapsing gas onto the electric curve could significantly reduce the long-run carbon-driven value case for Renewable Natural Gas, gas efficiency, and building electrification. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/ACC1.png) Staff defend the move by arguing the current gas number was always a placeholder figure from a 2021 CEC study that never lined up with the CPUC's main planning model, and that rebuilding it properly belongs somewhere other than this proceeding. The practical effect is that the gas carbon number is now driven by IRP inputs rather than developed inside R.22-11-013. Staff are also scrapping the 2024 model that jointly calculates capacity and carbon values. That version ran in Python, and parties complained it was a black box: small changes to inputs from the CPUC's planning models produced large, unpredictable swings in the outputs. The replacement is a simpler Excel calculation that parties can open and audit directly. Staff bracket the result with a ceiling at the high societal cost of carbon and two floors: - One tied to the operating cost of keeping existing gas plants online for reliability; and - The other tied to Cap-and-Trade allowance prices. Ratepayer advocates will want the ceiling lower. Clean-energy parties will want the floors gone. Hourly capacity allocation gets three refinements: - Frequency of loss-of-load replaces magnitude; - [SERVM](https://power-gem.co/software/servm-resource-adequacy-planning/?ref=calregulatory.com) energy prices replace temperature for identifying stressed days; and - Weekday risk is split from weekend. Staff point to planning models showing that the riskiest hours on the grid are shifting from summer afternoons to winter, as more solar, storage, and electric buildings change the shape of demand. Transmission allocation gets the same forward-looking treatment: instead of using 2023 CAISO load data for every future year, Staff will use the state's official load forecasts. The net effect is that hourly value moves toward winter peaks, evenings in spring and fall, and weekdays. Under the new proposal, the important numbers (gas carbon, the floors, transmission allocation) are all imported from the IRP and state load forecast. A workshop will convene on **April 29**. Opening comments are due **May 13**, with replies due **May 18**. **INSTANT ANALYSIS:** The new proposal reprices the gas-sector carbon value more than anything else. Staff pre-empted the main objection by casting the existing number as a placeholder, which shifts the conversation from whether to replace it to *what* replaces it. Electrification advocates and gas utilities end up on the same side of the ceiling question for different reasons: electrification loses valuation support as the gas curve compresses, gas utilities lose because sector carbon value now tracks electric decisions made elsewhere. The bundling is deliberate. Parties who want to kill one piece have to explain why the other two should survive without it. The Python-to-Excel shift closes off model-integrity battles and pushes the proceeding onto policy ground, which disadvantages parties whose 2024 strategy leaned on black-box critiques. The new hourly rules change what Net Billing Tariff exports, storage, and summer-afternoon DERs are worth. Rooftop solar compensation shifts without much fanfare, which is how ACC changes usually surface. --- ### DEMAND RESPONSE PG&E and SCE filed their 2025 Demand Response Load Impact Reports, giving the CPUC an 11-year forecast through 2036 and fresh inputs for Resource Adequacy planning. - [PG&E's portfolio](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K383/605383765.PDF?ref=calregulatory.com) runs three supply-side programs ([Automated Response Technology](https://www.pge.com/en/save-energy-and-money/energy-saving-programs/demand-response-programs/automated-response-technology.html?ref=calregulatory.com), [Base Interruptible Program](https://www.pge.com/assets/pge/docs/save-energy-and-money/energy-savings-programs/bip-fact-sheet.pdf?ref=calregulatory.com), [Capacity Bidding Program](https://www.pge.com/en/save-energy-and-money/energy-saving-programs/demand-response-programs/business-programs.html?ref=calregulatory.com#cbp)), four event-based load-modifying programs ([Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com), [Peak Day Pricing](https://www.pge.com/en/account/rate-plans/peak-day-pricing.html?ref=calregulatory.com), [SmartRate](https://www.pge.com/en/account/rate-plans/smartrate.html?ref=calregulatory.com), [SmartAC](https://www.pge.com/en/save-energy-and-money/energy-saving-programs/demand-response-programs/smartac.html?ref=calregulatory.com)), and residential Time-of-Use rates as the sole non-event resource. PG&E's forecasts follow protocols adopted in a 2024 decision ([D.24-12-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K149/550149956.PDF?ref=calregulatory.com)), reported under both PG&E and CAISO peaking conditions. - The BIP trajectory is the quantitative story: portfolio-adjusted impacts run **158–188 MW** per month in 2026 and climb to **238–282 MW** by 2036 (about 50% firm capacity growth from a single program). ART and CBP add **52–76** MW at summer peak; rate-design programs contribute **22–27 MW** as price signals rather than firm capacity. An attached appendix confirms that BIP stays under [D.10-06-034](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/119815.PDF?ref=calregulatory.com)'s emergency Demand Response cap. - PG&E's weather methodology is still the December 2022 Resource Innovations memo built on 2012–2021 data. That memo recommends a two- to three-year update cycle. There is no refresh in the new filing. PG&E is now at the outer edge of its own methodology window. - [SCE's portfolio](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K325/605325676.PDF?ref=calregulatory.com) runs about two to three times PG&E's portfolio in peak months: **425–689 MW** across 2026 under 1-in-2 conditions, against PG&E's **169–312 MW**. Supply-side programs bid into the CAISO as [Reliability Demand Response Resource or Proxy Demand Response](https://www.caiso.com/documents/pdr%5Frdrrparticipationoverviewpresentation.pdf?ref=calregulatory.com); load-modifying programs reshape the net load curve. - The [Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com) is sunsetting, not continuing. A 2023 decision ([D.23-12-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M521/K486/521486520.PDF?ref=calregulatory.com)) extended select subgroups to 2027, but SCE's forecast zeroes ELRP impacts after that. **INSTANT ANALYSIS:** The most reliable Demand Response in California still comes from a small number of large industrial and commercial customers who agree to cut power on short notice in exchange for capacity payments. PG&E's BIP and SCE's BIP-30 are doing the heavy lifting; everything else (residential thermostats, peak pricing, voluntary programs) is either a supplement or a price signal rather than firm capacity the grid can count on. Three things matter for trading desks and utility procurement. - First, there's a regulatory ceiling on how much emergency Demand Response can count toward Resource Adequacy requirements, and PG&E runs an annual test to show BIP stays under it. If BIP grows or performs better than forecast, that ceiling starts to bind and the RA math changes. - Second, the Emergency Load Reduction Program (the pandemic-era summer reliability pilot) is set to end in 2027 at both utilities, removing a meaningful block of dispatchable capacity right as California heads into the next round of tight supply years. - Third, PG&E is still using weather assumptions built on 2012–2021 data, past the refresh window its own consultants recommended. That introduces real uncertainty into the forecasts regulators use to decide how much new supply the state needs to build. For large customers and aggregators, the value is in load that actually drops when called. Voluntary and behavioral programs build participation numbers but don't carry the same weight with planners procuring against worst-case conditions. The next round of CPUC decisions will hinge on performance under stress, not enrollment. --- ### DIABLO CANYON PG&E filed Advice [7897-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7897-E.pdf?ref=calregulatory.com), notifying the CPUC that the IRS has ruled on the tax treatment of Diablo Canyon's Volumetric Performance Fees. The ruling: VPFs are taxable income to PG&E regardless of whether the money funds capital projects or operating expenses. This is the second of two IRS rulings ordered by a 2024 decision ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K462/550462685.PDF?ref=calregulatory.com)). The first, on depreciation treatment, came through [Advice 7835-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7835-E.pdf?ref=calregulatory.com). The CPUC ordered PG&E to seek the ruling at TURN's urging, on the theory that a favorable tax answer could produce substantial ratepayer savings. TURN lost. The IRS found that PG&E has enough control over how VPF money gets spent (discretion over whether and how to use it, subject only to CPUC approval) that it counts as the utility's income when collected, not a pass-through held for ratepayers. One question the IRS left open: when the tax hits. PG&E currently books VPFs as deferred revenue and recognizes them as costs are incurred. Whether that timing works for tax purposes is unresolved and could be litigated in future proceedings. **INSTANT ANALYSIS:** This ruling forecloses PG&E's most favorable tax path on a program that isn't just plant O&M; the statute contemplates broader public-purpose spending, which is why TURN fought this. A tax gross-up at California's combined corporate rate (**29%**) is real money on a multi-hundred-million dollar program, and every dollar of tax leakage is a dollar not reaching the energy programs ratepayers are funding through VPF collections. --- ### GAS LINE EXTENSION ALLOWANCES In SoCalGas's gas line extension allowances application ([A.25-07-001](https://www.socalgas.com/a25-07-001-gas-line-extension-allowance-application?ref=calregulatory.com)), a [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K328/605328542.PDF?ref=calregulatory.com) reopens the evidentiary record to allow SoCalGas to serve supplemental testimony supporting three statements about EV feasibility for a refuse hauling customer, specifically that: - Electric trucks lack the range for required routes; - High ancillary hydraulic loads for lifting and compacting refuse constrain EV options; and - Battery and fuel-cell EVs remain infeasible for heavy-duty trucking due to upfront costs, limited infrastructure, restricted range, and extended refueling times. SoCalGas may provide its supplement by **May 18**; intervenors may rebut by **June 2**. Cal Advocates and Sierra Club had argued the record lacked adequate support for these claims. SoCalGas countered in rebuttal that a 2022 decision ([D.22-09-026](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K987/496987290.PDF?ref=calregulatory.com)) "does not specifically require the submission of such customer evidence." The new ruling implicitly rejects that reading. **INSTANT ANALYSIS:** The ALJ is siding with intervenors on evidentiary sufficiency over SoCalGas's interpretation of D.22-09-026\. For utilities pursuing gas line extensions where electric alternatives are in dispute, the governing decision is being read to require customer-specific proof even where the utility argues it doesn't. Fleet operators and large-load developers on the customer side should expect their own operational constraints to become part of the evidentiary record. --- ### BACKBONE TRANSMISSION On April 23, PG&E's Cycle 1 backbone transmission capacity [fell 106 MMcf/d below the minimum design standard](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5207-G.pdf?ref=calregulatory.com), the average day in a 1-in-10 cold and dry year, which was set at 2,493 MMcf/d for 2026 under a 2006 decision ([D.06-09-039](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/60237.PDF?ref=calregulatory.com)). Cycle 1 available capacity came in at 2,387 MMcf/d (Redwood 1,740 + Baja-Topock 630 + California Production 17). PG&E restored compliance intraday by lifting Baja-Topock capacity to 800 MMcf/d. The breach traces to three concurrent maintenance events: - Burney Station, Redwood Path (April 23–24); - Topock Station, Baja Path (April 23–24); and - Antioch Station, Redwood Path (April 23–May 12) **INSTANT ANALYSIS:** PG&E got back above the threshold by moving volumes between paths in real time, not because the system had spare capacity sitting around. Baja-Topock went from 630 to 800 MMcf/d (a 170 MMcf/d increase to cover a 106 MMcf/d shortfall), leaving about 64 MMcf/d of cushion on the path carrying the load. Burney and Topock wrapped in a day. Antioch runs until **May 12**. The same Redwood Path impairment will stay in place for three more weeks, and whether PG&E stays above the threshold depends on Baja-Topock continuing to carry the load. This filing exists because a 2022 decision ([D.22-07-002](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M495/K983/495983692.PDF?ref=calregulatory.com)) created the first-day reporting requirement. Pre-2022, a one-day breach wouldn't have surfaced publicly. Watch for another threshold-breach notice before May 12\. One is routine maintenance; a second on the same outage would suggest the system can't cover this window without breaching the floor, and would give intervenors an argument against backbone downsizing. ### WEDNESDAY AGGREGATE: Does the Latest IRP Procurement Order Have a Cost-Causation Problem? URL: https://www.calregulatory.com/wednesday-aggregate-23/ Last updated: 2026-04-22T21:54:41.000Z Today's briefing covers: - A battle over the CPUC's February procurement order; - High DER Future calendar milestones; - LS Power's Collinsville substation project; - Nuclear decommissioning; and - Vehicle-grid integration. --- ### INTEGRATED RESOURCE PLANNING A new fight has emerged in the CPUC's Integrated Resource Planning docket over who should bear the cost of the Commission's February 2026 order requiring 6,000 MW of new reliability procurement for 2029-2032\. A coalition of the Alliance for Retail Energy Markets, the California Coalition of Large Energy Users, the Regents of the University of California, and Shell Energy North America [has asked for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023865.PDF?ref=calregulatory.com) of the CPUC's February procurement order ([*D.26-02-057*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K777/601777006.PDF?ref=calregulatory.com)*; see CRI's coverage of the application for rehearing* [*here*](https://www.calregulatory.com/friday-aggregate-irp-rehearing-tests-a-constrained-procurement-model-as-demand-response-and-pole-access-rules-move/?ref=california-regulatory-intelligence-newsletter) *and the CPUC's procurement order* [*here*](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-results-president-alice-reynolds-final-meeting/)). The applicants argue that the CPUC unlawfully assigned procurement obligations to Electric Service Providers based on current load share while California's Direct Access cap limits ESPs' ability to serve the future load growth driving the need for new capacity. They argue further that this forces Direct Access customers to fund procurement tied to demand they are legally barred from serving, particularly large incremental loads such as data centers and industrial expansion. The applicants ground their challenge in [Public Utilities Code Section 397](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-397/?ref=calregulatory.com), which requires procurement allocation based on each load-serving entity's contribution to the system conditions creating the need, along with cost indifference provisions in other areas of the Public Utilities Code. They also claim that D.26-02-057 lacks sufficient findings and evidentiary support for assigning ESPs obligations based on a static load-share methodology while Direct Access remains capped. As remedies, they propose either reopening Direct Access so ESPs can compete for new load or reallocating procurement obligations away from ESPs. Responses filed April 21 show a clear divide. - [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K328/605328522.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K383/605383747.PDF?ref=calregulatory.com) urge denial of the application, arguing that all customers benefit from grid reliability and all load-serving entities must contribute regardless of retail market caps. - The [Western Power Trading Forum](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K267/605267239.PDF?ref=calregulatory.com) and [3 Phases Renewables](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K320/605320585.PDF?ref=calregulatory.com) back the request for rehearing, with WPTF calling the allocation arbitrary because ESP market share will not remain constant if new utility-served load dominates future growth. - The California Community Choice Association [opposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K267/605267240.PDF?ref=calregulatory.com) rehearing but argues the underlying allocation methodology affects CCAs as well and should be revisited in the IRP procurement track or the Reliable and Clean Power Procurement Program. - Hydrostor [urges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K438/605438801.PDF?ref=calregulatory.com) the CPUC to resolve the AFR by July 31, to avoid compounding procurement uncertainty tied to pending [Effective Load Carrying Capability](https://stanwichenergy.com/insights/understanding-effective-load-carrying-capability-elcc-how-renewable-reliability-impacts-costs-for-energy-users?ref=calregulatory.com) values. **INSTANT ANALYSIS:** The AFR raises a serious question in California procurement policy: when new reliability needs are driven by forecast load growth, who pays if part of the competitive market is capped from serving that growth? The rehearing applicants have a credible fairness argument. If Direct Access stays capped, then assigning ESPs procurement obligations based on today's load share (rather than expected future load) invites cost-causation challenges, especially if large new loads such as data centers and advanced manufacturing land with bundled utilities or CCAs rather than DA providers. The utilities' counterargument is equally straightforward: reliability is a shared system good, existing DA customers rely on the same grid during peak events, and exempting ESPs creates a free-rider problem. **TL;DR:** The state wants competition, load growth, and rapid procurement but still operates with legacy market caps and layered customer classes. CalCCA's response is worth considering: even CCAs, who oppose rehearing, concede the allocation framework needs to be reopened. That suggests the cost-causation problem extends beyond the DA cap. --- ### DISTRIBUTED ENERGY RESOURCES The CPUC [issued a ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K919/604919777.PDF?ref=calregulatory.com) in the High DER Future docket ([R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com)), setting the procedural calendar for the 2026-2027 Distribution Planning and Execution Process cycle. The ruling implements the directives of a 2024 decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)), which ended the old [Distribution Investment Deferral Framework](https://www.epri.com/research/products/000000003002034025?ref=calregulatory.com) solicitation model and refocused the process on transparency, upgrade monitoring, and annual planning reports. The former Distribution Deferral Opportunity Report now operates as the Distribution Upgrade Project Report, paired with the Grid Needs Assessment and Independent Professional Engineer reviews. Key milestones to watch: - **May 18, 2026:** Distribution Forecasting Working Group workshop. The Joint Utilities (PG&E, SCE, and SDG&E) will present their proposed IEPR and Scenario Planning inputs for stakeholder challenge. This is the first contestability event of the new cycle. - **June 12, 2026:** Energy Division will approve (or modify) each utility's Decision Logic Framework for the 2025-2026 cycle. - **October 23, 2026:** Energy Division will approve (or modify) the 2026-2027 Decision Logic Frameworks. This is the methodological anchor for the entire cycle. - **August 16, 2027:** Final 2026-2027 Grid Needs Assessment/Distribution Upgrade Project Report filings are due. The 2025-2026 cycle runs on a standard Distribution Planning Advisory Group rhythm through fall 2026, closing with the joint Independent Professional Engineer Post-DPAG Report in March 2027\. Surrounding the May 18 workshop, the Joint Utilities file scenarios in early May, stakeholders comment in June, and Energy Division issues its approval or modification by end of July. Two methodological points are worth noting. SDG&E does not use a Decision Logic Framework; it provides engineering explanations in lieu of one, a distinction preserved from [Resolution E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K455/592455565.PDF?ref=calregulatory.com). And the Joint Utilities are required to present a proposed hot-spot calculation methodology during the May 2026 Distribution Forecasting Working Group (a 2025-2026 cycle item only). **INSTANT ANALYSIS:** The CPUC is converting distribution planning into a standing operating system with fixed milestones, recurring data drops, public challenge windows, and annual accountability cycles. Distribution circuits are where EV load, electrification, storage siting, and data-center interconnection pressure converge, which makes the process itself consequential. - The May 18 Distribution Forecasting Working Group workshop is where IEPR load-growth, DER-adoption, and localized demand assumptions will be publicly tested before they cement into the 2026-2027 Grid Needs Assessment/Distribution Upgrade Project Report. Stakeholders who wait for the June written-comment window are filing in reaction to an already-staged record. - Decision Logic Frameworks matter more. Energy Division holds explicit approval-or-modification authority over how utilities justify which circuits get upgraded, deferred, or deprioritized. That is a staff-level review of utility planning logic, not just disclosure of it. - For developers, large customers, and non-wires providers, the October 23 Energy Division decision on the 2026-2027 frameworks determines whether planning criteria favor traditional capital or alternatives. - SDG&E's exemption from the Decision Logic Framework requirement breaks methodological uniformity across the three IOUs. Comparability across service territories will degrade unless the Commission closes the gap. In sum, distribution planning is moving toward transmission-style transparency and recurring contestability. Anyone exposed to interconnection queues, local capacity needs, electrification load, or utility capital recovery should track this docket more closely than the caption suggests. --- ### TRANSMISSION **Commissioner Matthew Baker** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M605/K320/605320565.PDF?ref=calregulatory.com) for [LS Power Grid California](https://www.lspowergrid.com/utilities/ls-power-grid-california/?ref=calregulatory.com)'s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M536/K700/536700878.PDF?ref=calregulatory.com) to build the [Collinsville 500/230 kV Substation](https://ia.cpuc.ca.gov/environment/info/panoramaenv/collinsville/index.html?ref=calregulatory.com), a policy-driven upgrade from the CAISO's [2021-2022 Transmission Plan](https://stakeholdercenter.caiso.com/RecurringStakeholderProcesses/2021-2022-Transmission-planning-process?ref=calregulatory.com). The project includes: - A new substation; - Approximately 2.5 miles of 500 kV line looping into PG&E's Vaca Dixon-Tesla corridor; - A six-mile double-circuit 230 kV line to PG&E's Pittsburg Substation with about 4.5 miles of submarine cable beneath the Sacramento-San Joaquin Delta; and - Distribution and communications upgrades. The CAISO projects a **$145 million** present value benefit at 7% over 50 years. LS Power estimates **$324.7 million** in capital costs and agreed to a **$24.5 million** annual revenue requirement cap for the first 40 years, subject to FERC approval. Cost recovery runs through the CAISO's Transmission Access Charge under FERC jurisdiction, not CPUC retail rates. The project's in-service deadline is **June 1, 2028**. The Final Environmental Impact Report, released in March, identified significant and unavoidable impacts across air quality, biological resources, cultural resources, energy, GHGs, land use, noise, and tribal cultural resources. Intervenor testimony is due **May 13**, with rebuttal testimony due **June 5**. Opening briefs are due **July 10**, with replies on **July 24**. **INSTANT ANALYSIS**: Collinsville is where the CAISO's planning narrative rams into permitting reality. The planners made their decision. What remains is whether the state can permit, survive CEQA challenge, and energize on schedule. The key legal question is whether parties can challenge the CAISO's determination that the project is needed. State law tells the CPUC to presume the CAISO got it right. If that presumption holds, the remaining battle is about environmental impacts and cost. If a party successfully rebuts it, the CPUC has to re-litigate whether the project is needed at all, and the schedule gets harder to meet. FERC-jurisdictional Transmission Access Charge recovery means the $24.5 million annual revenue requirement cap gets tested at FERC, not the CPUC. Large loads and transmission customers watching TAC growth have no venue at the CPUC to dispute cost allocation. --- ### NUCLEAR DECOMMISSIONING SCE filed Advice Letter 5804-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)), reporting 2025 San Onofre Nuclear Generating Station Units 2 and 3 decommissioning costs against a forecast provided in AL 5426-E. Recorded 2025 costs came to **$214.1 million** on a 100% share basis in 2025 dollars, against a $323.5 million forecast, producing a **$109.4 million** underrun. On an SCE-share basis, recorded costs were **$162.5 million** versus $245.5 million authorized, and SCE withdrew **$173.8 million** from the decommissioning trusts. SCE attributes the variance to timing rather than scope, noting that some milestones pulled forward into 2025 while others shifted to 2026, with total cost unchanged. SCE reports that 49 of 62 buildings have been demolished and 669 million pounds of waste shipped in 6,935 shipments. On trust adequacy, SCE states that [NRC](https://www.nrc.gov/?ref=calregulatory.com)\-required costs are fully funded by year-end 2025 balances, but Site Restoration "To Go" costs exceed remaining balances. The 2025 recorded costs will be reviewed in a future Nuclear Decommissioning Cost Triennial Proceeding, while the pending 2024 NDCTP covering 2021-2023 costs completed briefing earlier this year. **INSTANT ANALYSIS:** The headline is a $109 million underrun, but none of it represents avoided cost. SCE's own variance explanation confirms that milestones moved in time rather than out of the project, which makes this an on-budget execution with favorable timing, not a cost-discipline triumph. The site restoration funding gap deserves closer attention than SCE's framing suggests. SCE's response is that it does not analyze adequacy by comparing balances to "To Go" costs because future returns above escalation are assumed to cover the shortfall, which is a bet on market performance over a multi-decade tail. The 2022 equity decline opened the gap, and the same mechanism can widen it. --- ### VEHICLE-GRID INTEGRATION SCE filed Advice Letter 5801-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to comply with [Resolution E-5452](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K741/602741239.pdf?ref=calregulatory.com), detailing the budget and incentive methodology for the approved managed-charging component of its ORCHARD vehicle-grid integration program. Resolution E-5452 approved the managed EV charging component and denied the bidirectional (V2X) rebate component (*see CRI's coverage* [*here*](https://www.calregulatory.com/march-19-2026-cpuc-voting-meeting-results-2/)). SCE reallocates the previously proposed **$22,928,224** four-year budget from a previous filing (AL 5536-E) entirely toward orchestrated charging. - Budget figures are estimates. SCE's RFP for Load Management Implementers is still out. Only 2025 and 2026 are submitted for approval; 2027 and 2028 are forecasts revisited in the September filing. The annual budgets are **$3.9 million**/**$5.4 million**/**$6.7 million**/**$6.9 million** against cumulative customer counts of 15,511/25,122/35,580/41,679. - SCE says it cannot fully answer one part of Resolution E-5452's directives because contracts between third-party providers and vehicle or [EVSE](https://www.evconnect.com/blog/what-is-electric-vehicle-supply-equipment/?ref=calregulatory.com) Original Equipment Manufacturers prohibit disclosure of underlying OEM fees and subscriptions. SCE's granular tables are filed under a confidentiality declaration, so the public version shows only totals. - On incentives, SCE will review enrollment quarterly and may restore a prior incentive level if retention at a given tranche falls below **75%**, though SCE states this is not the base case. Customers who opt out of more than **25%** of sessions in a quarter may forfeit the incentive or be removed. SCE will not establish a concurrent control group and will instead use pre-enrollment behavior and other EV pilot data as controls, supplemented by participant surveys. - On dynamic rates, SCE will not perform a bill-impact analysis for dual-enrolled customers. It will work with the Load Management Implementer and Automated Service Providers to log periods where dynamic rate signals and ORCHARD grid signals conflict, with annual review aligned to the Dynamic Rate Pilot Extension true-up. **INSTANT ANALYSIS:** The newsworthy item is not the budget but SCE telling the CPUC it cannot report Original Equipment Manufacturer fees and subscriptions because third-party vendor contracts prohibit disclosure. The CPUC asked for a specific cost breakdown and SCE has identified a contractual wall between itself and that data. The 75% retention floor and 25% opt-out ceiling indicate where SCE thinks the program breaks. SCE has pre-committed to a retention floor that triggers an incentive restoration, making the design an explicit test of how low per-customer cost can go before attrition forces a reversal. On dynamic rates, SCE is not proposing a second control layer that overrides tariff signals but is logging cases where ORCHARD and dynamic rate signals conflict and reviewing them annually. That is a diagnostic rather than an arbitration mechanism, and the question of which signal wins is left unresolved. ### April 30 CPUC Voting Meeting Preview: RNG Retreat, Hydrogen Denial, PG&E Financing Test URL: https://www.calregulatory.com/april-30-cpuc-voting-meeting-preview-rng-retreat-hydrogen-denial-pg-e-financing-test/ Last updated: 2026-04-21T23:11:47.000Z The CPUC's April 30 business meeting could produce decisions impacting utility finances, hydrogen, biomethane mandates, wildfire cost allocation, DER data, and retail bill relief. Below are some items that merit close attention. - A PD approving settlements in SCE's 2024 GRC Phase 2; - A [successor docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com) for the CPUC's [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com); - A PD cutting California's biomethane procurement target in half; and - A PD denying SoCalGas's request to recover **$266 million** tofund Angeles Link Phase 2 work. --- ### SCE 2024 GENERAL RATE CASE PHASE 2 A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998920.PDF?ref=calregulatory.com) approves nine of 10 settlement agreements resolving SCE's 2024 General Rate Case Phase 2 on marginal costs, revenue allocation, and rate design. The PD denies a Vehicle-to-Grid Rate Proposal Settlement Agreement and declines to adopt three contested proposals (deferring PRIME Plus and baseline allowance expansion to future rulemakings, and finding the [Solar Energy Industry Association](https://seia.org/about/?ref=calregulatory.com)'s transmission marginal cost proposal outside the proceeding's scope). The PD adopts a [comprehensive settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998820.PDF?ref=calregulatory.com) on marginal cost methodology and revenue allocation, agreed to by utilities, consumer advocates, and large customer groups. It sets key cost inputs (a **$132.72/kW-year** generation capacity marginal cost, [Avoided Cost Calculator](https://www.cpuc.ca.gov/dercosteffectiveness?ref=calregulatory.com)\-based energy costs, and [Real Economic Carrying Charge](https://www.lawinsider.com/dictionary/real-economic-carrying-charge?ref=calregulatory.com)\-based customer costs) and uses these to allocate SCE's revenue requirement across customer classes. The settlement applies a revenue-neutral allocation framework built on an illustrative **$17.5 billion** consolidated revenue requirement (approximately $17,466 million as of October 2024), with rates ultimately updated to actual authorized revenues at implementation. To limit bill volatility, the PD introduces "collars" that constrain how far class revenues can move from current levels: +**4.0%**/**−6.0%** for delivery revenues around the System Average Percentage Change, and +**0.97%**/**−1.9%** for generation revenues for bundled service customers. - A major element is the treatment of wildfire-related costs, which are allocated using a hybrid formula: **21.5%** tied to distribution cost causation and **78.5%** spread broadly based on system revenues, balancing cost causation with rate stability. The formula will be updated annually and governs until the next GRC Phase 2 proceeding. - The V2G settlement was the only opposed agreement, with Cal Advocates arguing that using the Avoided Cost Calculator to set EV export compensation is premature. The ALJ agrees, finding that the CPUC has not sufficiently evaluated the accuracy of Avoided Cost Calculator-based versus real-time marginal-cost-based credits, customer behavior regarding export rates, or export flexibility under different compensation structures. Existing dynamic pricing pilots should be used until that evaluation is complete, which portends broader implications for the Avoided Cost Calculator's expanding role in ratemaking. - On residential rate design, the approved settlement establishes a four-year glide-path moving Time-of-Use period rate differentials toward 80% of settled marginal cost ratios, with adjustments occurring each **October 1** from 2026 through 2029\. The TOU-D-PRIME seasonal differential increases from 2.4 to **6 cents/kWh**, moving toward 100% of marginal cost levels over the same period. - SCE's PRIME Plus proposal (a demand-based residential rate variant) was not rejected on its merits. The PD defers it to an anticipated industry-wide rulemaking on residential Time-of-Use rate structures, preserving the concept for future consideration. - TURN's baseline allowance proposal raised a substantive issue: residential solar adoption is depressing metered usage and thereby shrinking baseline quantities, disproportionately harming non-Net Energy Metering customers. The ALJ acknowledges the problem but rules that the statutory definition of "residential consumption" under the Public Utilities Code refers to utility-delivered energy, not customer-generated energy. The issue was referred to a future rulemaking affecting all large electric investor-owned utilities. - The Economic Development Rate settlement raises the EDR discount from 12% to **20%**, increases the MW cap from 200 to **300 MW**, expands the small customer demand threshold from 150 kW to **200 kW**, and includes a limited Economic Development Rate program for host sites supporting the 2028 Olympic Games. **INSTANT ANALYSIS:** The PD carries four main implications. - **Cost causation loses to rate stability (by design)**. The collaring mechanism and System Average Percentage Change-heavy wildfire allocators blunt large redistributions. - **Wildfire costs are being socialized**. The 78.5% System Average Percentage Change weighting spreads most wildfire burden broadly across load. This reduces class-specific exposure, especially for distribution-intensive customers. - **The Avoided Cost Calculator's role in ratemaking is now contested ground**. The V2G rejection suggests that the CPUC is not prepared to extend Avoided Cost Calculator-based compensation beyond the Net Billing Tariff without further study. Parties pushing Avoided Cost Calculator-derived values into new rate structures (dynamic rates, export credits, marginal cost proceedings) now face a higher evidentiary bar. - **A playbook for the next GRC cycle**. The settlement governs allocation mechanics until the next Phase 2\. Future battles will shift from methodology to inputs: load forecasts, revenue requirement, and program costs. The baseline allowance and PRIME Plus deferrals ensure those fights will also play out in parallel rulemakings. --- ### RISK-BASED DECISION-MAKING FRAMEWORK A [successor docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com) will continue refining the [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com) that governs how electric and gas utilities propose safety spending in General Rate Cases. The proceeding has four objectives: - Incorporating a formal risk tolerance standard into the framework; - Modifying the [Risk Assessment & Mitigation Phase](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/risk-assessment-and-mitigation-phase?ref=calregulatory.com) schedule to give the CPUC's [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) more review time; - Updating the Benefit-Cost Ratio methodology; and - Assessing whether small gas utilities [Alpine Natural Gas](https://alpinenaturalgas.com/?ref=calregulatory.com) and [West Coast Gas](https://www.westcoastgas.com/?ref=calregulatory.com) should be required to file annual [Risk Spending Accountability Reports](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/risk-spending-accountability-reports?ref=calregulatory.com). The docket's risk tolerance track picks up where [D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com) left off. That decision defined risk tolerance but declined to adopt a formal standard, delegating the work here. The CPUC will seek party proposals on both a formal tolerance standard and a benchmark tied to everyday risks Californians already accept. The RAMP schedule track responds to a documented pattern: the CPUC's Safety Policy Division has received deadline extensions on every RAMP filed since 2020, running about two months each time. The new rulemaking proposes formalizing additional review time, starting with PG&E's 2028 RAMP. The Benefit-Cost Ratio track addresses two gaps: - Inconsistent utility treatment of O&M expenses; and - A Present Value Revenue Requirement field that is currently optional but may be made mandatory. A parallel joint application ([A.26-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101196.PDF?ref=calregulatory.com)) on Benefit-Cost Ratio methodology for the [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) may inform this work. **INSTANT ANALYSIS:** Framework proceedings move slowly and attract less attention than contested rate cases, but their outputs are load-bearing. The risk-tolerance track is where the hardest policy question surfaces: California has spent a decade building tools for quantifying utility risk without ever specifying how much unmitigated risk is acceptable. The RAMP reform track looks administrative but isn't: more formalized SPD review time means more SPD influence over what enters the GRC record. The Benefit-Cost Ratio track is where methodology becomes money: inconsistent O&M treatment means two utilities can propose functionally similar programs and score them differently based on accounting choices. --- ### BIOMETHANE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K926/604926834.PDF?ref=calregulatory.com) cuts California's biomethane procurement target in half and pushes compliance out five years, from 72.8 Bcf annually by 2030 to **36.4 Bcf** annually by 2035\. The **17.6 Bcf** Diverted Organic Waste target is preserved but also extended to 2035, collapsing the prior short-term/medium-term structure into a single deadline. - All feedstocks may bid into utility solicitations immediately, without first satisfying the Diverted Organic Waste milestone. A new Cost Containment Mechanism bars procurement approval if contracts would push the program's running-average above-market cost past **1%** of the Renewable Gas Cost Allocation Pool (RGCAP) revenue requirement, or cause year-over-year increases above 3% of the prior year's combined RGCAP plus above-market cost base. The PD grounds the pullback in [CARB](https://ww2.arb.ca.gov/?ref=calregulatory.com) data showing residential and commercial gas customers generated only 2.6% of statewide methane emissions in 2023. - The 2040 delivery cutoff is eliminated, freeing 15-year contracts signed in the late 2020s and 2030s to run their full term. Co-digestion must now separate component feedstocks for attribution rather than count wholesale as Diverted Organic Waste, reshaping dairy/food-waste project math. - Utilities may purchase brown gas at or below market rate from Renewable Gas Standard-eligible projects stripped of environmental attributes, with developers retaining the [Renewable Thermal Certificates](https://3degreesinc.com/what-we-do/implement-your-strategy/renewable-thermal-certificates-rtcs/?ref=calregulatory.com) (a parallel transaction channel outside the Cost Containment Mechanism). - Open landfills become eligible contingent on a Utility Tier 2 Advice Letter coordinated with [CalRecycle](https://calrecycle.ca.gov/?ref=calregulatory.com). Wastewater treatment plants get a narrow combustion carve-out, filtration-conditioned. The **4%** livestock cap holds. Renewable Thermal Certificate unbundling and interconnection rate-basing are deferred. - All procurement contracts move to Tier 2 Advice Letter review, replacing the $17.70/$26.00 MMBtu price-tiered structure from a 2022 decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)). **INSTANT ANALYSIS:** The original [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com) framework ran ahead of market reality. Supply was thin, pricing was high, and the utilities were procuring into a nascent market with ratepayers bearing the risk. Halving the target and extending the deadline restores economic credibility without formally abandoning the program. The Cost Containment Mechanism is notable. A hard affordability screen tied to running-average and year-over-year bill impact suggests that procurement will survive only if the numbers pencil. Expect suppressed high-priced RNG contracting, reduced speculative bidding, and leverage shifting from developers who assumed mandated demand would guarantee premiums. Opening feedstock eligibility is a pragmatic pivot toward commodity sourcing, but the retained Diverted Organic Waste target plus co-digestion attribution changes keep the [Senate Bill 1383](https://www.wm.com/us/en/sb1383?ref=calregulatory.com) linkage intact. For gas utilities, this PD brings relief. For Renewable Natural Gas developers, policy support now comes with stricter economics and cost containment. For large customers, the PD suggests that the Commission will revisit climate programs when affordability pressure becomes difficult to ignore. --- ### HYDROGEN/ANGELES LINK A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com) denies SoCalGas's request to recover **$266 million** from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the [Angeles Link](https://www.socalgas.com/sustainability/innovation-center/angeles-link?ref=calregulatory.com) hydrogen pipeline project. The project entails dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. The PD finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision ([D.22-12-055](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K167/500167327.PDF?ref=calregulatory.com)) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers. - The record shows significant opposition from consumer advocates, environmental groups, and shippers, who argue that the project's benefits are indirect and uncertain, and that shifting early-stage development costs onto ratepayers would violate core cost-causation principles. Phase 2 cost estimates have nearly tripled since the project was initially proposed, rising from $92 million to $266 million. - SoCalGas declined federal [IIJA](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com) funding through [ARCHES](https://archesh2.org/?ref=calregulatory.com) ( funding the CPUC had specifically directed the utility to pursue in D.22-12-055 to offset ratepayer exposure) arguing that federal compliance costs would not serve ratepayer interests. The PD notes this means no federal offset exists for the proposed costs. - The PD concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise sharply, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. The PD does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational. - The PD declines to resolve jurisdictional questions around whether the project would qualify as a pipeline under Public Utilities Code Section [227](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-227/?ref=calregulatory.com)/[228](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-228/?ref=calregulatory.com) or a gas plant under Section [221](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-221/?ref=calregulatory.com)/[222](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-222/?ref=calregulatory.com), finding such determinations both premature (because the project is not constructed or dedicated to public use) and unnecessary given the denial of cost recovery. The application is denied in full and the proceeding is closed, leaving SoCalGas to pursue the project, if at all, without ratepayer-backed funding for Phase 2. **INSTANT ANALYSIS:** The CPUC is rejecting the idea that speculative, pre-construction hydrogen infrastructure can be funded by legacy gas ratepayers, though it is not permanently foreclosing ratepayer recovery if the project is eventually constructed and demonstrated to be used and useful. For now, the PD is pushing hydrogen out of the mainstream utility cost-recovery model and into a merchant or contract-backed lane. The refusal of federal funding compounds the problem: SoCalGas eliminated the one mechanism the CPUC itself identified to cushion ratepayer impact, then asked ratepayers to absorb the full cost anyway. Developers will need anchor customers, bilateral deals, or external capital. --- ### TRANSMISSION This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K928/604928020.PDF?ref=calregulatory.com) conditionally approves PG&E's request under Public Utilities Code Section 851 to lease interests in future transmission projects to Citizens Energy Corporation. The arrangement would allow Citizens to provide up to **$1 billion** in prepaid capital across five option periods in exchange for 30-year leasehold entitlements in qualifying PG&E high-voltage transmission assets, with Citizens receiving a proportionate share of CAISO Transmission Access Charge revenues. - The PD does not grant blanket approval. PG&E must file a Tier 3 Advice Letter for each option period identifying specific projects and demonstrating that ratepayers are no worse off than under ordinary utility balance-sheet financing. The PD finds the overall structure novel enough to warrant heightened public-interest review, citing undefined future projects and unknown revenue requirements across all five tranches. - Citizens has committed to directing a large share of after-tax profits to customer bill assistance in PG&E territory, estimated at more than **$450 million** over the life of the program. The PD finds the current record insufficient on distribution mechanics. Each advice letter must detail participating nonprofits, eligible communities, demographics served, and alignment with CPUC environmental and social priorities. For Option Periods 2 through 5, PG&E must also account for how funds were actually spent in the prior period. **INSTANT ANALYSIS:** This decision rejects the broad financing pipeline PG&E sought and converts it into a tranche-by-tranche approval regime. The deeper theme is institutional caution around off-balance-sheet utility finance: the CPUC is open to alternative capital sources for transmission buildout but unwilling to delegate future oversight based on a high-level framework. For PG&E, conditional authority is still optionality. If balance-sheet pressure or transmission build demands intensify, it now has a pathway to monetize portions of future transmission assets. For ratepayers and consumer advocates, the ruling preserves repeated intervention points and forces proof that outside capital is at least competitive with traditional utility financing at each exercise. --- ### DISTRIBUTED GENERATION [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K928/604928135.PDF?ref=calregulatory.com) expands funding and governance for the[ California Distributed Generation Statistics (DGStats) platform](https://www.californiadgstats.ca.gov/?ref=calregulatory.com), raising the three-year contract cap from $990,000 to **$2.6 million**, with annual inflation indexing authority delegated to staff. The draft resolution frames DGStats as a nationally recognized repository underpinning [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) forecasting, NEM/NBT cost-shift analysis, and DER program design. PG&E, SCE, and SDG&E must also rebrand the platform under a broader name that can accommodate non-DG programs like Community Solar. Draft Resolution E-5436 orders a sweeping cleanup of interconnection data systems: - Validated equipment drop-downs for generators, inverters, and batteries; - Standardized language and validation rules on system-cost entries; renaming "System Size" fields to "Generator Size" (DC and AC); - Auto-calculation of DC capacity in Standard Test Condition; and - Retroactive rebuilding of historical DC entries where equipment matches the verified list. Energy Division attributes current data problems to manual inputs, inconsistent test conditions, and placeholder cost entries like $0 or $1 submitted to speed through review. The utilities must host a hybrid public stakeholder workshop on decommissioning, covering the prevalence of unreported decommissions, metering-based detection, customer guidance, and Integration Capacity Analysis and forecasting impacts. They must also begin tracking standardized decommission reasons (Replaced, Retired functional/non-functional, Destroyed, Abandoned, Other) in a queryable format. Separately, Energy Division is authorized to publish anonymized [CSLB](https://www.cslb.ca.gov/?ref=calregulatory.com) Disclosure Document data on DGStats. **INSTANT ANALYSIS:** A 2.6× funding increase shows sustained institutional investment in distributed resource intelligence, and the CPUC is treating DER data as planning infrastructure. The most consequential piece of the draft resolution is data normalization. Retroactive DC capacity corrections, stricter cost-entry validation, and standardized equipment inputs could greatly improve the datasets feeding NEM/NBT cost-shift debates, California Energy Commission demand forecasting, and hosting-capacity analysis. Decommissioning (the permanent retirement of an interconnected DG system) deserves attention. Regulators appear concerned that aging and abandoned systems are overstating active DER capacity in Integration Capacity Analysis maps and planning models, meaning some distribution upgrades may be sized against phantom generation. If the workshop confirms the scale, it will reopen questions about hosting capacity claims and DER penetration figures that have shaped recent proceedings. Every forecast, cost-shift model, and hosting-capacity map downstream of DGStats inherits whatever the cleanup produces. --- ### CLIMATE CREDIT A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473601.PDF?ref=calregulatory.com) in [R.25-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com) directs immediate, interim changes to California's residential [Climate Credit ](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com)program to improve bill affordability, primarily by shifting when credits are delivered rather than altering their size or eligibility. Historically, these credits (funded by [Cap-and-Invest](https://ww2.arb.ca.gov/our-work/programs/cap-and-invest-program?ref=calregulatory.com) allowance revenues) were issued in low-usage months (spring and fall), but the CPUC now finds that approach misaligned with affordability needs. - For 2026, large electric utilities (PG&E, SCE, SDG&E) are ordered to move electric bill credits to August and September, when usage and bills are highest. Small and multi-jurisdictional utilities (Bear Valley, Liberty, PacifiCorp) will shift their remaining 2026 credit to November to match winter peaks, then distribute in October and November beginning in 2027. - Natural gas credits will move to February beginning in 2027; the April 2026 gas credit already went out and could not be redirected, given timing constraints. - The PD emphasizes speed and feasibility, adopting only timing changes that utilities can implement immediately, while deferring more complex reforms (e.g., eligibility changes, credit recalculation, baseline territory-level distribution) to Phase 1B. - In parallel, the PD implements statutory requirements under [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com) by directing electric utilities to remit **5%** of Cap-and-Invest allowance auction revenues to the State Treasury for deposit in the [California Transmission Accelerator Revolving Fund](https://autl.assembly.ca.gov/system/files/2026-01/01.15%5Ftx-accelerator-oversight-hearing-background.pdf?ref=calregulatory.com). Remittances are due within 15 days of final receipt of revenues from each auction, covering auctions held between **July 1, 2026** and **July 1, 2031**. - The PD updates Template D-1 within the utilities' Greenhouse Gas Revenue and Reconciliation Application Form, requiring standardized reporting on remittances through existing ERRA compliance, the Energy Cost Adjustment Clause, or advice-letter filings. - The PD also requires limited updates to customer outreach (primarily clarifying bill savings and attributing them to the Cap-and-Invest program) while avoiding expanded messaging that could reduce available credit funds. All changes are explicitly designated as interim, preserving flexibility for broader program redesign in subsequent phases of the rulemaking. **INSTANT ANALYSIS:** If adopted, this PD would shift Climate Credits into peak months, lowering summer and winter bills without increasing total value. It's a timing change, not new relief. The bigger move is upstream: AB 1207 requires 5% of allowance auction revenues to flow to the Transmission Accelerator Fund, reducing the pool available for bill credits. The CPUC is implementing a legislative mandate, not making a discretionary policy choice, but the effect is the same. Climate funds are starting to split between direct ratepayer relief and grid infrastructure buildout. Utilities get a simple, workable change on credit timing. Affordability reforms are deferred. --- ### ERRA COMPLIANCE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K993/604993832.PDF?ref=calregulatory.com) approves, with modifications, SDG&E's 2023 ERRA compliance filing and authorizes recovery of a net **$214.580 million** undercollection. This amount excludes confidential Local Generating Balancing Account and Tree Mortality Non-Bypassable Charge Balancing Account balances. Three negotiated adjustments are adopted. - SDG&E's Resource Adequacy Buffer (initially treated as unsold and valued at zero) is reclassified as Retained RA, with SDG&E's own counterproposal adopted as the Consensus valuation methodology. - The Renewables Portfolio Standard position is corrected by **$3.2 million** in additional Retained RECs. - 2023 revenues from the [Miguel Vanadium Redox Flow](https://www.energy-storage.news/sdge-and-sumitomo-unveil-largest-vanadium-redox-flow-battery-in-the-us/?ref=calregulatory.com) and [Ramona Air Attack Base](https://www.renewableenergyworld.com/power-grid/microgrid/sdge-microgrid-to-help-firefighters-during-power-shutoff-events/?ref=calregulatory.com) battery systems are booked to the Electric Distribution Fixed Cost Account, spreading benefits across all distribution customers rather than bundled customers alone. The substantive fight involves the [Green Tariff Shared Renewables](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-rates/green-tariff-shared-renewables-program?ref=calregulatory.com) program. The [EcoShare](https://www.sdge.com/sites/default/files/2022%5Fecoshare%5Fprice%5Fterms%5Fand%5Fconditions%5Fsummary.pdf?ref=calregulatory.com) sub-program never enrolled a customer; EcoChoice's enrollment collapsed into a death spiral of rising rates and departures. San Diego Community Power and Clean Energy Alliance argued that the Public Utilities Code confines recovery to former participants or shareholders. The PD rejects that reading. SDG&E may recover outstanding Green Tariff Shared Renewables balances through the Public Purpose Programs charge, with a Tier 1 Advice Letter apportioning costs across customer classes based on historical GTSR load, with class-specific per-kWh adders applied. **INSTANT ANALYSIS**: ERRA compliance proceedings keep absorbing allocation fights that exceed their nominal scope. The Green Tariff Shared Renewables mandate is the main precedent here. Once a Commission-designed program collapses and the participant class empties out, statutory indifference protections lose much of their power, and stranded balances migrate to the PPP. Other utilities will study this logic closely: when no participant class remains, cost recovery can shift elsewhere. The PD also demonstrates the CPUC's preference for administrability over hindsight punishment. Compliance with prior CPUC direction still insulates utilities when programs fail on design rather than execution. Intervenors should read this as a warning: attacking execution is insufficient when the framework itself was Commission-built. Cost-allocation elasticity ends up being the main story. Narrow legacy balances become broad surcharges when no clean payer class survives, which is worth tracking as load migration and non-bypassable charge pressure continue to compound. ### MONDAY AGGREGATE: New Friction for Aliso Canyon; New Transmission Questions for PG&E URL: https://www.calregulatory.com/monday-aggregate-new-friction-for-aliso-canyon-new-transmission-questions-for-pg-e/ Last updated: 2026-04-21T03:55:50.000Z Today's briefing covers: - The latest in Aliso Canyon procedural arcana; - A successor docket for the CPUC's Risk-Based Decision-Making Framework; - The proper accounting of PG&E transmission assets; and - Amendments to large-resource Mid-Term Reliability contracts, with RA implications. --- ### ALISO CANYON RULINGS **ALJ Jamie Ormond** issued back-to-back rulings April 16-17 in SoCalGas's [D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com) compliance [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com), expanding the evidentiary record and overriding the utility's resistance to discovery. The April 16 [email ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K937/604937767.PDF?ref=calregulatory.com) (*initially reported by CRI* [*here*](https://www.calregulatory.com/friday-aggregate-2/)) memorializes directions from the prior day's workshop. SoCalGas must produce information on significant outages outside its service territory by **May 1** and inside its territory by **May 15**. Parties may comment on both outage filings by **June 1**. Comments on the [workshop presentation slides](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K989/604989524.PDF?ref=calregulatory.com) are due **April 28**, with replies due **May 5**. The [April 17 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K921/604921162.PDF?ref=calregulatory.com) grants Sierra Club's motion to compel responses to certain data requests, served February 27\. SoCalGas had resisted on relevance grounds, arguing Sierra Club sought to relitigate the past. The ALJ rejects that framing directly, saying: > Parties to a proceeding have broad discovery rights, Applicant should not assume as to know what a Party seeks to do with information sought in a discovery request. And the Commission, rather than SoCalGas, determines both the admissibility of information and evidence and the weight granted to it. SoCalGas must produce complete, unredacted responses within 10 days. The ruling also establishes prospective NDA timelines for future confidentiality claims: five days to provide an executable NDA, 48 hours to return redlines, 10 days to produce after execution. **INSTANT ANALYSIS**: The ALJ is saying that SoCalGas does not control the scope of this proceeding (on outage history, on discovery, or on what counts as relevant). The compel order is notably blunt: the utility cannot prejudge what a party intends to do with requested information. For stakeholders tracking the underlying storage inventory question, the practical consequence is a wider evidentiary record than SoCalGas sought to build. Intervenors now have room to test the utility's reliability narrative against historical outage data and compelled discovery. That shifts the credibility dynamic before any briefing on merits begins. --- ### RISK-BASED DECISION-MAKING The CPUC is expected to launch [a new rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K834/602834588.PDF?ref=calregulatory.com) on [**April 30**](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M605/K306/605306479.pdf?ref=calregulatory.com) to refine the Risk-Based Decision-Making Framework used by electric and gas utilities when proposing safety spending in General Rate Cases. The new proceeding has four objectives: - Incorporate a formal risk tolerance standard into the [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com); - Modify the [Risk Assessment & Mitigation Phase](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/risk-assessment-and-mitigation-phase?ref=calregulatory.com) filing schedule to give the CPUC's [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) more review time; - Update the Benefit-Cost Ratio methodology; and - Assess whether small gas utilities [Alpine Natural Gas](https://alpinenaturalgas.com/?ref=calregulatory.com) and [West Coast Gas](https://www.westcoastgas.com/?ref=calregulatory.com) should be required to file annual [Risk Spending Accountability Reports](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/risk-spending-accountability-reports?ref=calregulatory.com). A risk-tolerance track picks up where a 2025 decision ([D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com)) left off. That decision defined risk tolerance as the maximum acceptable residual risk after mitigation weighed against the cost of further reduction, but declined to adopt a formal standard, delegating that work here. The CPUC will seek party proposals on both a formal tolerance standard and a benchmark tied to common everyday risks Californians already accept. An anticipated RAMP schedule track responds to a documented pattern: Safety Policy Division has received deadline extensions on every RAMP filed since 2020 (the Sempra IOUs in 2021, SCE in 2022, PG&E in 2024, Sempra again in 2025), running about two months each time. The new rulemaking proposes modifying Rate Case Plans to formalize additional review time, starting with PG&E's 2028 RAMP application. The proceeding will also address whether informal party comments on RAMP filings should continue. The Benefit-Cost Ratio methodology track addresses two gaps. - First, utilities have each applied their own approach to O&M expenses in Benefit-Cost Ratio calculations; the new rulemaking proposes standardizing that treatment. - Second, the current RAMP Data Template includes a Present Value Revenue Requirement field as optional; the new proceeding will consider making it mandatory to better reflect life-cycle costs in Benefit-Cost Ratio calculations. A parallel joint application by PG&E, SCE, and SDG&E ([A.26-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101196.PDF?ref=calregulatory.com)) addresses Benefit-Cost Ratio methodology for the [Senate Bill 884](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) undergrounding program specifically; the new rulemaking cites that process as potentially informative. **INSTANT ANALYSIS:** This rulemaking is about the rules that govern how every major safety spending request gets evaluated (in this GRC cycle and the ones that follow). Framework proceedings like this move slowly and attract less attention than contested rate cases, but their outputs are load-bearing. - The risk tolerance track is where the hardest policy question will surface. California has spent a decade building tools for quantifying utility risk but has never specified how much unmitigated risk is acceptable once those tools run. This proceeding is designed to close that gap. - The RAMP reform looks administrative but isn't. Safety Policy Division has taken extensions on every RAMP since 2020\. More formalized review time means more SPD influence over what enters the GRC record. Parties who engage early gain more than parties who wait. - The Benefit-Cost Ratio track is where methodology becomes money. Inconsistent O&M treatment and no required Present Value Revenue Requirement metric mean two utilities can propose functionally similar programs and score them differently based on accounting choices. Some programs that currently look favorable will not survive standardization. --- ### TRANSMISSION PG&E filed [Advice Letter 7894-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7894-E.pdf?ref=calregulatory.com) to confirm that 620 work orders for transmission plant were miscoded to distribution asset classes from 2006 through 2022, and identified and corrected in 2023\. The earliest in-service date was 2006, but the miscoded assets did not enter CPUC rates until the 2011 General Rate Case (base-year mechanics meant the 2003 and 2007 GRCs carried zero balance for these assets). - Total revenue requirement collected through bundled retail rates over 2011–2022 was **$73.5 million**. Of that, PG&E estimates **$7.9 million** would have been recovered from wholesale transmission customers had the assets been correctly classified. (This amount is approximately 10%, using a methodology Cal Advocates proposed in the underlying Transmission Revenue Requirement Reclassification Memorandum Account proceeding.) - The remaining **$65.6 million** would still have flowed through bundled retail transmission rates. PG&E's position: the previously approved **$(42.6) million** refund covering 2023–2026 resolves the current-cycle impact, the assets are excluded from CPUC rates starting **January 1, 2027** via the 2027 GRC, and no further refund is warranted for 2011–2022\. If the Commission orders additional refunds, PG&E recommends the TRRRMA as the vehicle. The FERC-side argument is mechanical. From January 2006 through April 2019, PG&E operated under stated transmission rates with no true-up mechanism. From May 2019 through December 2022, the TO20 Formula Rate applied (but TO20 was superseded by TO21 on January 1, 2024, closing the error-correction window). PG&E argues retroactive charges to wholesale customers would be contested and likely fail. Internal controls, data validation, and capital accounting training have been updated; PG&E concedes misclassifications may still occur against a **$100 billion** \+ plant base. Protests are due **May 7**. **INSTANT ANALYSIS:** The $7.9 million headline understates the interesting number. The real figure is $65.6 million: what bundled retail customers paid over 2011–2022 for assets that should have been allocated through transmission treatment, and what they will not be refunded under PG&E's recommended outcome. PG&E's logic: the FERC mechanism to recover that $65.6 million from wholesale customers has lapsed, so neither party pays it back. Bundled retail customers absorb the full historical differential. That is the precedent worth noting. When jurisdictional misclassification is discovered after the relevant FERC rate vehicle has been superseded, the historical cost-allocation error becomes uncollectable from the side that should have borne it. The clean period (2023 onward) is symmetric: FERC picks up the costs, CPUC-jurisdictional customers get refunded. The legacy period is asymmetric: bundled retail customers overpaid, wholesale customers underpaid, and PG&E's recommendation leaves both sides where they are. The key questions for any protest: whether 2011 is the correct start date, whether the 10% wholesale share is defensible across all four GRC cycles (it ranged from 9.2% to 12.1%), and whether TRRRMA is the right vehicle if additional refunds are ordered. The main takeaway: plant classification sits at the CPUC/FERC seam, and when errors span multiple rate-case vintages, the window to recover from the correct customer class may close before the error is discovered. That is a feature of the regulatory construct, not a PG&E-specific failure. --- ### MID-TERM RELIABILITY PG&E filed [Advice Letter 7895-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7895-E.pdf?ref=calregulatory.com), seeking CPUC approval of amendments to two Mid-Term Reliability RFO Phase 3 Power Purchase Agreements with Atlas Solar XII and XIII (Atlas North 1 and 2). The projects (co-located **375 MW** solar PV + **225 MW** four-hour lithium-ion battery storage each, located in [La Paz County, Arizona](https://en.wikipedia.org/wiki/La%5FPaz%5FCounty,%5FArizona?ref=calregulatory.com)) were originally approved in Resolution E-5370\. For compliance counting, each project delivers 150 MW solar + 225 MW storage toward MTR and [D.26-02-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K777/601777006.PDF?ref=calregulatory.com) obligations. The amendments change the delivery term start from December 1, 2027 to **September 1, 2028**, a nine-month delay; the 15-year term is unchanged. Projected commercial operation remains **June 15, 2028**. The projects are expected to contribute approximately **2,200 GWh** annually to PG&E's GHG-free energy goals and about **0.6 MMt CO2** in emissions reductions. Two facts the advice letter underplays. - First, ownership: the [Merrimack Energy Independent Evaluator](https://merrimackenergy.com/independentevaluatorservices?ref=calregulatory.com) report shows Atlas Solar XII and XIII were Hanwha/174 Power Global subsidiaries at original execution in February 2024, with [Lydian Energy](https://www.lydianenergy.com/?ref=calregulatory.com) now the operating parent. 174 Power Global and Lydian both participated in amendment negotiations. - Second, the market benchmark: Merrimack compared the amended terms against shortlisted solar-plus-storage offers from PG&E's 2025 GHG-Free RFO (offers received July 18, 2025), and recommended approval, finding negotiations "conducted fairly and reasonably." The filing suggests that development fundamentals are in reasonable shape. The main power transformers and high-voltage breakers (the long-lead items that typically drive delays) are already procured, with [Engineering, Procurement, and Construction](https://en.wikipedia.org/wiki/Engineering,%5Fprocurement,%5Fand%5Fconstruction?ref=calregulatory.com) execution targeted for Q2 2026\. The Large Generator Interconnection Agreement under CAISO queue position Q1402 is fully executed with CAISO and DCR Transmission, LLC. The projects qualify for a **30%** Investment Tax Credit plus **10%** Domestic Content and **10%** Energy Community adders, though the seller carries the risk if any of those credits fail to materialize. Cost recovery mirrors the original agreements: net costs flow through the Portfolio Allocation Balancing Account, with above-market costs [PCIA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com)\-eligible under the terms of a 2023 decision ([D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com)). Protests are due **May 7**. **INSTANT ANALYSIS:** The ownership story is of particular interest. 174 Power Global executed the original PPAs in February 2024; Lydian Energy is now the operating parent, and both entities sat at the negotiation table. Schedule delays concurrent with a control transition is a recognizable pattern in solar-plus-storage development. The question isn't whether these specific amendments clear (they will) but whether other Hanwha-originated projects in the California interconnection queue are running the same playbook. On the approval itself, PG&E's unstated argument is straightforward: re-soliciting against 2025 GHG-Free RFO pricing would cost ratepayers more than tolerating a nine-month delay, and a decision last fall ([D.25-09-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K576/581576925.PDF?ref=calregulatory.com)) made the alternative compliance math worse by killing bridge contracts. ### MONDAY NEWS CODEX: Senate Bill 1359; Perovskite-Silicon Manufacturing in CA; the Trolley Problem URL: https://www.calregulatory.com/monday-news-codex-senate-bill-1359-perovskite-silicon-manufacturing-in-ca-the-trolley-problem/ Last updated: 2026-04-21T15:02:12.000Z - **Are Long-Promised Solar Perovskites Finally Hitting Mass Production?** "Perovskites hold a place of honor in the pantheon of much-heralded clean energy breakthroughs that have yet to actually arrive, alongside small modular nuclear reactors and solid-state batteries. In theory, these [crystal structures](https://www.energy.gov/cmei/systems/perovskite-solar-cells?ref=calregulatory.com) could radically improve solar panels’ capabilities by absorbing wavelengths of light that conventional silicon cells can’t catch. But the stunning advances in R&D specimens have yet to infiltrate the cold, hard world of commercial solar manufacturing." [**CANARY MEDIA**](https://www.canarymedia.com/articles/solar/perovskites-mass-production-tandem-fremont?ref=calregulatory.com) - **Tandem PV Launches Commercial Perovskite-Silicon Manufacturing in California:** "Tandem PV has opened a 40 MW commercial demonstration factory in Fremont, California, marking a significant transition for perovskite-silicon technology from laboratory development to repeatable manufacturing at scale." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/20/tandem-pv-launches-commercial-perovskite-silicon-manufacturing-in-california/?ref=calregulatory.com) - **California's Gas System is Crumbling – SB 1359 Charts a Path to a Clean Energy Future:** "A new bill introduced by Sen. **Henry Stern**, [**SB 1359 (2026)**](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202520260SB1359&ref=calregulatory.com), titled the 'Gas Transition Responsibility and Electrification Act,' would establish a comprehensive framework to manage the transition away from natural gas and toward electrification in a way that protects ratepayers, reduces emissions, and ensures an orderly and equitable phase-down of gas infrastructure. Specifically, SB 1359 would direct the California Public Utilities Commission to align gas system planning, ratemaking, and infrastructure investment decisions with California’s climate goals, while prioritizing electrification and minimizing stranded asset risk (i.e., the financial risk of future ratepayers having to pay for gas pipelines that become obsolete)." [**LEGAL PLANET**](https://legal-planet.org/2026/04/17/californias-gas-system-is-crumbling-sb-1359-charts-a-path-to-a-clean-energy-future/?ref=calregulatory.com) - **California's Proposed SAF Tax Credit Really Will Raise Gas and Diesel Prices While Delivering Small Carbon Reductions:** "The company best placed to immediately benefit from the proposed tax credit is Phillips 66, a Texas oil company that [converted its oil refinery in Rodeo California](https://agdatanews.substack.com/p/build-it-and-hope-they-mandate-it?utm%5Fsource=publication-search) to make renewable diesel and SAF mostly from waste oils and fats." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/04/20/californias-proposed-saf-tax-credit-really-will-raise-gas-and-diesel-prices-while-delivering-small-carbon-reductions/?ref=calregulatory.com) - **California Advances Carbon Neutrality Goals with the Largest Renewable Energy Project to Date for the DWR:** "The new Pastoria Solar Project, Power Bank, and Energy Facility will provide 105 megawatts of clean energy to help move water across the state."[ **ABC 23 BAKERSFIELD**](https://www.turnto23.com/news/in-your-neighborhood/frazier-park-grapevine/california-advances-carbon-neutrality-goals-with-the-largest-renewable-energy-project-to-date-for-the-dwr?ref=calregulatory.com) - **California Powers its Massive Water Pumps with 105 MW Kern County Solar Project:** "The California Department of Water Resources and developer Calpine have brought the 105 MW Pastoria Solar Project online in Arvin, marking the largest renewable energy procurement in the history of the State Water Project. Situated in Kern County near the foot of the Tehachapi Mountains, the facility utilizes approximately 226,000 solar panels equipped with tracking technology to follow the sun’s path." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/20/california-powers-its-massive-water-pumps-with-105-mw-kern-county-solar-project/?ref=calregulatory.com) - **FERC Tees Up June Decision on Data Center Interconnection Reform:** "In [an April 13 filing at FERC](https://elibrary.ferc.gov/eLibrary/filelist?accession%5Fnumber=20260413-5278&optimized=false&ref=calregulatory.com), the National Association of Regulatory Commissioners highlighted recent efforts by states to develop data center interconnection rules. 'The abundance of recent state undertakings demonstrate that state commissions are in the best position to ensure rational and efficient interconnections of new large loads while protecting all customers … from improper cost-shifts or unfair interconnection processes,' the organization said." [**UTILITY DIVE**](https://www.utilitydive.com/news/ferc-doe-data-center-interconnection-pjm-backstop-auction/817804/?ref=calregulatory.com) - **Natural Gas Dominates in the Annual Energy Outlook 2026:** "Natural gas demand not only increases due to increases in the generating sector but also because of expanding liquefied natural gas exports. U.S. dry gas production increases up to 40% through 2050 from 2025 levels among the cases. The EIA projects LNG exports will rise from about 15 billion cubic feet per day in 2025 to [more than 30 billion cubic feet per day by 2050](https://www.eia.gov/todayinenergy/detail.php?id=67425&ref=calregulatory.com)." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/fossil-fuels/natural-gas-dominates-in-the-annual-energy-outlook-2026/?ref=calregulatory.com) - **Renewable + Storage Grid:** "Currently available short-duration storage systems such as the Tesla Megapack would probably be acceptable for peak shaving applications early in the transition. However, as transition progresses, medium-duration and long-duration storage solutions would be required to effectively compensate for multi-day interruptions and seasonal variations in renewable generation performance. Pumped hydro storage would likely be a suitable medium-duration storage approach, though proposed pumped hydro systems have met with public resistance. Green Hydrogen production and storage has been suggested as a long-duration storage option, but its capital and operating costs are currently excessive." [**CLIMATE CHANGE CONUNDRUM**](https://edreid.substack.com/p/renewable-storage-grid) - **The Hidden Obstacles Facing Renewable Energy:** "The dynamics that defined the expansion of U.S. wind and solar power over the past two decades have been completely upended by more recent technological developments. A steady migration toward air conditioning-reliant states like Arizona, Florida, and Texas, together with the growing adoption of electric heat pumps and vehicles, is helping drive electricity consumption up for the first time in a generation. But the big story, of course, is AI data centers, whose power consumption could triple (or more) within a decade. So it’s telling that, while wind and especially solar continue to grow steadily in the United States, data centers are relying [overwhelmingly](https://cleanview.co/content/power-strategies-report?ref=calregulatory.com) on natural gas to meet their immediate power needs—at least for now." [**THE ECOMODERNIST**](https://www.breakthroughjournal.org/p/the-hidden-obstacles-facing-renewable?ref=calregulatory.com) - **Trolleys, Fires, and Oxygen Machines:** "Turning off the power comes at a cost. In 2019, the high winds and dry air that fueled the fires of 2018 [returned](https://www.caloes.ca.gov/wp-content/uploads/Preparedness/Documents/PA%5FCase%5FStudy%5F7%5FPower%5FOutage.pdf?ref=calregulatory.com). Like the whiplash that comes after a car crash, California utilities shut off power to 3 million people between October and November. Communication was patchy at best, and people died as a result. Customers reliant on oxygen or dialysis machines in their homes were [left](https://www.theguardian.com/us-news/2019/oct/11/california-pge-utility-power-shutoff-disabled?ref=calregulatory.com) to 'fend for \[themselves\].' One man in northern California died just 12 minutes after an outage, [unable](https://www.foxnews.com/us/oxygen-dependent-man-dies-12-minutes-after-pge-cuts-power-to-his-home?ref=calregulatory.com) to reach his battery-powered backup oxygen machine." [**THE INTERTIE**](https://jonathanpbell.substack.com/p/trolleys-fires-and-oxygen-machines) - **Why Californians Are Leaving:** "Under \[**Gavin**\] **Newsom**, the once massive California oil industry has been [effectively stifled](https://laist.com/news/climate-environment/californias-fossil-fuel-phaseout-has-left-it-vulnerable-to-the-iran-oil-shock?ref=calregulatory.com), leaving California dependent on Middle Eastern crude, and [particularly vulnerable](https://www.wsj.com/opinion/gavin-newsom-is-driving-up-gasoline-prices-49af8467?ref=calregulatory.com) to the Hormuz crisis." [**NEW YORK POST**](https://nypost.com/2026/04/05/opinion/gavin-newsoms-a-failed-governor/?ref=calregulatory.com) ### FRIDAY AGGREGATE: Aliso Canyon Goes Procedural; CPUC May Keep PG&E Wildfire Costs on Track URL: https://www.calregulatory.com/friday-aggregate-2/ Last updated: 2026-04-20T19:59:55.000Z Today's briefing covers: - The continuing Aliso Canyon saga; - PG&E's Wildfire & Gas Safety application; - SoCalGas's upcoming customer forum; - Backbone gas transmission adequacy; - Nuclear decommissioning; and - Utility safety reportage. ### ALISO CANYON INVENTORY LEVELS On April 15, [we reported on the Aliso Canyon workshop](https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/) that convened that day. Since then, SoCalGas has filed [workshop presentations](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K989/604989524.PDF?ref=calregulatory.com) on behalf of itself and the CPUC's Energy Division. **At issue:** Energy Division's [2025 Biennial Assessment recommends](https://www.calregulatory.com/r/52e70c9c?m=bb484012-a69a-425c-839a-750c0bd64e46) cutting Aliso Canyon's authorized inventory by 10 Bcf to **58.6 Bcf**. SoCalGas is contesting the pipeline deliverability inputs, Receipt Point Utilization, and storage withdrawal curves that produced that number. The relevant proceeding is [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com). [April 15 Aliso Canyon Biennial Assessment Workshop SummaryThe first Aliso Canyon Biennial Assessment Workshop exposed a conflict over whether reliability depends on storage or on optimistic assumptions.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/iterograph_Tue-Mar-31-2026--16-.png)](https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/) SoCalGas disputes Energy Division's analytical foundation, which evaluates natural gas storage needs through four analyses: - Demand reduction; - Gas balance reliability; - Hydraulic modeling; and - Economics. SoCalGas argues that Staff's Biennial Assessment systematically overstates available pipeline supply by assuming Receipt Point Utilization levels that do not reflect real storm conditions. Historical events support that argument: Winter Storm Fern in January 2026 reduced Receipt Point Utilization to 25%, the 2024 Arctic Blast to 38%, and the 2021 event to 47%. **NEXT STEPS:** Parties may submit comments on workshop presentation slides by **April 28**, with reply comments due **May 5**. Parties may also propose modifications or additional analysis to inform the next biennial assessment cycle. An April 16 email ruling from **ALJ Ormond** directs SoCalGas to compile historical outage information. Outages outside its service territory over the past decade are due by **May 1**, while outages within its territory over the same period are due by **May 15**, with the option to include older events. Parties may comment on these outage reports by **June 1**. Additional CRI coverage of Aliso Canyon inventory levels is available at the following links. [IRP Cycle 2024-2026 Changes; Woolsey Fire Financing OrderCovers: IRP; Woolsey Fire; Aliso Canyon; 2026 ERRA Forecasts of PG&E and SCE![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://images.unsplash.com/photo-1688040637388-d2c0aa7b9907?crop=entropy&cs=tinysrgb&fit=max&fm=jpg&ixid=M3wxMTc3M3wwfDF8c2VhcmNofDc0fHxlbGVjdHJpY2l0eSUyMGdlbmVyYXRpb258ZW58MHx8fHwxNzY4NjE2NTQ5fDA&ixlib=rb-4.1.0&q=80&w=2000)](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/?ref=california-regulatory-intelligence-newsletter) [Aliso Canyon Clash; Criticism of IRP ContinuesAliso Canyon Clash; PCIA/ERRA Reform (Track 3); Criticism of IRP Continues![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Feb-18-2026--2--1.png)](https://www.calregulatory.com/monday-aggregate-aliso-canyon-clash-pcia-erra-reform-track-3-criticism-of-irp-continues/) [Scoping Memo Opens Fight Over PG&E Gas Cost ReallocationFor the first time, PG&E is combining its GCAP and GT&S cost-allocation and rate-design proposals into a single application.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/ExponentAsset-752daf9a8cab45e2700cd23aa224703d.JPG)](https://www.calregulatory.com/monday-aggregate-cpuc-scoping-memo-opens-fight-over-pg-e-gas-cost-reallocation/?ref=california-regulatory-intelligence-newsletter) --- ### ALISO CANYON – ADDITIONAL ISSUES (DISCOVERY & PROCEDURE) SoCalGas filed [a response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K919/604919741.PDF?ref=calregulatory.com) on April 16 urging the CPUC to deny a Sierra Club motion to compel additional discovery in [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com). SoCalGas argues the disputed requests (bulk production of discovery records from two prior dockets and a historical accounting of gas-price mitigation measures) are irrelevant to a proceeding whose sole purpose is evaluating future Aliso Canyon inventory levels. The strongest argument in the filing is procedural: no scoping memo has been issued. The CPUC has not formally defined the issues for this proceeding. Sierra Club is demanding wholesale discovery against a target that doesn't yet exist, and SoCalGas says that alone forecloses any showing of relevance. **INSTANT ANALYSIS:** The no-scoping-memo argument is a threshold kill shot: if the ALJ agrees with SoCalGas, Sierra Club's motion fails before the merits are reached. No defined issues means no cognizable relevance standard means no compelled production. SoCalGas's good-faith compromise offers during meet-and-confer (targeted production on discrete issues, rejected same day) reinforce this stance. Watch for the ALJ's ruling on this dispute: it will show how much latitude intervenors have to import prior-proceeding record into forward-looking gas infrastructure cases before the proceeding is even scoped. --- ### WILDFIRE MITIGATION & GAS SAFETY The CPUC issued [an amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K937/604937718.PDF?ref=calregulatory.com) in PG&E's Wildfire Mitigation and Gas Safety cost-recovery proceeding ([A.23-06-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M511/K547/511547762.PDF?ref=calregulatory.com)). The ruling reopens the record to admit new evidence on 2023–2030 revenue requirements and removes specific dollar amounts from the scoped issues. The point of doing this is to allow broader consideration of how approved costs translate into rates. The underlying problem is procedural: costs that are already under review lack a recovery forum for later years because General Rate Case cycles didn't align with this case's timeline. The ruling directs parties to meet and confer on whether additional testimony or hearings are needed, with a joint status report due **May 13**. **INSTANT ANALYSIS:** Once costs clear prudency review here, the downstream revenue requirement follows. The CPUC will adjust the procedural vehicle rather than let recovery strand. For PG&E, billions in wildfire and safety spending stays on a viable recovery path into the next decade. For intervenors, litigation risk re-enters late, now focused on how costs translate into rates, not just whether they were prudently incurred. --- ### SOCALGAS ANNUAL CUSTOMER FORUM SoCalGas will hold its annual Utility Customer Forum on **May 15**, as a virtual webinar, with RSVPs due by **May 14**. The forum will review: - How Operational Flow Order events are triggered; - How the Operational Hub acquires and deploys gas supplies to maintain minimum flow requirements; and - Whether additional flow requirements, tools, or infrastructure improvements are needed to support system reliability. Ahead of the meeting, SoCalGas will publish an annual report by **May 1** summarizing reliability issues, minimum flow needs, and operational activity, including transaction-level detail. --- ### BACKBONE GAS TRANSMISSION On April 15, PG&E and SoCalGas submitted compliance filings demonstrating their backbone gas transmission adequacy. A key regulatory shift: utilities now report actual operating capacity against the 1-in-10 cold-and-dry year design standard, not nominal capacity. - PG&E's combined backbone capacity remained sufficient through March 31, 2026 and is projected to meet demand through 2035\. One documented exception: gas day 03/04/2026, when simultaneous maintenance at Delevan Station and Topock Compressor Station produced a **121 MMcfd** deficit against the 2,554 MMcfd threshold, the only below-standard day in the period. - SoCalGas exceeded minimum design standards on every day of its nine-month compliance window and projects reserve margins ranging from **64%** in 2026 to **83%** in 2035\. *PG&E* [*Advice Letter 5201-G*](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5201-G.pdf?ref=calregulatory.com)*; SoCalGas AL 6629-G (available* [*here*](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)*).* **INSTANT ANALYSIS**: These filings confirm surplus conditions on the intrastate gas system at the moment policy momentum is pointed the other direction. Both utilities are telling the CPUC the same thing: backbone capacity is not constrained, reliability standards are being met with margin, no near-term infrastructure shortfall is emerging. That undermines any immediate reliability-based case for new gas investment while reaffirming that existing assets can carry the system through the transition window. The shift to actual operating capacity reporting gives the CPUC a firmer evidentiary grip on real system performance: a cleaner baseline for future policy moves, whether that means ratcheting down capacity requirements, or litigating cost allocation as load declines. One number worth watching: PG&E's Table 3 shows utilization dropping from 87% in 2026 to **57%** by 2035, with off-system contracts going to zero after 2030\. The 80-90% utilization guideline was written for a different system. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/3-2.png) --- ### NUCLEAR DECOMMISSIONING PG&E filed two parallel advice letters on April 16 requesting CPUC authorization to draw from nuclear decommissioning trusts for 2026 ([AL 7889-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7889-E.pdf?ref=calregulatory.com) and [AL 7893-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7893-E.pdf?ref=calregulatory.com)). The filings share a regulatory framework but reflect opposite situations. - **Diablo Canyon**: PG&E requests **$3.4 million** against a $4.3 million 2026 plan. The 2021 cost estimate projected $519 million for 2026 activities. The gap is Senate Bill 846, the 2022 legislation extending operations to 2030 suspended the active decommissioning program, leaving only permitting, transition planning, and spent fuel preparation. The $5 billion trust is intact. The decommissioning project is not. - **Humboldt Bay Unit 3**: PG&E requests **$12.1 million** against a $13.4 million 2026 plan, entirely for spent fuel management (Independent Spent Fuel Storage Operations, security staffing, and Nuclear Regulatory Commission fees). The decommissioning itself is done; the [Part 50 license](https://www.nrc.gov/reading-rm/doc-collections/cfr/part050/full-text?ref=calregulatory.com) was terminated in November 2021\. What remains is a spent fuel custody problem running to 2033, pending DOE pickup currently forecast for 2031–2032. **INSTANT ANALYSIS:** These filings share a common endpoint: long-term on-site fuel storage awaiting federal removal. Humboldt Bay is the cleaner case. Decommissioning is complete, the license terminated in 2021, but the site remains active because DOE pickup isn't forecast until 2031–2032\. The Independent Spent Fuel Storage Operations run to 2033\. Diablo Canyon extends the timeline but not the destination. [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com) bought the state a few more years of generation and deferred the decommissioning program by a decade. The back-end obligation remains. Ratepayer-backed trusts are funding an indefinite holding pattern on federally stranded material. --- ### UTILITY SAFETY CULTURE SoCalGas's [Q1 2026 Safety Culture Improvement Plan report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K921/604921129.PDF?ref=calregulatory.com) updates the CPUC on progress under [I.19-06-014](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M306/K870/306870841.PDF?ref=calregulatory.com), an investigation into whether SoCalGas and its parent Sempra had organizational cultures and governance structures that genuinely prioritized safety. The impetus was the [2015 Aliso Canyon gas storage blowout](https://www.cpuc.ca.gov/regulatory-services/safety/gas-safety-and-reliability-branch/aliso-canyon-well-failure?ref=calregulatory.com). SoCalGas's report documents implementation under a "Plan-Do-Check-Act" framework, with the stated goal of shifting safety culture from compliance-oriented incident avoidance toward a learning-driven model embedded in leadership behavior and daily operations. **INSTANT ANALYSIS:** SoCalGas is building a compliance-grade safety culture. Whether it holds depends on field-level behavior change, not internal coherence. ### NEWS CODEX: The SB 254 Report/Warning; Ava Community Energy Solar + Battery Incentive Program URL: https://www.calregulatory.com/news-codex-2/ Last updated: 2026-04-16T22:25:32.000Z - **As Some Oil Deliveries to US Stop Flowing, California Braces for an Energy Crisis:** "'Jet-fuel prices are bonkers,' said **Tom O’Connor**, an ICF energy consultant who advises California’s Energy Commission after 30 years with ExxonMobil." [**KQED**](https://www.kqed.org/news/12080093/as-some-oil-deliveries-to-us-stop-flowing-california-braces-for-an-energy-crisis?ref=calregulatory.com) - **A State Agency's Blunt Warning on Wildfire Spending:** "As the California Public Utilities Commission said in [its own SB 254 response](https://www.counties.org/wp-content/uploads/2026/02/CPUC-SB-254-Study-Information-and-Recommendations-1.30.2026.pdf?ref=cleanpowercalifornia.org) in January, the current system 'treats utilities as if they are solely responsible for damages from catastrophic wildfires and can fully mitigate the risks of those damages through reasonable diligence.' They can’t, and their ratepayers can’t afford to keep paying to try." [**THE CURRENT**](https://www.cleanpowercalifornia.org/a-state-agencys-blunt-warning-on-wildfire-spending/?ref=calregulatory.com) - **California Regulator Rejects Community Solar Pricing Model, Triggering Industry Backlash:** "The NVBT proposal would have tied compensation for exported solar electricity to the hourly value of energy delivered to the grid. However, the CPUC opted instead for the ACC methodology, which estimates the utility’s avoided cost of procuring equivalent power from other sources." [**PV TECH**](https://www.pv-tech.org/california-regulator-rejects-community-solar-pricing-model-triggering-industry-backlash/?ref=calregulatory.com) - **California School District Completes 3.5 MW Solar and Energy Modernization Project:** "The Yucaipa-Calimesa Joint Unified School District has announced the completion of a district-wide energy transformation, marking a significant milestone for distributed generation in California’s Inland Empire. In partnership with OpTerra Energy Services, the $33 million initiative combined on-site solar PV with deep energy efficiency retrofits to hedge against rising utility rates and provide a living laboratory for its 8,600 students." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/14/california-school-district-completes-3-5-mw-solar-and-energy-modernization-project/?ref=calregulatory.com) - **Can California Thrive on Renewable Electricity?** "According to the [California Energy Commission](https://www.energy.ca.gov/data-reports/energy-almanac/california-electricity-data/2023-total-system-electric-generation?ref=calregulatory.com), in 2023, Californians generated 215,000 GWh per year and imported another 66,000 GWh. That represented only 14 percent of the 1.9 million GWh of primary energy (7 EJ = 1.9 million GWh) inputs to the state. On the other end, the net energy services consumed by Californians in 2023, if expressed in terms of electricity, were equal to 693,000 GWh (the energy equivalent of 2.5 EJs). So what if California went fully electric and was able to double the current 36 percent efficiency, and could convert 72 percent of its primary energy input into net energy services?" [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/can-california-thrive-on-renewable-electricity/?ref=calregulatory.com) - **Community-Scale Solar Offers $6.5 Billion in Savings, Bypassing California Gridlocks:** "For CCAs in California, community solar offers an alternative to waiting for a massive grid overhaul that may take a decade. By investing in localized, community-scale solar and storage now to save billions, cut emissions, and bypass the interconnection queue."[**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/14/community-scale-solar-offers-6-5-billion-in-savings-bypassing-california-gridlocks/?ref=calregulatory.com) - **Distributed Batteries Get Legislative, Utility Lift in California:** "Ava Community Energy [launched an $11.25 million incentive program](https://www.prnewswire.com/news-releases/in-northern-california-ava-community-energy-debuts-smarthome-battery-a-residential-solar--storage-program-for-community-powered-energy-302737477.html?ref=calregulatory.com) last week for residential customers installing solar and battery storage in their homes. The Oakland, California-based community choice aggregator’s [SmartHome Battery program](https://avaenergy.org/go-electric/residential-solar-storage/smarthome-battery/residents/?ref=calregulatory.com) allows customers to share up to 80% of their home batteries, Ava said Thursday. Ava said it will provide rebates of $500/kWh for income-qualified customers and $90/kWh for customers who don’t meet income qualifications on the portion of the battery they choose to share." [**UTILITY DIVE**](https://www.utilitydive.com/news/distributed-batteries-get-legislative-utility-lift-in-california/817466/?ref=calregulatory.com) - **Google to Advance CDR Science with New Wetland Restoration Project in California:** "...Google announced that it is launching a new project in California that will serve to restore wetlands and advance the science on carbon dioxide removal...the project is located in California’s Bay Area, right next to Google’s Mountain View campus." [**CARBON HERALD**](https://carbonherald.com/google-to-advance-cdr-science-with-new-wetland-restoration-project-in-california/?ref=calregulatory.com) - **Largest US Renewable Project Begins Generating Electricity:** "The largest renewable energy project ever built in the United States has begun generating electricity, putting a two-decade push to deliver wind power generated in New Mexico to consumers in California on the cusp of completion. SunZia Wind has begun testing its 916 turbines as it nears the start of commercial operations later this quarter, according to a person familiar with the project. The impact is already evident: California broke its record for wind generation eight times in the last four weeks, according to Grid Status, a website that tracks power flows." [**E&E NEWS**](https://www.eenews.net/articles/largest-us-renewable-project-begins-generating-electricity/?ref=calregulatory.com) - **States Are Lifting Bans on Nuclear Power:** "Five states — Wisconsin, Kentucky, Montana, West Virginia, and, most recently, Illinois — have fully lifted their moratoria since 2016\. Others are loosening the reins, with Connecticut easing restrictions on small modular reactors and Rhode Island allowing utilities to [buy electricity](https://legiscan.com/RI/text/H5575/2025?ref=calregulatory.com) from neighboring states’ nuclear plants. Five more — [California](https://heatmap.news/am/us-renewables-batteries?ref=calregulatory.com), [Massachusetts](https://www.ctpublic.org/2026-03-06/repeal-of-1982-nuclear-law-gaining-traction-on-beacon-hill-cape-cod-activists-object?ref=calregulatory.com), [Minnesota](https://minnesotareformer.com/2026/03/19/with-2040-carbon-free-deadline-looming-bipartisan-legislators-look-to-overturn-nuke-moratorium/?ref=calregulatory.com), [New Jersey](https://www.njsendems.org/m/newsflash/home/detail/1310?ref=calregulatory.com), and [Vermont](https://legislature.vermont.gov/Documents/2026/Docs/BILLS/H-0601/H-0601%20As%20Introduced.pdf?ref=calregulatory.com) — are now weighing legislation to overturn their bans. Oregon, meanwhile, is [considering](https://www.ans.org/news/2026-02-25/article-7795/oregon-bill-would-create-new-feasibility-study/?ref=calregulatory.com) a bill that would require a feasibility study to look into nuclear power. (In Hawaii, the results of such a [study](https://files.hawaii.gov/dbedt/annuals/2025/2025-hseo-scr136.pdf?ref=calregulatory.com) concluded in December that the state should maintain its moratorium on atomic energy.)" [**CANARY MEDIA**](https://www.canarymedia.com/articles/nuclear/states-are-lifting-bans-nuclear-power?ref=calregulatory.com) - **WECC Says Glen Canyon Could Reach Dead Pool Before Summer's End, Warns of Widespread Heat Across the West:** "Western entities plan to add 177 GW of new generation resources by 2035 and retire 22 GW. Among the planned additions, 70 GW is in the Desert Southwest, 49 GW is in California, and about 15 GW each are planned for the Basin, Northwest and Rocky Mountain subregions. Across the West, 90 percent of the planned new resources are inverter-based wind, solar or battery storage." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regional%5Froundup/wecc-says-glen-canyon-could-reach-dead-pool-before-summer-s-end-warns-of-widespread/article%5F1eb2f3a1-2cff-4ef0-9c2e-471d1e19d181.html?ref=calregulatory.com) - **Why Producing More Oil in California Helps the Environment:** "It may take several decades before Californians no longer depend on petroleum fuel, but if we source it here instead of importing, it will generate hundreds of thousands of jobs and hundreds of billions of dollars. Moreover, the biggest oil-related source of methane and volatile organic compounds polluting the atmosphere, by far, is [leakage from natural seeps](https://abundanceca.com/115-oil-extraction-reduces-methane-seepage/?ref=calregulatory.com) continually opened up via seismic activity. The only way to reduce, if not eliminate, this leakage of methane and VOCs is not by capping or recapping wells and eliminating production, but instead to safely *increase* drilling in order to deplete the underground reservoirs." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-why-producing-more-oil-in-california-helps-the-environment/?ref=calregulatory.com) ### Aliso Canyon Workshop: Energy Division Pushes Inventory Cut as SoCalGas Warns of Supply Shortfalls URL: https://www.calregulatory.com/aliso-canyon-workshop-energy-division-pushes-inventory-cut-as-socalgas-warns-of-supply-shortfalls/ Last updated: 2026-04-15T22:22:37.000Z The CPUC’s first Aliso Canyon Biennial Assessment Workshop exposed a direct conflict over whether Southern California gas reliability depends on storage or on optimistic assumptions about pipeline performance. Energy Division recommends reducing Aliso Canyon's maximum inventory by 10 Bcf (from 68.6 to **58.6 Bcf**), the maximum step permitted under a 2024 decision ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)). SoCalGas argues the current 68.6 Bcf maximum should be raised, not reduced. **ALJ Jamie Ormond** was present, steering the record toward safety concerns. ### Energy Division's Assessment Energy Division's presentation was led by **Khaled Abdelaziz** (natural gas modeling lead) with **Eileen Hlavka** covering the economic analysis and **Jean Spencer** making clarifying interventions during the Q&A session. The Energy Division assessment comprises four analyses required by D.24-12-076. - **Analysis 1 (Demand Reduction)**: This is a binary test comparing 1-in-10 peak day demand forecasts against a 4,121 MMcfd closure threshold established by a contractor several years ago. Forecasted peak demand exceeds the threshold in both study periods (by **441 MMcfd** for winter 2025-26 and **76 MMcfd** for winter 2030-31), which means that Aliso Canyon cannot be closed entirely. This analysis does not determine a minimum inventory level. - **Analysis 2 (Gas Balance Reliability):** This analysis uses an in-house stochastic daily mass balance model. At pipeline supply capacity of 3,200 MMcfd (reflecting resolution of the L4000/L4002 Northern Zone outage), only about **1%** of Aliso Canyon's inventory is needed (but some inventory is still required). Abdelaziz stressed this is "a necessary but not sufficient test" because it doesn't conserve energy or account for cost-mitigation withdrawals. - **Analysis 3 (Hydraulic Modeling)**: This analysisuses [Synergi Gas](https://www.dnv.com/software/services/pipeline/synergi-gas/?ref=calregulatory.com) 4.9.5 by DNV to simulate the full pipeline network hour by hour. For winter 2025-26, the simulation succeeded but required **550 MMcfd** of continuous withdrawal from Aliso Canyon; without it, linepack collapses and curtailments become imminent. For winter 2030-31, Aliso Canyon is not needed, but only if three major system upgrades are completed, no unplanned outages occur, and demand reductions materialize as forecast. Aliso Canyon is not needed for summer high-demand days in either period. - **Analysis 4 (Economic Analysis)**: This is a threshold comparison designed as an off-ramp: if SoCal Citygate forward prices exceed 50% above Henry Hub and historical levels, the CPUC should consider maintaining inventory regardless of reliability findings. The threshold was not triggered for winter 2025-26\. Hlavka noted that since the fall 2025 report, forward prices for winter 2026-27 have actually dropped due to mild weather and high storage inventories, meaning market conditions are now *more* supportive of reducing inventory. Energy Division's bottom line: the CPUC should reduce Aliso Canyon's levels by 10 Bcf, though it hedges that a smaller reduction "may be appropriate" given LNG export uncertainty. ### SoCalGas's Rebuttal SoCalGas's presentation was split between **Andrew Sawin** (senior engineer, Gas Transmission Planning) on reliability and **Michelle Dandridge** (senior manager, Strategic Planning, Transmission & Storage) on economics. Their central thesis: the assessment systematically understates storage value through unrealistic supply assumptions. - The main dispute is receipt point utilization (the percentage of available pipeline capacity that shippers actually schedule and deliver). Energy Division follows the **85/100%** Receipt Point Utilization framework from [Attachment A ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K129/551129840.PDF?ref=calregulatory.com)of D.24-12-076 (85% on Northern and Southern zones, 100% on Wheeler Ridge). SoCalGas calls this "unrealistic and imprudent," citing actual Receipt Point Utilization during recent storms: **47%** in 2021, **38%** in 2024, and **25%** during [Winter Storm Fern](https://en.wikipedia.org/wiki/January%5F23%E2%80%9327,%5F2026%5FNorth%5FAmerican%5Fwinter%5Fstorm?ref=calregulatory.com) in January 2026\. SoCalGas also argues that pipeline outages (L4000/L4002, L5000, L225) were not properly modeled. Their corrected supply assumptions show approximately **800 MMcfd** less available supply than Energy Division assumed. - Winter Storm Fern is SoCalGas's centerpiece: over **8 Bcf** was withdrawn from storage in six days, with Northern Zone supplies at **9%** of capacity, and Wheeler Ridge collapsing from 765 to **115 MMcfd** due to the [Castaic L225 landslide](https://abc7.com/post/castaic-gas-line-rupture-usc-geologist-discusses-landslide-caused-leak/18334153/?ref=calregulatory.com). SoCalGas's own mass balance and peak day analyses at corrected supply assumptions show deficits at both **58.6** and **68.6 Bcf**; only **86.2 Bcf** (the previous pre-leak maximum) produces a surplus. - On economics, Dandridge argued the assessment's economic analysis is too narrow: it doesn't model storage's price-mitigation role, doesn't capture Unbundled Storage Program impacts, and uses forward prices that assume current storage levels, creating a circularity problem. A 10 Bcf reduction would cut the fully-subscribed Unbundled Storage Program from 25 to **15 Bcf**, directly increasing customer price volatility and reducing ratepayer revenues. - Dandridge also cited what SoCalGas characterized as an inconsistency in the biennial assessment's forward-look pricing for winter 2026-27, claiming that when corrected, prices actually breach the **50%** economic threshold. In sum, SoCalGas's position is that no reduction in storage levels should occur. ### Q&A Session The Q&A sessions exposed vulnerabilities on both sides. - Energy Division's weakness is the economic analysis. Spencer acknowledged a circularity: "part of the reason prices are low is because storage is really high." She explicitly invited parties to address the limitations in testimony, suggesting that Energy Division wants help building a better framework. - SoCalGas's weaknesses are in their assumption choices. Abdelaziz elicited that the L4000/L4002 pressure reduction (which anchored much of SoCalGas's reliability modeling) actually ended in summer 2025 and did not persist into the winter. SoCalGas used it anyway for "consistency." - On the L225 Wheeler Ridge assumption for 2030-31, Sawin acknowledged that SoCalGas did not compute the joint probability of that outage coinciding with a 1-in-10 peak day. Abdelaziz noted prior work showed such joint probabilities are "very, very low" and questioned whether worst-case assumptions are consistent with a 1-in-10 regulatory standard. - On Receipt Point Utilization, Abdelaziz provided context: during the original investigation, no stakeholder besides SoCalGas advocated below 85%. SoCalGas's corrected supply of 2,400 MMcfd against 3,600 nominal works out to approximately **67%** ("the lowest capacity I've seen over the past six years"). - **Dr. Issam Najm** ([Porter Ranch Neighborhood Council](https://www.prnc.org/?ref=calregulatory.com)) also got Sawin to confirm that low Receipt Point Utilization figures reflect what customers *chose to schedule*, not whether gas was physically unavailable (complicating SoCalGas's framing of Receipt Point Utilization as purely a reliability metric). ### Closing Orders Ormond directed SoCalGas and Energy Division to file their presentation slides, with party comments due **April 28** (10 pages max) and reply comments due **May 5** (5 pages). She explicitly invited suggestions for improving the analytical methodology. More significantly, Ormond ordered SoCalGas to produce a narrative history of outages over the past decade that caused serious reliability concern i.e., events "that make people at SoCalGas's hair fall out," with a **May 15** deadline. ### INSTANT ANALYSIS Three disputes will shape the outcome of this proceeding. - First, Receipt Point Utilization, the single largest driver of the supply-calculation gap. Energy Division has the procedural high ground ([Attachment A](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K129/551129840.PDF?ref=calregulatory.com) of D.24-12-076), but SoCalGas has Winter Storm Fern. - Second, the economic analysis: both sides acknowledge it is rudimentary, and the party that offers the CPUC a credible framework (rather than just criticizing the existing one) may have outsized influence. - Third, whether Aliso Canyon retirement by 2030-31 is realistic given Energía Costa Azul supply diversions, L225 vulnerability, and system upgrades that haven't been publicly identified. ### WEDNESDAY AGGREGATE: PG&E and SCE Launch Flexible Service Connections, Allowing Large Loads to Interconnect Before Grid Upgrades URL: https://www.calregulatory.com/wednesday-aggregate-22/ Last updated: 2026-04-15T21:09:39.000Z Today's briefing includes: - Flexible Service Connections; - IOU opposition to any non-zero valuation of pre-2019 banked RECs in the PCIA; - A potential new compliance layer in the Climate Change Adaptation docket; - Utility responses to the CPUC president on Senate Bill 884 matters; and - PG&E's modified transmission service agreement with Microsoft. --- ### FLEXIBLE SERVICE CONNECTIONS PG&E and SCE jointly filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7868-E.pdf?ref=calregulatory.com) implementing a February decision ([D.26-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K715/598715449.PDF?ref=calregulatory.com)), which directed both utilities to establish a tariffed standard offering for Flexible Service Connections within 60 days. (*See CRI's coverage of D.26-02-025* [*here*](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/)). [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/02/iterograph_Tue-Feb-03-2026.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) The framework lets eligible customers receive electric service before full infrastructure upgrades are complete by operating under predefined Power Import Limits and time-varying seasonal load profiles. Participation is voluntary, requires customer-installed, utility-approved control systems, and is explicitly framed as an interim bridge (the agreement terminates when upgrade capacity is restored). Eligibility is determined by the utility based on grid and customer characteristics. Customers on circuits with pre-existing underground cable temperature exceedances are categorically ineligible. For eligible projects, utilities develop Load Limit Profiles optimized to the specific constrained component, monitor compliance through Advanced Metering Infrastructure and eventually [DERMS](https://www.next-kraftwerke.com/knowledge/derms?ref=calregulatory.com), and may curtail or disconnect customers who exceed limits. The proposal standardizes the application process, engineering methodology, and cost-tracking requirements across both utilities. **INSTANT ANALYSIS**: This filing creates a new access model for constrained distribution capacity. Rather than waiting for upgrades, loads with flexibility and the capital to deploy control systems can secure partial service now by accepting curtailment obligations, turning interconnection into a performance-based arrangement. That is a meaningful shift in how utilities manage distribution scarcity. Near-term, the beneficiaries are controllable demand: data centers, fleet charging, and industrial loads with shift flexibility. Inflexible loads stay behind upgrade queues. Load flexibility is beginning to function as a prerequisite for timely grid access, not just a rate incentive. Longer-term, utilities are building the contractual and monitoring infrastructure to condition grid access on real-time operational compliance. If upgrade backlogs grow faster than capital programs can clear them, this framework could graduate from a bridge mechanism into a permanent allocation regime, where dynamic limits replace guaranteed capacity as the baseline service expectation. --- ### PCIA/ERRA REFORM In [a pair of April 2026 ex parte meetings](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K598/604598913.PDF?ref=calregulatory.com), PG&E, SCE, and SDG&E briefed **Commissioner Darcie Houck**, **President John Reynolds**, and **Commissioner Matthew Baker** on their opposition to any non-zero valuation of pre-2019 banked Renewable Energy Credits in the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com). - The investor-owned utilities want one outcome: zero-dollar valuation. They argue that a Track 2 proposal advanced by CalCCA would retroactively revalue legacy RECs, shift costs onto bundled customers to benefit a subset of departing load customers, and conflict with the Public Utilities Code. On the product side, they argue that pre-2019 RECs are non-tradable, lack energy attributes, and carry no power content label or Integrated Resource Planning value. In their view, applying the RPS Market Price Benchmark to those credits is a category error. - The IOUs lean on CalCCA's own 2019 working group filing, reproduced in an appendix, where CalCCA stated that pre-2018 RECs were already paid for by bundled customers under prior RPS Adders. That becomes an estoppel line: the accounting was settled, the framework moved forward on that basis, and reopening it now is selective. - For reference, CalCCA's [March 5 ex parte](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K896/601896098.PDF?ref=calregulatory.com) frames the issue as a missing credit that arises when IOUs use banked RECs for current compliance. Under its proposal, later-departing customers receive value at the RPS Market Price Benchmark at the point of use, reflecting the IOUs' avoided cost of procuring replacement RECs. CalCCA ties this to Commission treatment of banked RECs in later vintages and presents it as a continuation of existing methodology, not a reset of prior accounting. **INSTANT ANALYSIS:** This is a battle over when value is recognized. The IOUs anchor value at the time of payment and treat the accounting as closed. CalCCA anchors value at the time of use and treats the current framework as incomplete until that credit is applied. The IOUs invoke the CPUC's 2021 [Voluntary Accelerated Market Operations](https://avaenergy.org/wp-content/uploads/2022/05/4%5FVoluntary%5FAllocation%5Fand%5FMarket%5FOffer%5FVAMO%5FPresentation%5FDraft%5Fq7p7o3.pdf?ref=calregulatory.com) decision ([D.21-05-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M385/K738/385738144.PDF?ref=calregulatory.com)) to widen the blast radius, arguing it rested on existing treatment of banked RECs and that a shift now would call prior outcomes into question. That moves the dispute from valuation mechanics into decision integrity. Every non-utility proposal in the IOUs' attached affordability chart (see below) generates a net cost transfer onto bundled customers: over two billion dollars under CalCCA's primary proposal, hundreds of millions to over one billion under the four Energy Division staff alternatives. If Energy Division drifts toward partial valuation, this becomes a negotiation over allocation mechanics. If staff holds near zero, CalCCA's position collapses. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/afford.png) --- ### CLIMATE CHANGE ADAPTATION **Commissioner Darcie Houck** issued [a ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K618/604618022.PDF?ref=calregulatory.com) that moves climate adaptation out of long-cycle utility planning and into the application review process. The ruling solicits comment on a staff-proposed [Climate Adaptation Framework](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545298.PDF?ref=calregulatory.com) that would require investor-owned utilities to address climate risks directly in infrastructure, maintenance, and emergency response filings. Initial comments are due **April 30**, with replies on **May 15**. The CPUC's[ Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) proposes a standardized structure organized around five policy areas: repetitive loss and failure, site selection, design and engineering, equipment tolerance, and climate risk modeling. For covered filings, utilities would screen against these areas, document climate risks and modeling assumptions, and tie project decisions back to existing planning tools: - The Climate Adaptation Vulnerability Assessment; and - [Risk Assessment and Mitigation Phase](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/risk-assessment-and-mitigation-phase?ref=calregulatory.com). Where that linkage is absent, utilities must explain why. An annual reporting requirement tracks how the framework was applied across filings over the prior year. The framework is presented as guidance, not a requirement. The ruling asks whether it should become mandatory, what thresholds should govern applicability, and whether smaller utilities should face scaled or phased obligations. Those questions remain open. **INSTANT ANALYSIS:** This structure would create a new compliance layer. Once utilities begin filing against these five areas, Energy Division reviews them, parties litigate them, and ALJs reference them in decisions. That is how CPUC guidance becomes practice. The near-term effect is more documentation, new intervenor entry points on modeling assumptions and design standards, and greater Commission discretion to shape project outcomes (before any formal mandate arrives). --- ### UNDERGROUNDING On April 10, the three major electric IOUs responded to prehearing conference instructions from CPUC **President John Reynolds** and **ALJ DeAngelis**. Reynolds made it clear that he was surprised, particularly in PG&E's case, that no IOU undergrounding plan had been filed with the [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) (Energy Safety). His expectation was that post-2027 undergrounding decisions should be made within the [Senate Bill 884 framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com), not in General Rate Case submissions. All three utilities share a common defense: the framework has been too unstable to anchor final investment decisions. Beyond that, their positions are different. - PG&E gives [the most detailed account](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541843.PDF?ref=calregulatory.com). Years of shifting guidance between the CPUC and Energy Safety repeatedly forced revisions to its 10-year Electrical Undergrounding Plan (Benefit-Cost Ratio methodology changes, revised data templates, new cost-recovery rules), with each iteration resetting work that was already done. With [Resolution SPD-37](http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K953/589953368.pdf?ref=calregulatory.com) in effect, PG&E sees a viable path and is targeting a Q3 2026 filing, a 2028 program start, and interim continuity through a General Rate Case bridge program if approvals slip. - SCE [has not decided whether to file at all](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545290.PDF?ref=calregulatory.com). Its existing General Rate Case already authorizes undergrounding through 2028, reducing immediate pressure to enter the new framework. It offers no filing timeline and is still evaluating whether SB 884 is even the right venue for post-2028 activity. - SDG&E [expressed a general intent to file](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536711.PDF?ref=calregulatory.com) before year-end 2026 while conditioning that on how the CPUC resolves open Phase 1 issues that could affect Benefit-Cost Ratio calculations. It is further along than Edison. **INSTANT ANALYSIS:** The utilities are being asked to commit capital while Benefit-Cost Ratio math, audit rules, and cost-recovery conditions remain unsettled. Until Phase 1 of this proceeding closes, SB 884 remains a parallel track, not the primary decision venue that President Reynolds intends it to be. --- ### LARGE LOADS/DATA CENTERS PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7886-E.pdf?ref=calregulatory.com) modifying its transmission service agreement with Microsoft for a 90 MW data center in San Jose, implementing two directives from [Resolution E-5439](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K932/594932206.pdf?ref=calregulatory.com): - Extending the refund eligibility period from 10 to 15 years; and - Capping annual refunds at **75%** of transmission-related net revenues collected from the project, adjusted for Income Tax Component of Contribution. The modified agreement also adds consequential damages and limitation of liability provisions to protect ratepayers. Key financial terms are confidential. *See CRI's coverage of Resolution E-5439* [*here*](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/). [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://static.ghost.org/v5.0.0/images/link-icon.svg)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/01/iterograph_Thu-Jan-15-2026--11-.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) **INSTANT ANALYSIS:** This filing puts the CPUC's framework for hyperscale transmission load into practice: customized agreements, cost recovery tied to project-specific revenues, refund exposure capped and time-bounded. The contracts and deviations sheets show Google and STACK Infrastructure moving through the same Rule 15/16 pathway, confirming this is now a repeatable structure rather than a one-off accommodation. The terms are designed so utilities recover costs, ratepayers aren't exposed to project shortfalls, and large customers get transmission access without broad cost socialization. That balance is what makes these agreements approvable. This pattern should hold as hyperscale demand continues hitting PG&E's service territory. ### MONDAY AGGREGATE: CPUC Begins Setting Cost-Recovery Parameters as Undergrounding and Securitization Frameworks Take Shape URL: https://www.calregulatory.com/monday-aggregate-cpuc-begins-setting-cost-recovery-parameters-as-undergrounding-and-securitization-frameworks-take-shape/ Last updated: 2026-04-13T22:35:50.000Z Today's briefing covers: - Benefit-Cost Ratio calculations for electrical undergrounding; - A PD authorizing SCE to issue almost **$2 billion** in recovery bonds to finance Woolsey Fire costs; - Energy Division's updated SERVM inputs for the RA docket; - A distortion in the Diablo Canyon cost-recovery framework; - The BioMAT's future (or lack thereof); and - Interstate natural gas capacity. --- ### UNDERGROUNDING CPUC President **John Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545275.PDF?ref=calregulatory.com) that establishes the framework for [A.26-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101196.PDF?ref=calregulatory.com), in which the CPUC will evaluate joint proposals from PG&E, SCE, and SDG&E to implement key outstanding elements of the [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). This is the first proceeding to define the cost-effectiveness framework for SB 884 undergrounding at scale, and it will drive billions in ratepayer exposure. The proceeding addresses three main issues: - How to standardize Benefit-Cost ratio (BCR) calculations for undergrounding projects; - What audit framework should govern utility cost tracking; and - What conditions should apply to cost recovery through the program's one-way balancing account. These questions trace back to prior CPUC guidance in Resolutions [SPD-15](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com) and [SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K953/589953368.pdf?ref=calregulatory.com) and from the foundational BCR work developed in the Commission's Risk-Based Decision-Making Framework. Attached to the scoping memo is a [white paper on BCR Methodology](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545276.PDF?ref=calregulatory.com), the first substantive Staff position on the BCR question, and the document that will anchor intervenor counter-proposals, which are due **June 9**. Staff recommends adopting "Method 3," the Disaggregated Formulation, which places O&M Costs in the denominator and O&M Savings in the numerator separately, and pairs that formula with the "No-Build Baseline," measuring incremental benefits only against existing funded programs. Both choices constrain utility flexibility at scale. The ruling adopts an accelerated track, with a proposed decision expected in October, and an official vote targeted for **November 19**. The schedule aligns with utility timelines, particularly PG&E's expected Q3 2026 undergrounding plan filing and its planned shift of cost recovery from General Rate Cases to the SB 884 framework, beginning in 2028\. --- **INSTANT ANALYSIS**: The CPUC is not deciding whether to underground. It is deciding how the economics get constructed and policed, and that will determine the scale, pace, and recoverability of billions in future spending. - The BCR methodology is the center of gravity, and the Staff white paper is the terrain. Staff has made the first move, recommending a specific formula and baseline that constrain how utilities can present cost-effectiveness. The recommendation to adopt the “Disaggregated Formulation” (Method 3) separates O&M costs and savings rather than netting them, avoiding the mathematical distortions that can arise when large O&M savings collapse the denominator in alternative formulations. - The No-Build Baseline is just as important. It forces projects to measure incremental benefits against existing funded programs, preventing utilities from claiming credit for risk reductions already being paid for by ratepayers. That is a direct check on double counting and materially lowers headline BCRs in high-mitigation areas. - Staff also has a broader concern with baseline manipulation. The white paper points to inconsistent baseline application in utility filings as a source of skewed results that can favor capital-intensive solutions like undergrounding over lower-cost alternatives. The audit and cost-recovery tracks carry equal importance. The one-way balancing account is already a powerful instrument; the question now is how much friction the CPUC adds around it. Strong audit rules and conditionality favor ratepayer advocates. Flexible treatment favors the utilities and accelerates deployment. This is a direct negotiation over who bears risk when costs overrun or benefits fail to materialize. The accelerated pace tells you that the CPUC wants to keep this at a policy level rather than build a litigated evidentiary record. That favors parties who can shape the written narrative early (and disadvantages intervenors who need time to develop quantitative counter-proposals to utility-drafted BCR frameworks). The June 9 counter-proposal deadline is the first true test of whether intervenors can meaningfully challenge Staff’s opening position. On the intervenor side, [EPUC filed a protest](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347234.PDF?ref=calregulatory.com). EPUC's presence shows where the pressure will concentrate: not on whether undergrounding is good policy, but on whether the BCR inputs, audit rigor, and balancing account conditions adequately protect against cost pass-through that ratepayers can't absorb. **TL;DR:** This proceeding will define the rules for undergrounding as an asset class in California. Staff has presented a framework that diminishes utility flexibility and reduces some of the methodological advantages that have historically supported large capital builds. If that framework holds, undergrounding can scale on more defensible terms. If it weakens, the conflict shifts back to whose assumptions control the math. --- ### WILDFIRES The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K577/604577373.PDF?ref=calregulatory.com) authorizing SCE to issue approximately **$1.951 billion** in recovery bonds to finance 2018 Woolsey Fire costs under [Assembly Bill 1054](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201920200AB1054&ref=calregulatory.com). The total includes **$1.639 billion** in Wildfire Expense Memorandum Account costs, **$299.2 million** in pre-securitization financing, and **$12.7 million** in upfront costs. Rather than recovering these costs through traditional ratemaking, SCE will monetize a dedicated revenue stream ("recovery property") backed by a non-bypassable Fixed Recovery Charge on most customers. The PD finds the structure meets the three-part statutory test: - Costs are just and reasonable; - Issuance is in the public interest; and - Securitization lowers total customer costs on an NPV basis. Compared to traditional rate-base financing at SCE's **7.59%** authorized return, estimated ratepayer savings are approximately **$811 million** Net Present Value. The more conservative comparison (against five-year amortization at the same discount rate) yields approximately **$304 million** NPV. The financing structure requires SCE to transfer recovery property to a bankruptcy-remote Special Purpose Entity, which issues the bonds and services debt from Fixed Recovery Charge revenues. The charge applies to all non-exempt existing and future customers, is irrevocable, and adjusts at least annually through a true-up mechanism. [CARE and FERA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com) customers are explicitly exempt. Departing load customers (Direct Access entities and Community Choice Aggregators) remain obligated under applicable tariffs. Expected transaction maturity is capped at **22 years**; legal final maturity cannot exceed **33 years**. Comments are due **April 30**. The earliest the CPUC will consider this item is **May 14**. **INSTANT ANALYSIS:** This is a textbook AB 1054 securitization, but at real scale. SCE converts its Woolsey liabilities into a bond-backed revenue stream outside rate base, trading equity returns for cheaper debt. The $811 million NPV savings claim holds directionally, but it's the favorable baseline. The $304 million figure, comparing against five-year amortization, is the more conservative read, and both numbers carry uncertainty. The non-bypassable charge attaches to essentially all load, survives migration, and binds future customers. That calcifies wildfire costs as system-level obligations rather than utility-specific exposures, and keeps pressure on departing load cost responsibility arguments for years. Duration is the number the savings narrative glosses over. Expected maturity runs to 22 years, with a 33-year legal cap. Near-term bill relief is real; so is the long-dated encumbrance. Each issuance layers another fixed charge onto the stack. Political visibility risk grows as procurement and infrastructure costs compound. SCE improves its balance sheet immediately. Customers will pay for decades. --- ### RESOURCE ADEQUACY The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541829.PDF?ref=calregulatory.com) that formally incorporates Energy Division's [updated SERVM inputs](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K617/604617992.PDF?ref=calregulatory.com) into the record. - **What Changed:** The CPUC upgraded its core reliability model (SERVM) with the 2025 [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) demand forecast, extended weather and hydro data through 2024, refreshed baseline resources from August 2025 CAISO interconnection and retirement data, improved storage optimization, updated outage rates, fuel costs, and emissions pricing. The Integrated Resource Planning proceeding holds the 2024 IEPR and prior baseline by agreement (the split is intentional, not incidental). - **Why It Matters:** This is a major update year, and the scope reflects it. Higher and more complex load shapes from electrification drivers (EVs, building load, data centers) combined with two additional extreme weather years in the dataset means SERVM is being calibrated to surface more challenging reliability conditions. Storage [ELCC](https://blog.ucs.org/mark-specht/elcc-explained-the-critical-renewable-energy-concept-youve-never-heard-of/?ref=calregulatory.com) implications from the revised optimization will directly affect RA counting rules. The baseline resource refresh closes the gap between modeled and actual system buildout. - **What to Watch:** The study case structure changed significantly, from 2,645 cases (23×23×5) to 125 cases run with 25 outage draws each. Staff decoupled weather and hydro years, a methodological assumption parties should scrutinize. The 2028 Loss of Load Expectation study result, expected by **August 2026**, will set the table for local capacity obligations, flexible capacity requirements, and the next round of IRP portfolio constraints. Everything downstream of this proceeding runs through these inputs. **INSTANT ANALYSIS:** Every number that comes out of the 2028 Loss of Load Expectation study (reliability need, ELCC values, procurement volumes) will trace back to what was just cemented into this record. Three areas stand out. - The demand forecast shift to the 2025 IEPR with explicit electrification load almost certainly pushes peak demand higher and changes its shape. Later evening peaks driven by EV charging interact badly with solar falloff. If that dynamic is embedded in the new hourly profiles, the storage adequacy picture gets worse, not better. - The storage optimization upgrade deserves scrutiny from load-side parties. Better modeled storage performs better in reliability simulations, which could reduce measured reliability need and soften procurement mandates. Parties representing load will want to examine whether the new storage dispatch logic is conservative enough to reflect real-world operator behavior. A **90%** nameplate discharge constraint is one lever; how aggressively the model arbitrages versus reserves for scarcity hours is another. - The case structure change is underappreciated. Decoupling weather and hydro years and reducing to 125 cases with 25 outage draws is a computational tradeoff. Staff defends it on convergence grounds. But it eliminates the correlated stress scenarios (wet hydro year with mild weather, dry year with heat dome) that historically drove California's worst reliability events. Parties should demand sensitivity runs. The 2028 Loss of Load Expectation study result will set the table for local capacity obligations, flexible capacity requirements, and the next round of IRP portfolio constraints. These inputs are the opening position. --- ### DIABLO CANYON The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545283.PDF?ref=calregulatory.com) granting in part a [petition by the Alliance for Nuclear Responsibility](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486351.PDF?ref=calregulatory.com) to modify a 2024 Diablo Canyon cost-recovery approval ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K462/550462685.PDF?ref=calregulatory.com)). Going forward, the CPUC will use the final Resource Adequacy Market Price Benchmark (rather than the forecast value) when determining whether Diablo Canyon's actual operating costs fall within the **115%** threshold that triggers automatic reasonableness review under the Public Utilities Code. The CPUC's rationale is straightforward: because the RA Market Price Benchmark is a Commission-issued, market-based benchmark, the final value is simply more consistent with the statute's intent to assess actual costs. The Commission agrees with PG&E that this adjustment should apply to all Diablo Canyon extended operations proceedings through 2030, not just the 2025 revenue requirement (ensuring consistent treatment across years). The PD rejects broader requests to revise past findings or adjust already-approved revenue requirements, concluding that existing ERRA-style true-up mechanisms have already flowed updated benchmark values into rates. The result is a forward-looking fix to the cost-evaluation methodology, without reopening prior rate decisions or altering previously authorized revenue levels. Comments are due **April 30**. The earliest the CPUC will consider this item is **May 14**. **INSTANT ANALYSIS:** This approval is a surgical fix to a real distortion in the Diablo Canyon cost-recovery framework. By switching the 115% test to the final RA Market Price Benchmark, the PD narrows a gap where inflated forecast benchmarks could insulate hundreds of millions in costs from review. The distinction matters because the safe harbor under the Public Utilities Code is binary: sit under 115% and scrutiny largely stops. A higher forecast Market Price Benchmark made that threshold easier to clear: the 2025 forecast Market Price Benchmark was **$42.54/kW-month** against a final value of **$11.21**. The PD stops short of reopening past revenue requirements, keeping PG&E whole on already-booked costs. But going forward, the evaluation is grounded in actual market conditions rather than CPUC forecasts that proved dramatically wrong. If adopted, the PD would harden the back-end audit function of the Diablo Canyon Power Plant framework through 2030. --- ### RENEWABLES PORTFOLIO STANDARD The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K598/604598906.PDF?ref=calregulatory.com) denying the Bioenergy Association of California's [March 2025 petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) to extend or modify the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) (BioMAT) program, on procedural grounds. The BioMAT ended on December 31, 2025 and that sunset date remains intact. The petition sought to remove or extend the sunset, adjust pricing for inflation, revise allocation rules, and expand project eligibility for microgrids and resource adequacy. The PD dismisses the petition before reaching the merits. The Bioenergy Association of California filed more than four years after the underlying decision, and its justifications (COVID disruption, subsequent legislation, 2021-2022 policy developments) were either stale or previously litigated in a prior petition that failed on the same timeliness grounds. Comments are due **April 30**. The earliest the CPUC will consider this item is **May 14**. **INSTANT ANALYSIS:** BioMAT is done as a dedicated program pathway. Any revival attempt has to compete inside the broader RPS docket, where bioenergy is one priority among many and carries none of the contractual certainty that a standalone Feed-in Tariff structure provided. The PD also reinforces that recycled policy arguments don't cure a late filing. Parties that missed the window need genuinely new facts. --- ### INTERSTATE NG PIPELINE CAPACITY PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5202-G.pdf?ref=calregulatory.com) for pre-approval to enter a firm transportation service agreement with the [El Paso Natural Gas Company](https://pipeportal.kindermorgan.com/portalui/DefaultKM.aspx?TSP=EPGD&ref=calregulatory.com) for San Juan Basin gas delivery to California core customers. The structure is a pre-arranged capacity release from a firm shipper to PG&E, not a direct contract. Contract terms are confidential (market-sensitive, proprietary) but cost recovery flows through existing channels: the Core Pipeline Demand Charge Account and Tariff G-CT for Core Transport Agents. Protests are due **April 20**. **INSTANT ANALYSIS:** This is a routine compliance filing under the CPUC's 2015 interstate capacity planning range decision ([D.15-10-050](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M155/K504/155504363.PDF?ref=calregulatory.com)). The capacity release structure is the only detail worth tracking. A firm shipper is on the other side of this transaction, and Core Transport Agents can access the confidential terms under a non-disclosure agreement, meaning secondary capacity market activity on EPNG is in motion. Core customers remain fully exposed to upstream procurement costs through existing recovery mechanisms. ### MONDAY NEWS CODEX: AES Withdrawal; SB 913; Community Solar PD URL: https://www.calregulatory.com/monday-news-codex-aes-withdrawal-sb-913-community-solar-pd/ Last updated: 2026-04-13T16:51:39.000Z - **4 New EV Fast Chargers Running on Solar Power Launched in California:** "The four charging ports are CCS, and there are six more fast chargers planned for this summer which will have NACS ports. The charging station has 1,080 solar panels to generate clean, renewable electricity and battery storage to store excess electricity to provide charges at night." [**CLEAN TECHNICA**](https://cleantechnica.com/2026/04/12/4-new-ev-fast-chargers-running-on-solar-power-launched-in-california/?ref=calregulatory.com) - **AES Pulls Out of San Diego Area Battery Project After Local Opposition:** "Independent power producer [AES Corp.](https://www.aes.com/?ref=calregulatory.com) [withdrew its application](https://thecoastnews.com/developer-withdraws-seguro-battery-project-in-eden-valley/?ref=calregulatory.com) to develop the Seguro battery system in Escondido, 30 miles from San Diego. The company had intended to fill a former horse ranch with 320 megawatts of battery containers, which would have been one of the most powerful stand-alone energy storage facilities in the country. The facility would have strengthened the Southern California grid late in the day, when solar generation fades and home consumption surges, pushing the state forward on its quest to produce 100% clean electricity by 2045." [**CANARY MEDIA**](https://www.canarymedia.com/articles/batteries/aes-san-diego-area-battery-opposition?ref=calregulatory.com) - **As EV Load Grows, Utilities Use Managed Charging to Harness Flexibility, Lower Costs:** "The California Public Advocates Office reported in 2025 that [EV charging management](http://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/presentations/251030-public-advocates-office-dgem-2025-slides.pdf?ref=calregulatory.com) had a 'significant' impact on costs for all three investor-owned utilities in the state, and 'mass shifting of peak EV load away from the peak could save between $5 billion and $18 billion in distribution costs by 2040.'" [**UTILITY DIVE**](https://www.utilitydive.com/news/as-ev-load-grows-utilities-use-managed-charging-to-harness-flexibility-lo/816859/?ref=calregulatory.com) - **Batteries Buying "Free" California Solar, Driving Up Price:** "Aurora Energy Research has found that energy storage is raising the value of negatively priced solar electricity by up to $42 per MWh in the CAISO wholesale market." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/08/batteries-buying-free-california-solar-driving-up-price/?ref=calregulatory.com) - **California Advances SB 913 to Open Grid Market to Batteries:** "SB 913, the Clean Local Power Act, advanced out of committee and now heads to the Senate floor. The bill, introduced by Senator **Josh Becker** of Menlo Park, requires the California Public Utilities Commission to build permanent market pathways for aggregated distributed energy resources to qualify as resource adequacy capacity. The CPUC would have until June 30, 2027 to finalize the rules." [**ENERGY STORAGE WIRE**](https://theenergystoragewire.com/california-advances-sb-913-to-open-grid-market-to-batteries/?ref=calregulatory.com) - **California Bill Would Limit EV-Charging Access in Affordable Housing:** "Legislation backed by developers would waive EV-charging requirements for new low-income housing projects, just as the state looks to build 1 million more units." [**CANARY MEDIA**](https://www.canarymedia.com/articles/electric-vehicles/california-limit-ev-charging-access?ref=calregulatory.com) - **California Energy Commission Says Solar Project in Twentynine Palms May Proceed Despite Council Vote:** "There was a narrow victory for opponents of a proposed solar farm at the March 23 Twentynine Palms City Council meeting when council voted to uphold the 2012 moratorium against such developments. In a letter... **Jared Babula,** attorney for the California Energy Commission, informed **Robert Smith**, attorney with K&L Gates LLP representing solar developer, E-Group, of its own power to supersede council rulings."[ **Z107.7FM**](https://z1077fm.com/california-energy-commission-says-solar-project-in-twentynine-palms-may-proceed-despite-council-vote/?ref=calregulatory.com) - **California Proposed Decision on Community Solar "Virtually Ensures No Projects Will be Built":** "The \[proposed\] decision maintains the commission’s focus on avoiding 'cost-shifting' to non-participating ratepayers, a position heavily supported by investor-owned utilities like PG&E, SCE, and SDG&E." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/04/09/california-proposed-decision-on-community-solar-virtually-ensures-no-projects-will-be-built/?ref=calregulatory.com) - **Floating Offshore4 Wind – a Financial and Environmental Catastrophe:** "Altogether, the total project cost for California’s planned offshore wind developments is $248 billion, or not quite $10 billion per gigawatt of capacity. The financing cost for this sum at 4 percent interest and a 20 year term is $18.3 billion per year. If we assume a 40 percent yield for these intermittent sources of energy (that’s optimistic, when onshore wind farm yields are closer to 25 percent), the completed project will produce 10 gigawatts of baseload power, which is equal to 87,600 gigawatt-hours per year. That is 87.6 billion kilowatt-hours, generated at an annual project financing cost of $18.3 billion, and that’s equal to $0.21 per kilowatt-hour. This is a best case wholesale price, before construction cost overruns, ongoing costs for operations and maintenance, and retail markups (adding about $0.20/kWh) to cover distribution, utility overhead, and regulatory charges." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-floating-offshore-wind-a-financial-and-environmental-catastrophe/?ref=calregulatory.com) - **Levelized Cost of Energy Models are Junk:** "\[Lazard's\] calculations show that for California, unsubsidised solar costs $51/MWh, unsubsidised solar plus some storage costs $77/MWh. However, the storage is not enough to give proper firm capacity, so the cost of solar (or solar plus storage) rises to $142/MWh when the costs of capacity payments to a firming resource are considered. The $142/MWh is above the $48-109/MWh range for a combined cycle gas turbine. However, this too flatters the cost of 'firm' renewables because the high-end cost of gas reflects a load factor of just 30%. The need to run gas turbines on such low load factors only arises because of renewables." [**EIGEN VALUES**](https://davidturver.substack.com/p/lcoe-levelised-cost-of-energy-models-junk) - **NRC Approves Diablo Canyon License Extension to 2045, Shifting Decision to California Legislature:** "The U.S. Nuclear Regulatory Commission [approved](https://www.nrc.gov/docs/ML2602/ML26022A077.pdf?ref=calregulatory.com) a 20-year operating license renewal for the Diablo Canyon Power Plant, authorizing operations for the two units until the mid-2040s. State law, however, currently limits operations to 2029 and 2030 unless the state legislature authorizes a further extension. The federal approval allows Unit 1 to operate until November 2, 2044 and Unit 2 to operate until August 26, 2045\. The approval completes the federal licensing process initiated under 2022 legislation to extend operations beyond planned retirement dates. Currently, Unit 1 is authorized to stay open until 2029 and Unit 2 is authorized to stay open until 2030." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/nrc-approves-diablo-canyon-license?ref=calregulatory.com) - **Oil Pipeline Reopens, Boosting California's Energy Supply:** "The Santa Ynez Pipeline's reopening has sparked a political battle, with Governor **Gavin Newsom**'s office and U.S. Rep. **Vince Fong** on opposite sides. Newsom, a Democrat, has been criticized for his strict environmental rules, which have accelerated refinery closures and boosted reliance on imported oil. In contrast, Fong, whose district includes some of the state's richest oil reserves, has hailed the refinery as a critical step toward lowering fuel costs. The governor has maintained that rising gas prices are due to Trump's war-related actions in Iran, which blocked the Strait of Hormuz, a key route for the world's oil supply." [**NATIONAL TODAY**](https://nationaltoday.com/us/ca/santa-ynez/news/2026/04/12/oil-pipeline-reopens-boosting-californias-energy-supply/?ref=calregulatory.com) - **Show Love for Transmission:** "That lack of capacity means California’s grid is becoming congested, and congestion makes electricity more expensive and less reliable. We need a lot more power lines, substations and other infrastructure to ensure clean energy can flow to the places where people are powering more EVs, electric appliances, air conditioners, manufacturing facilities and data centers. Major transmission projects regularly take 10 years or more to complete, and California needs dozens more to accommodate the 165 gigawatts of new clean power it’s projected to need by 2045 to meet rising demand and the state’s clean energy goals. And they need to be built affordably." [**THE CURRENT**](https://www.cleanpowercalifornia.org/show-love-for-transmission/?ref=calregulatory.com) - **Terra-Gen to Pay $5.6M to Settle CAISO Market Manipulation Charges:** "Terra-Gen also violated FERC’s 'duty of candor' rule in a compliance report to the agency related to an earlier settlement agreement. The report failed to disclose that CAISO’s market monitor had new concerns about the company’s market behavior, according to FERC." [**UTILITY DIVE**](https://www.utilitydive.com/news/terra-gen-ferc-caiso-market-manipulation/817178/?ref=calregulatory.com) - **Trump's Energy Chief Attacks California Oil and Gas Policies in Long Beach:** "Last year, Long Beach celebrated a deal Synergy Oil & Gas negotiated with a regional wetlands authority in Southern California. A former oil field, 154 acres of land in the city of Long Beach would become public wetlands; the company would gain a more valuable property and environmental credits. But a state law meant to keep wells away from homes and schools thwarted the company’s plan for more drilling – and now the wetlands deal has become fodder for the Trump administration’s war against California Democratic energy policies. U.S. Energy Secretary **Chris Wright** traveled to the property, owned by Synergy Oil & Gas, on Wednesday with a message to Gov. Gavin Newsom: state policies are increasing costs for Californians, and the Trump administration will be challenging them." [**CAL MATTERS**](https://calmatters.org/environment/2026/04/wright-synergy-oil-long-beach/?ref=calregulatory.com) ### CPUC Advances SCE Rate Design Settlements as V2G Rejection Draws Industry Pushback URL: https://www.calregulatory.com/cpuc-advances-sce-rate-design-settlements-as-v2g-rejection-draws-industry-pushback/ Last updated: 2026-04-10T23:52:05.000Z On April 9, parties filed comments on a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998920.PDF?ref=calregulatory.com) in SCE's 2024 General Rate Case Phase 2\. - Recall that the PD approves nine of 10 settlement agreements resolving SCE's 2024 General Rate Case Phase 2 on marginal costs, revenue allocation, and rate design. The PD denies a Vehicle-to-Grid Rate Proposal Settlement Agreement and declines to adopt three contested proposals (deferring PRIME Plus and baseline allowance expansion to future rulemakings, and finding the [Solar Energy Industry Association](https://www.calregulatory.com/r/bfa32be4?m=bb484012-a69a-425c-839a-750c0bd64e46)'s transmission marginal cost proposal outside the proceeding's scope). - The PD adopts a [comprehensive settlement](https://www.calregulatory.com/r/387dd818?m=bb484012-a69a-425c-839a-750c0bd64e46) on marginal cost methodology and revenue allocation, agreed to by utilities, consumer advocates, and large customer groups. It sets key cost inputs (a **$132.72/kW-year** generation capacity marginal cost, [Avoided Cost Calculator](https://www.calregulatory.com/r/f98c7155?m=bb484012-a69a-425c-839a-750c0bd64e46)\-based energy costs, and [Real Economic Carrying Charge](https://www.calregulatory.com/r/e9b74274?m=bb484012-a69a-425c-839a-750c0bd64e46)\-based customer costs) and uses these to allocate SCE's revenue requirement across customer classes. - The settlement applies a revenue-neutral allocation framework built on an illustrative **$17.5 billion** consolidated revenue requirement (approximately $17,466 million as of October 2024), with rates ultimately updated to actual authorized revenues at implementation. To limit bill volatility, the PD introduces "collars" that constrain how far class revenues can move from current levels: +**4.0%**/**−6.0%** for delivery revenues around the System Average Percentage Change, and +**0.97%**/**−1.9%** for generation revenues for bundled service customers. *Additional details on the proposed decision are available* [*here*](https://www.calregulatory.com/monday-aggregate-cpuc-approves-sce-rate-design-settlements-denies-socalgas-266m-for-angeles-link-hydrogen-pipeline/?ref=california-regulatory-intelligence-newsletter)*.* [CPUC Denies SoCalGas $266M for Angeles LinkThe CPUC issued a PD denying SoCalGas’s request to recover $266 million from natural gas ratepayers to fund Phase 2 work for Angeles Link.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-75.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Mar-18-2026--4-.png)](https://www.calregulatory.com/monday-aggregate-cpuc-approves-sce-rate-design-settlements-denies-socalgas-266m-for-angeles-link-hydrogen-pipeline/?ref=california-regulatory-intelligence-newsletter) Below is a roundup of parties' comments. If additional comments surface, we will update accordingly. --- ### Overview of Parties' Comments Parties differ on one issue. Everything else settled. The PD approves a stack of negotiated agreements on marginal costs, revenue allocation, and rate design. The California Farm Bureau Federation signed three of them and [wants adoption without changes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536669.PDF?ref=calregulatory.com). CALSTART signed the EV Rate Design Settlement and [supports it, with one clerical request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K607/604607281.PDF?ref=calregulatory.com): the PD omitted CALSTART from the settling party list. They ask the CPUC to fix the record and adopt the agreement. CALSTART's substantive point is about timing risk. Energy-only rates for medium- and heavy-duty fleet customers extend through **2030** under the settlement. The concern is what happens after. Demand charge phase-ins not tied to actual utilization could kill projects being financed today. Energization delays are common. Early-stage load factors are low. The adopted load-factor-based on-ramp ties rate treatment to actual usage rather than a calendar deadline, which is the right design. The live dispute is Vehicle to Grid (V2G). The PD rejected the Vehicle-to-Grid Rate Proposal settlement. SCE's V2G arguments were filed jointly with CALSTART, the Small Business Utility Advocates, the Solar Energy Industries Association, and the Vehicle-Grid Integration Council, a broad coalition pushing for reversal. Their argument runs on two tracks. (1) The legal track: the PD evaluated the export pricing mechanism in isolation rather than the settlement as a whole, which is the wrong standard. (2) The policy track: rejecting V2G export pathways tells manufacturers and customers that California doesn't want bidirectional charging connected to the grid. That message lands now, during a three-to-five-year product development cycle. The result is EVs optimized for behind-the-meter use (vehicle-to-home, backup power, time-of-use arbitrage) not grid resources. Approximately **18.5 GW** of battery capacity gets routed around the grid. SCE's specific defense of [Avoided Cost Calculator](https://www.cpuc.ca.gov/dercosteffectiveness?ref=calregulatory.com)\-based export pricing is grounded in a 2022 decision ([D.22-12-056](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043682.PDF?ref=calregulatory.com)), where the Commission already adopted the calculator for [Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/nem-revisit/net-billing-tariff?ref=calregulatory.com) exports at far greater scale. The PD's demand for additional studies before applying the same tool to V2G is, in SCE's framing, an evidentiary bar invented for this proceeding with no basis in prior CPUC standards. The practical problem is timing. The only existing export pathways for bidirectional charging in SCE territory (the [Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com) and the [Demand Side Grid Support Program](https://www.energy.ca.gov/programs-and-topics/programs/demand-side-grid-support-program?ref=calregulatory.com)) expire by 2027\. The Vehicle-to-Grid Rate Proposal was designed to replace them. Dynamic rates are not ready: no residential customers have enrolled in PG&E's dynamic export pilots despite direct equipment incentives. If the Vehicle-to-Grid Rate Proposal goes to further study, there is no bridge program. ### **INSTANT ANALYSIS** The CPUC's instinct is to slow-walk V2G until the evidence base is cleaner. The industry's counter is that slow-walking is itself a policy outcome, one that redirects capital, shapes product design, and forecloses grid integration during the window where it could still be built in. The issue is not resolved. If the Commission doesn't revisit V2G quickly, it comes back in the next proceeding with a longer delay and a harder argument to answer. ### Angeles Link Denial Draws Broad Support, but Parties Look to Contain Precedent Risk URL: https://www.calregulatory.com/angeles-link-denial-draws-broad-support-but-parties-look-to-contain-precedent-risk/ Last updated: 2026-04-10T22:35:51.000Z On April 9, parties filed comments on a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com) denying SoCalGas's request to recover **$266 million** from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the [Angeles Link](https://www.socalgas.com/sustainability/innovation-center/angeles-link?ref=calregulatory.com) hydrogen pipeline project. Recall that the Angeles Link proposes dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. - The PD finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision ([D.22-12-055](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K167/500167327.PDF?ref=calregulatory.com)) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers. - The PD concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. - The PD does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational. Below is a roundup of parties' comments on the PD; if any additional comments surface we will update accordingly. --- ## Overview of Parties' Comments Parties are divided along cost-allocation and policy lines, with broad agreement that Phase 2 cost recovery is off the table now, but disagreement over whether the denial is legally sound and how it should be framed. ### Consumer Advocates Consumer advocates support the denial but with distinct requests. TURN [supports the PD without modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541810.PDF?ref=calregulatory.com). The Utility Consumers' Action Network (UCAN) [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536675.PDF?ref=calregulatory.com) attribution corrections and a hedge on [Infrastructure Investment and Jobs Act ](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com)funding language. The PD states as fact that SoCalGas declined federal funding because compliance costs would not be in ratepayers' interest; UCAN wants "SoCalGas claimed" added to indicate that this is SoCalGas's characterization. UCAN also requests a new finding that parties' participation in the Angeles Link Planning Advisory Group contributed to this decision, which would open the intervenor compensation window for Advisory Group work completed throughout 2023 and 2024. Cal Advocates cites a [§1705](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-1705/?ref=calregulatory.com) deficiency: the PD discusses cost causation but fails to separately state findings of fact and conclusions of law on the issue, an omission with appellate implications. ### Environmental Advocates The Environmental Defense Fund [raises two errors of omission](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K617/604617981.PDF?ref=calregulatory.com): - The PD ignores the CPUC's Affiliate Transaction Rules, which apply to any regulated gas utility proposing activities outside its core business; and - The PD offers no guidance on what a compliant future hydrogen application would need to demonstrate, risking a market signal that utilities should abandon hydrogen infrastructure entirely. ### Industrial Ratepayers and Commercial Interests Air Products/Indicated Shippers [support the PD and want it adopted expeditiously](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K607/604607266.PDF?ref=calregulatory.com), but seek attribution corrections throughout. The PD credits Cal Advocates, CEJA/Sierra Club, and TURN for arguments that Air Products/Indicated Shippers also advanced in the record. Air Products/Indicated Shippers further preserve their jurisdictional position for future proceedings, maintaining that whether standalone hydrogen transportation falls under CPUC authority is ultimately a question for the Legislature. ### Prospective Hydrogen Users and End-User Interests The [Port of Los Angeles](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541818.PDF?ref=calregulatory.com) and the [Southern California Generation Coalition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536983.PDF?ref=calregulatory.com) (SCGC) accept the denial but want it without prejudice. The Port is a prospective direct hydrogen offtaker with zero-emission deadlines in 2030 and 2035, partially addressing the PD’s no-identified-beneficiary finding. SCGC takes a narrower approach: deny the application without prejudice and allow SoCalGas to refile under the existing Angeles Link Memorandum Account. SCGC also makes a forward-looking market case: a Lancaster-to-LA-Basin pipeline corridor is emerging, with [Element Resources building a **$1.85 billion** green hydrogen plant ](https://carboncredits.com/element-resources-launches-1-85b-hydrogen-plant-in-lancaster/?ref=calregulatory.com)opening in 2027 and the Los Angeles Department of Water & Power [converting the Scattergood gas plant to run on hydrogen](https://fuelcellsworks.com/2025/10/29/green-investment/ladwp-approves-800m-hydrogen-conversion-of-scattergood-plant-drawing-praise-and-protests?ref=calregulatory.com). ### Labor-Aligned Parties Labor-aligned parties oppose the PD but argue differently. The Utility Workers Union of America Local 483 (UWUA) [makes a procedural case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K577/604577360.PDF?ref=calregulatory.com): the PD mischaracterizes SoCalGas's position; it sought only a nominal Phase 2A authorization with allocation deferred to Phase 2B, not immediate recovery from all ratepayers. If the Commission adopts the PD, UWUA requests dismissal without prejudice. The California State Pipe Trades Council (CSPTC) [makes a statutory case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K541/604541825.PDF?ref=calregulatory.com): the planning-stage bar is wrong as a matter of law. The Commission has approved pre-construction R&D costs in rates before, including EPIC, EV charging, and demand-flexibility pilots. Senate Bill 1075's explicit directive to develop green hydrogen infrastructure is sufficient to justify departing from cost causation. CSPTC cites specific project benefits: - 53,000 direct construction positions; - 4.5 to 9 million metric tons of CO₂ avoided; and - NOx reductions equivalent to 90% of [SCAQMD](https://en.wikipedia.org/wiki/South%5FCoast%5FAir%5FQuality%5FManagement%5FDistrict?ref=calregulatory.com)'s 2037 stationary source targets. ### SoCalGas SoCalGas accepts the affordability-based outcome but mounts a comprehensive attack on the PD's legal reasoning. The main scoping violation: Phase 2A was scoped to law and policy without an evidentiary record, yet the PD renders findings of fact on cost reasonableness, beneficiary identification, and Infrastructure Investment and Jobs Act funding without affording parties a hearing. SoCalGas argues this violates [Public Utilities Code §1705](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-1705/?ref=calregulatory.com) and due process precedent. The main legal error: the PD conflates used-and-useful, which applies to plant in rate base, with the prudence standard that governs planning expenditure recovery. Applying used-and-useful to planning authorization creates a regulatory paradox that makes Phase 2 approval permanently unachievable under the staged framework that D.22-12-055 itself established. Beyond the legal errors, SoCalGas highlights two practical dangers: - The PD silently bypasses the subset-of-ratepayers question the scoping ruling put directly at issue; and - Its jurisdictional language is broad enough to reach pending proceedings the CPUC never intended to touch. SoCalGas wants three things added to the PD's ordering paragraphs: - Deny without prejudice; - Declare non-precedential on jurisdiction and cost allocation; and - Expressly carve out Phase 1 cost recovery in [A.25-06-011, the Phase 1 cost-recovery proceeding](https://www.socalgas.com/angeles-link-phase-1-reasonableness-review?ref=calregulatory.com). --- ### **INSTANT ANALYSIS** Angeles Link is in a pre-construction phase with no identified beneficiary class, making broad cost socialization hard to justify under any standard in this record. The fight is over what the denial actually adjudicates. The PD treats the denial as a merits determination (the project fails cost causation, used-and-useful, and beneficiary identification). SoCalGas, Air Products/Indicated Shippers, EDF, and SCGC argue in different registers that it should be narrower: a policy call on affordability, with jurisdictional and cost-allocation questions reserved for a proceeding with an actual evidentiary record. If the used-and-useful holding stands, utilities cannot recover planning costs for infrastructure that isn't already built, structurally precluding the staged development model the CPUC approved in D.22-12-055\. If the cost-causation adjudication stands without addressing the subset question, it forecloses alternative allocation designs parties never had the chance to brief. Notably, the without-prejudice ask cuts across opposing sides: UWUA, SCGC, the Port of Los Angeles, and SoCalGas all want it despite disagreeing on the outcome. The Commission can grant it without changing the result. --- ### TL;DR The Commission is not killing hydrogen. It's declining to fund a $266 million planning exercise on existing ratepayer backs for a project that may never be built. That is a defensible policy call. The question is whether the PD's legal reasoning survives the record it built. ### FRIDAY AGGREGATE: IRP Rehearing Tests a Constrained Procurement Model as Demand Response and Pole Access Rules Move URL: https://www.calregulatory.com/friday-aggregate-irp-rehearing-tests-a-constrained-procurement-model-as-demand-response-and-pole-access-rules-move/ Last updated: 2026-04-10T20:57:33.000Z Today's briefing includes: - Updates to our April 9 summary of CPUC Resolution E-5440, whose [final redlined changes](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K536/604536198.pdf?ref=calregulatory.com) are now available; - An AFR addressing the CPUC's recent procurement order in the Integrated Resource Planning docket; - A Demand Response ruling focused on the ELRP and DSGS programs; - SoCalGas NG curtailment updates; and - A President Reynolds PD updating access to utility poles. Collectively these items showcase how the CPUC is dealing with live systems rather than abstract policy: allocating procurement tied to load that cannot freely move, extending DR programs that were never built to last, and imposing more defined rules on who can touch the grid (and when). As we regularly see now: cost exposure and access conditions are fluid developments. --- ### INTEGRATION CAPACITY ANALYSIS (UPDATE) Yesterday we reported that the CPUC adopted [Resolution E-5440](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?ref=calregulatory.com), which approves remediation plans submitted by the investor-owned utilities to fix accuracy, transparency, and usability problems in their [Integration Capacity Analysis](https://www.calregulatory.com/r/34db80bc?m=bb484012-a69a-425c-839a-750c0bd64e46) tools. Since our post went live, [redlined changes](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K536/604536198.pdf?ref=calregulatory.com) to Resolution E-5440 surfaced in an obscure corner of the CPUC's document feed, which we've incorporated into our April 9 summary. The key modifications are: - A change indicating that SDG&E must publish its redacted generation fields within **30 calendar days** (not 15); and - Language that softens the resolution's original characterization of SDG&E being explicitly out of compliance. We've also drawn attention to PG&E's introduction of a "safety bank" technical criterion, as highlighted in the CPUC's final edit. Those updates are now fully incorporated into yesterday's summary (available [here](https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/)). [CPUC Begins Rate-Design OverhaulThe Commission launched a new rulemaking on advanced electric rate design, focused on cost causation, affordability, and clearer price signals.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-73.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Apr-07-2026--3--1.png)](https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/) --- ### INTEGRATED RESOURCE PLANNING A new [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023865.PDF?ref=calregulatory.com) surfaced in the CPUC's Integrated Resource Planning docket. The following groups (the "Rehearing Parties") filed an AFR of the CPUC's February 2026 procurement order ([D.26-02-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K777/601777006.PDF?ref=calregulatory.com)): - The [Alliance for Retail Energy Markets](https://www.retailenergymarkets.com/?ref=calregulatory.com); - The [California Coalition of Large Energy Users](https://www.linkedin.com/company/california-coalition-of-large-energy-users/?ref=calregulatory.com); - The [Regents of the University of California](https://regents.universityofcalifornia.edu/?ref=calregulatory.com); and - [Shell Energy North America](https://energyconnect.shell.com/About-SENA?ref=calregulatory.com). The Rehearing Parties argue that D.26-02-057 unlawfully allocates new resource procurement obligations by relying on current load share while ignoring the statutory cap on Direct Access, which prevents Electric Service Providers from serving new load. As a result, ESPs are assigned responsibility for capacity tied to future demand growth they cannot legally serve, creating improper cost shifting onto DA customers. The applicants contend this violates multiple provisions of the Public Utilities Code, particularly requirements around cost causation and prohibitions on shifting costs between customer classes. They assert that D.26-02-057 lacks sufficient evidentiary support and fails to align procurement obligations with actual system contributions. As remedies, they propose either reopening Direct Access to allow ESPs to compete for new load or reallocating procurement obligations to entities that can actually serve that load. *CRI's coverage of the February procurement order is available* [*here*](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-results-president-alice-reynolds-final-meeting/). [President Alice Reynolds’ Final CPUC Voting MeetingReynolds cited the addition of 6,800 MW + of new clean capacity in 2025 and the rapid build-out of battery storage to approximately 17,000 MW.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-74.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Feb-12-2026--24-.png)](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-results-president-alice-reynolds-final-meeting/) **INSTANT ANALYSIS:** This filing is a coordinated strike on the CPUC’s IRP procurement framework, centered on a single vulnerability: the CPUC allocated future capacity obligations based on static load share, while the Direct Access cap freezes ESP participation. That mismatch creates a clean cost-causation problem. ESPs are being assigned procurement tied to load growth they are legally barred from serving (especially large new loads like data centers). The filing is constructed around statutory hooks. [Section 397](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-397/?ref=calregulatory.com), [454.52(c)](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-454-52/?ref=calregulatory.com), and [366.2(d)(1)](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-366-2/?ref=calregulatory.com) of the Public Utilities Code all point to the same constraint: procurement costs must track contribution and cannot be shifted across customer classes. The parties are building a record that the CPUC ignored its own cost allocation doctrine (and decades of departing load precedent). Rehearing is paired with a parallel push to reopen Direct Access, which reframes the issue from an allocation dispute to a question about market access. If DA expands, the allocation problem dissolves. If it does not, the Commission faces pressure to reallocate billions in procurement responsibility. This filing represents an early test of how the CPUC plans to handle load growth from data centers and electrification under a constrained retail market. If the current framework holds, cost fights between utilities, Community Choice Aggregators, and ESPs will intensify. If it breaks, Direct Access expansion moves back onto the table in a serious way. --- ### DEMAND RESPONSE A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023876.PDF?ref=calregulatory.com) in [R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com) resets the schedule for resolving Demand Response bridge-year funding. It builds on a [March 10 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K872/601872252.PDF?ref=calregulatory.com) and keeps the focus on interim funding for the [Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com) and [Demand Side Grid Support Program](https://www.energy.ca.gov/programs-and-topics/programs/demand-side-grid-support-program?ref=calregulatory.com), which were both created as emergency responses to the 2020 heat events. Opening comments are due **April 30**, with replies on **May 21**. Substantively, the ruling asks whether the Emergency Load Reduction Program should continue, be redesigned, or sunset, and whether the Demand Side Grid Support Program offers elements worth carrying forward. The CPUC is no longer just extending these programs, it is forcing the question of what they become. **INSTANT ANALYSIS:** The Commission is managing a live gap: the Emergency Load Reduction Program is still being used, but it was never built to last, and nothing fully formed has replaced it. The program has been extended year after year as a stopgap, and the ruling now puts that status on the table: continue it, change it, or end it. The Demand Side Grid Support Program complicates the picture further. It sits outside CPUC control and does not have stable funding beyond 2026, leaving the state with overlapping programs and no guaranteed continuity. Either these programs are absorbed into the system on firmer footing, or they start to unwind. Either path will bring cost-allocation battles, especially if bridge-year funding continues to carry programs that were never designed to be permanent. --- ### NATURAL GAS CURTAILMENT SoCalGas filed Advice Letter 6623-G (available [here](https://tariffsprd.socalgas.com/scg/filings/?ref=calregulatory.com)) to report Q1 2026 maintenance-related gas curtailments covering January 1 through March 31\. The filing lists three localized events in Riverside, Goleta/Oxnard, and Sun Valley, each tied to planned maintenance work. SoCalGas states that all affected noncore customers were fully curtailed during the outage windows and that the events complied with its tariff rules. Customer notification relied on account managers and ENVOY postings, while customer-specific data remains confidential. Separately, SoCalGas issued an ENVOY notice for a planned noncore curtailment in Glendale on **April 14–15** (6 a.m. to 6 p.m. daily) to support maintenance work, with customer-specific usage limits to be set ahead of the event and timing subject to change. **INSTANT ANALYSIS:** This routine filing shows how SoCalGas is managing localized reliability through planned curtailments rather than emergency actions. Three events across Riverside, the Central Coast, and the LA Basin indicate a system that still requires targeted outages to complete maintenance, with noncore customers serving as the primary shock absorbers. The Glendale ENVOY notice follows immediately after the quarter, pointing to a steady pipeline of maintenance-driven constraints rather than isolated events. For large gas users, curtailment exposure is an ongoing operating condition. There is no rate impact, but the pattern is notable. Maintenance is happening on a live system, and noncore customers are carrying the burden. --- ### RIGHTS OF WAY/UTILITY POLE ACCESS CPUC President **John Reynolds** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K598/604598889.PDF?ref=calregulatory.com) that would adopt General Order 178, governing access to poles, conduit, and rights-of-way across California. The PD updates the framework established in a 2022 decision ([D.22-10-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M498/K026/498026496.PDF?ref=calregulatory.com)) and denies pending petitions for modification. A proposed [General Order](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K545/604545258.PDF?ref=calregulatory.com) standardizes make-ready timelines, expands one-touch make-ready and self-help pathways, and imposes additional transparency requirements around contractor qualifications and construction practices. The proposed GO also adds a formal overlashing provision, allowing existing attachers to add facilities to existing lines with advance notice rather than prior approval, subject to defined conditions. The PD increases penalties tied to unauthorized attachments and strengthens consequences for data reporting failures, with a greater emphasis on tracking, documentation, and compliance visibility. Pole owners would be required to submit regular compliance information identifying unauthorized attachments and their resolution status, including geographic detail. The framework also contemplates a standardized self-help agreement to be filed for CPUC approval within a defined implementation window. The earliest the CPUC will consider this item is **May 14**. Comments are due **April 30**. **INSTANT ANALYSIS**: The Commission is shifting leverage toward attachers while forcing utilities to maintain a defensible record of every attachment on the system. At the same time, required tracking of attachments, locations, and resolution status creates a strong record of what is on the system. In short, the Commission is closing the window on “we didn’t know what was on the pole.” Utilities are expected to play a more active role in identifying and addressing noncompliant attachments while maintaining defensible records. That combination raises the likelihood of disputes between pole owners and attachers as the new framework is implemented. ### California SB 254 Report Warns of Rising Wildfire Costs, Insurance Strain, and Utility Liability Pressure URL: https://www.calregulatory.com/california-sb-254-report-warns-of-rising-wildfire-costs-insurance-strain-and-utility-liability-pressure/ Last updated: 2026-04-09T23:44:22.000Z On April 7, the [California Earthquake Authority](https://www.earthquakeauthority.com/?ref=calregulatory.com) published a [Senate Bill 254](https://www.cawildfirefund.com/sb-254-natural-catastrophe-resilience-study?ref=calregulatory.com) "Study Report," which frames California's natural catastrophe problem as three interconnected systems under compounding strain: - A contracting insurance market; - Financially pressured electric utilities; and - Communities facing escalating wildfire exposure. The report's central argument is that these are not separate problems (stress in any one domain amplifies pressure on the others), with costs flowing in every direction to ratepayers and policyholders. Doing nothing has a quantifiable price, and the report attempts to establish that price as a baseline for evaluating solutions. The report organizes policy options around three pathways: - Intensifying community-level wildfire mitigation; - Reallocating catastrophe burdens across ratepayers, shareholders, and the public; and - Expanding the State's direct role in financing and backstopping wildfire risk. The report holds that resilience requires coordinated action across government, utilities, insurers, and communities (what the it calls a "whole of society" approach) that balances safety, affordability, and long-term climate goals against the escalating cost of inaction. CPUC commissioner **Darcie Houck** mentioned the report during today's CPUC voting meeting, in the context of the Commission's substantial new rate-design OIR: > I'm pleased to see the SB 254 report was issued this week and provides some very good recommendations. The legislature is going to be looking at that, and as the conversation and this rulemaking continues – and we address the challenging and wide-ranging implications for communities – we're going to need to be having that conversation, both within the rulemaking and with external entities that are going to help provide policy direction on how we address these issues. See CRI's April 9 voting meeting coverage [here](https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/). [CPUC Begins Rate-Design OverhaulThe Commission launched a new rulemaking on advanced electric rate design, focused on cost causation, affordability, and clearer price signals.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-72.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Apr-07-2026--3-.png)](https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/) ### **INSTANT ANALYSIS** This report is a serious warning with a policy menu attached. It acknowledges that California's current model (strict utility liability under inverse condemnation, cost socialization through rates, and a retreating private insurance market) was designed for a loss environment that no longer exists. The [Eaton Fire](https://en.wikipedia.org/wiki/Eaton%5FFire?ref=calregulatory.com) has likely exhausted or critically impaired the [California Wildfire Fund](https://www.cawildfirefund.com/?ref=calregulatory.com). SCE was downgraded to BBB-minus in September 2025\. The [FAIR Plan](https://www.cfpnet.com/?ref=calregulatory.com) now covers nearly 39% of homes in very high fire risk areas. The existing framework is failing. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/changes.png) Three dynamics drive the cost-of-inaction analysis. Wildfire liability costs are no longer recoverable from episodic events, they are accumulating as a baked-in charge on utility finances. Inverse condemnation and the cost-of-service model ensure that those costs migrate to ratepayers whether utilities are solvent or not. And private insurance, the traditional first-line shock absorber, is in active retreat from high-risk areas, concentrating residual risk in the FAIR Plan and, ultimately, on the State. The report's pathways highlight where the legislative conflict lands. Community mitigation is the least controversial and the slowest to show results. Liability reform (particularly around inverse condemnation) is where the most acute conflict sits, because it determines whether wildfire losses fall on shareholders, customers, or taxpayers. A State backstop and State-sponsored insurer options (Pathway 3) are the endgame scenarios: explicit acknowledgment that if the California Wildfire Fund model cannot be meaningfully reconstituted, Sacramento will absorb the residual effects. The report should be read as a precursor document for rate-design proceedings, Wildfire Fund successor negotiations, and liability reform legislation that will run through the CPUC and multiple legislative venues simultaneously. Utilities, Community Choice Aggregators, large customers, and insurers are all exposed to the cost-allocation battles this report is setting up. The conflict over who pays, how much (and through what mechanism) is taking center stage. ### April 9, 2026 CPUC Voting Meeting Results: Commission Launches Rate-Design Overhaul as Wildfire Costs, Data Centers, and Income Tiers Collide URL: https://www.calregulatory.com/april-9-2026-cpuc-voting-meeting-results-commission-launches-rate-design-overhaul-as-wildfire-costs-data-centers-and-income-tiers-collide/ Last updated: 2026-04-10T16:36:42.000Z The CPUC convened for its **April 9** voting meeting. [As we anticipated yesterday](https://www.calregulatory.com/changes-to-april-9-cpuc-voting-meeting-agenda-renewable-gas-standard-pd-delayed-until-april-30/), three notable items were held by the Commission until its **April 30** meeting: - **BIOMETHANE**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846485.PDF?ref=calregulatory.com) modifying the CPUC's Renewable Gas Standard program under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com); - **TRANSMISSION:** A [PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K795/601795585.PDF?ref=calregulatory.com) allowing PG&E to enter into a long-term investment arrangement with [Citizens Energy Corporation](https://citizensenergy.com/?ref=calregulatory.com); and - **ERRA COMPLIANCE**: A [PD](https://www.calregulatory.com/r/c05e0df7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) approving SDG&E's 2023 Energy Resource Recovery Account compliance application. Below are summaries and analyses of today's most substantive agenda items. The meeting oversaw the launch of a significant rate-design rulemaking, new compliance requirements for interconnection data, and an energy-storage investigation. --- ### ELECTRIC RATE DESIGN The Commission [launched a new rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K776/601776967.PDF?ref=calregulatory.com) on advanced electric rate design, focused on cost causation, affordability, and clearer price signals for grid use, covering both residential and non-residential rate structures. The proceeding carries forward unresolved issues from the Demand Flexibility rulemaking (the Base Services Charge, dynamic rates, and electrification incentives) and implements two new statutory requirements: - A data-center cost impact assessment due to the Legislature by **January 1, 2027**; and - An exemption from non-bypassable charges for certain industrial customers using process heat recovery technology ([Assembly Bill 2109](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=201120120AB2109&ref=calregulatory.com)). A [proposed consultant scope](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K838/603838663.pdf?ref=calregulatory.com) expands the Commission's rate-design modeling infrastructure and adds a new toolkit for large non-residential customers. Parties will be able to model bill impacts across Time-of-Use periods, demand charges, and major cost drivers including transmission and wildfire costs. Wildfire-related costs are now central to rate design. Authorized costs between 2019 and 2024 total approximately **$40 billion** (about27% of PG&E's total revenue requirement and 17% of SCE's and SDG&E's), which is currently recovered through volumetric rates. An [Income Verification Process Working Group report](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K849/603849545.pdf?ref=calregulatory.com) proposes a framework for differentiating among non-low-income customers (those who do not qualify for [CARE or FERA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com)) by subdividing them into separate moderate- and high-income tiers using census tract data. A customer appeals process would handle exceptions. The Commission is also considering an alternative design that would place all non-low-income customers in the highest tier by default, requiring them to appeal downward to receive a lower rate. **COMMENTS FROM THE DAIS:** President **John Reynolds** framed rate design as the primary interface between ratepayers and California's policy goals: well-designed rates advance the transition, poorly designed ones work against it. - Commissioner **Matthew Baker** said existing methods are "deeply unequal" and breaking down under wildfire costs embedded in volumetric rates. He noted Fresno, where PG&E customers are running **$40–$100/month** above average in summer, with the lowest wealth quintile spending as much as **75%** of discretionary income on electricity after rent. - Baker named this as a direct consequence of how wildfire costs are currently collected. - Baker also acknowledged data-center load growth as a potential source of system value, not just a cost-shifting risk. - Commissioner **Christine Harada** framed rate design as the incentive layer determining whether infrastructure investment realizes its value, emphasizing modernized price signals, accessible demand flexibility, and equitable benefit distribution. - Commissioner **Darcie Houck** said that the affordability crisis is rooted in asking rates to solve problems that ratemaking is ill-equipped to solve, with wildfire mitigation costs being the prime example. She characterized the current recovery structure as unsustainable given that the benefits accrue to the state as a whole (rather than ratepayers alone). - Houck raised the possibility of moving these costs out of rates entirely and pointed to the [new Senate Bill 254 report](https://www.cawildfirefund.com/sites/wildfire/files/documents/2026/sb-254-natcatresiliencyreport4-7-26.pdf?ref=calregulatory.com) as carrying legislative recommendations the CPUC will need to coordinate with externally. - Houck also broadened the affordability lens to the large population of Californians for whom the rate itself is the only available mitigation tool, called out tribal communities as requiring proactive engagement. - Houck closed by highlighting demand flexibility as an underutilized tool that the rate structure should be explicitly designed to accommodate. **INSTANT ANALYSIS:** This OIR is a major reset. The CPUC is consolidating unresolved issues from multiple proceedings into a single venue where affordability, electrification, and large-load growth now collide. Standardized modeling tools will compress input disputes; the real fights will be over methodology, cost-allocation assumptions, and who controls the analytical frame. Four areas merit close attention. - **Wildfire cost recovery** is the dominant affordability driver and may become a legislative question, not just a rate-design one. At 17–27% of utility revenue requirements and recovered entirely on a volumetric basis, any reclassification into fixed or demand charges reshapes bills for every large C&I customer on the service list. Entities with exposure to cost-recovery proceedings or legislative strategy should treat this as a question of who ultimately bears wildfire liability costs, not just a rate-design dispute. - **Large-load tariff design** will be contested on two fronts simultaneously: ratepayer protection from data center cost-shifting on one side, and tariff structures that capture system value from large loads on the other. Commissioners Baker and Houck both noted the upside: large-volume consumption, correctly tariffed, could place downward pressure on rates broadly. How the Commission resolves this issue will determine whether data-center growth is net negative or net positive for the broader customer base and sets precedent for hydrogen and other large emerging loads. - **Income verification** carries significant cost and misclassification risk. The proposed threshold defining "moderate income" (below **600%** of the Federal Poverty Line, or **$159,900** for a household of three in 2025) will be the opening salvo in party comments. The alternative design that would place all non-low-income customers in the highest tier by default would significantly alter administrative burden and customer segmentation outcomes if adopted. Commissioner Baker's Fresno data shows the gap is already wide enough that getting it wrong at scale could put more upward pressure on rates. - **Demand flexibility and dynamic rates** are the execution layer uniting all three areas above. Harada telegraphed that proposals failing to credibly translate price signals into customer behavior will face opposition throughout this proceeding. Commissioner Houck reinforced it: rate structures that treat demand flexibility as an add-on rather than a design requirement are unlikely to survive Commission scrutiny. Interconnection economics are a natural downstream consequence of how large-load rate design resolves, though not a stated scope item in this order. --- ### INTEGRATION CAPACITY ANALYSIS [Resolution E-5440](https://www.calregulatory.com/r/a4aa5e58?m=bb484012-a69a-425c-839a-750c0bd64e46) approves, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their [Integration Capacity Analysis](https://www.calregulatory.com/r/34db80bc?m=bb484012-a69a-425c-839a-750c0bd64e46) tools. These tools estimate how much distributed energy can be added to the grid without upgrades. The resolution approves PG&E's already-underway remediations for erroneous device setting data and incorrect queued generation mapping, orders SCE to complete reactivation of the remaining 311 inactive circuits on its ICA maps by September 30, directs utilities to improve the timeliness of map updates, and expands reporting so stakeholders can track when Integration Capacity Analysis results diverge from real interconnection outcomes. - It establishes a formal concordance/discordance framework that categorizes interconnection and energization applications into one of four scenarios based on whether the ICA map value and the actual engineering outcome aligned. In so doing, the resolution creates a taxonomy for measuring ICA usefulness across all three major electric utilities. - The resolution orders SDG&E to immediately cease excessive redactions of "Total Generation" and "Existing Generation" fields for circuits implicating the 15/15 rule and to publish those fields within **30 calendar days**. It also directs all utilities to publish more complete system information (including substations up to the transmission level) on public planning portals within three months, and establishes new metrics to measure whether Integration Capacity Analysis outputs align with actual engineering results. - The resolution codifies new definitions, distinguishing "ICA accuracy" (whether the utility correctly followed the approved methodology) from "ICA alignment" (whether ICA results match real-world engineering outcomes). **INSTANT ANALYSIS:** This resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. The resolution holds SDG&E noncompliant on redaction practices, reinforcing that these are enforceable obligations**.** For developers, DER providers, and large-load customers, the main takeaway is that Integration Capacity Analysis outputs will become more auditable as the new tracking and reporting requirements take effect (concordance tracking within six months, substation portal updates within three). The framework creates equal scrutiny for both false positives (ICA shows capacity, engineering finds a constraint) and false negatives (ICA shows a constraint, engineering finds capacity), giving utilities reason to improve methodology accuracy rather than systematically shade results in either direction. **UPDATE:** A separate issue that surfaced late in the proceeding warrants watching: the [Interstate Renewable Energy Council](https://irecusa.org/?ref=calregulatory.com) raised concerns that PG&E inserted a "safety bank" criterion not authorized by Commission orders, which can trigger redaction of ICA Static Grid results (a critical output for interconnection customers). The resolution does not resolve the issue but orders utilities to present on their reverse-power-flow calculations at the next ICA workshop and file a joint advice letter establishing or modifying their approaches. How that proceeding develops could affect interconnection siting intelligence across all three utilities. --- ### ERRA COMPLIANCE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846486.PDF?ref=calregulatory.com) approves SCE's 2023 ERRA compliance application in full. SCE gets a clean record on procurement compliance, contract administration, least-cost dispatch, and account treatments. The financial result: a **$63.195 million** rate decrease reflecting net overcollections across seven accounts, plus a **$70,811** return tied to four 2023 Public Safety Power Shutoff events. Cal Advocates argued that a series of contract disputes, invoice errors, and a letter of credit defect spanning three record years established a year-to-year pattern of imprudent contract management by SCE, warranting heightened scrutiny in future ERRA proceedings. The decision rejects that framing entirely: each incident had been (or is now) resolved as prudent, and four contracts over multiple years at a **0.0048%** error rate does not constitute a pattern. No disallowances. No enhanced disclosure requirements. The one process constraint: SCE must file a Tier 2 Advice Letter within 60 days to modify its Affiliate Transfer Fee Memorandum Account tariff and return a **$219,000** overcollection through the Base Rate Recovery Balancing Account. The CPUC split the remedy, approving the underlying entries now, but requiring staff and public review before formalizing the forward-looking tariff treatment. **INSTANT ANALYSIS:** This is a standard compliance approval. Cal Advocates' attempt to convert ERRA into a procurement enforcement vehicle fails. The decision does include one warning, however: two or more contract errors in a single record period may be enough to establish the pattern Cal Advocates couldn't prove here. That language matters for future proceedings. --- ### ENERGY STORAGE INVESTIGATION The CPUC [launched an investigation](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K525/604525374.PDF?ref=calregulatory.com) to determine whether: - PG&E’s Elkhorn Energy Storage System has been out of service for nine or more consecutive months; and - The CPUC should eliminate consideration of the plant’s value or disallow associated expenses from rates under [Public Utilities Code §455.5](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-455-5/?ref=calregulatory.com#:~:text=%28b%29%20Every%20electrical%2C%20gas,commission%20when%20any%20portion%20of) or other statutory authority. The 182.5 MW/730 MWh battery system at Moss Landing has been offline since June 2, 2025 following a coolant leak during restart. PG&E reports it has no definitive return date and is planning for the facility to remain offline through the remainder of 2026. While PG&E maintains that energy storage may not qualify as a “generation or production facility” under §455.5, it provided notice voluntarily, triggering the CPUC’s obligation to open this proceeding. The order launching this rulemaking also directs PG&E to establish a memorandum account to track its authorized revenue requirement and related revenues, with amounts accruing interest and subject to refund from the date the investigation is issued. The matter may ultimately be addressed in coordination with PG&E’s Test Year 2027 General Rate Case. **INSTANT ANALYSIS:** If the Commission finds that §455.5 applies to storage, the statute provides a direct path to disallow value and expenses tied to a prolonged outage. If it does not, the CPUC retains authority under “just and reasonable” standards to examine the same cost-recovery question. - The memorandum account does not determine outcomes, it preserves the ability to reconcile revenues and apply refunds with interest if the CPUC later finds that costs should not have been collected during the outage period. - The record points to extended uncertainty. PG&E has no restart timeline and is working with Tesla as the maintenance and warranty provider to address the coolant leak. That combination keeps the focus on outage duration, asset classification, and cost recovery rather than safety findings, which are being handled in separate investigations. At the end of the day, this is a cost-recovery proceeding anchored in outage duration and statutory interpretation, with potential downstream implications for how long-duration outages at utility-owned storage assets are treated in rates. ### Changes to April 9 CPUC Voting Meeting Agenda: Renewable Gas Standard PD Delayed Until April 30 URL: https://www.calregulatory.com/changes-to-april-9-cpuc-voting-meeting-agenda-renewable-gas-standard-pd-delayed-until-april-30/ Last updated: 2026-04-10T00:19:49.000Z Some substantive energy items on the **April 9** CPUC voting meeting agenda [have been delayed](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K537/604537612.PDF?ref=calregulatory.com) until **April 30**. Commissioner **Darcie Houck** held the following two items for further review. - **BIOMETHANE**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846485.PDF?ref=calregulatory.com) modifying the CPUC's Renewable Gas Standard program under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com). - **TRANSMISSION PROJECTS:** A [PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K795/601795585.PDF?ref=calregulatory.com) allowing PG&E to enter into a long-term investment arrangement with [Citizens Energy Corporation](https://citizensenergy.com/?ref=calregulatory.com), under which Citizens could lease partial transmission entitlements in future PG&E transmission projects. Additionally, commission staff requested a hold on the following item until April 30\. - **ERRA COMPLIANCE**: A [PD](https://www.calregulatory.com/r/c05e0df7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) approving SDG&E's 2023 Energy Resource Recovery Account compliance application. Our full meeting preview is available at the following link. We will provide complete meeting results tomorrow afternoon. The CPUC's agenda can be found [here](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K524/604524766.pdf?ref=calregulatory.com). [New Rulemaking Forces a Decision on Who Pays for Large LoadThe April 9 agenda reflects a Commission increasingly focused on cost control, data accountability, and who ultimately bears system costs.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-71.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Mar-31-2026--26--1.png)](https://www.calregulatory.com/puc-april-9-voting-preview-new-rulemaking-forces-a-decision-on-who-pays-for-large-load/) ### WEDNESDAY AGGREGATE: Cost Questions Intensify Across Storage, SB 1221, and Shared Renewables URL: https://www.calregulatory.com/wednesday-aggregate-21/ Last updated: 2026-04-08T19:38:09.000Z Today's aggregate includes: - More activity involving Senate Bill 1221 decarbonization pilots; - Utility safety metric reports and energization reports; - A PD establishing the statewide Shared Renewables Portfolio; - SDG&E's cost-benefit report on the Advanced Energy Storage project; and - A looming investigation into PG&E's Elkhorn Energy Storage System. We will include a summary on the latter item in our full April 9 voting meeting report tomorrow afternoon (*please see our meeting preview* [*here*](https://www.calregulatory.com/puc-april-9-voting-preview-new-rulemaking-forces-a-decision-on-who-pays-for-large-load/)). [New Rulemaking Forces a Decision on Who Pays for Large LoadThe April 9 agenda reflects a Commission increasingly focused on cost control, data accountability, and who ultimately bears system costs.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-70.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Mar-31-2026--26-.png)](https://www.calregulatory.com/puc-april-9-voting-preview-new-rulemaking-forces-a-decision-on-who-pays-for-large-load/) ### SENATE BILL 1221/DECARBONIZATION PILOTS California's four major gas utilities filed compliance reports in the CPUC's [Long-Term Gas Planning docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com), documenting their virtual [SB 1221](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/sb-1221-implementation?ref=calregulatory.com) information sessions and stakeholder outreach pursuant to a decision last December ([D.25-12-042](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K226/592226529.PDF?ref=calregulatory.com)). In sum, the reports reflect a mix of public resistance, information gaps, and in Southwest Gas's case, [near-total indifference](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K032/604032587.PDF?ref=calregulatory.com). - SoCalGas and SDG&E held the most attended sessions and recorded the clearest opposition majorities: [29 of 38 commenters opposed SoCalGas](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023794.PDF?ref=calregulatory.com); 25 of 34 [opposed SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K016/604016117.PDF?ref=calregulatory.com). - PG&E's session landed differently: [its own sentiment analysis](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K016/604016117.PDF?ref=calregulatory.com) found the dominant tone was neutral and information-seeking rather than oppositional, with negative comments clustered around implementation concerns rather than outright rejection. - Southwest Gas is the only utility that reported no tribal contacts, no load-serving entity contacts, and no expressed interest from any community organization. Where opposition did register, it boiled down to: - The electric grid cannot absorb the load; - Public Safety Power Shutoff and wildfire outages make full electrification dangerous; and - Gas provides resilience that electricity doesn't. Several commenters characterized the SB 1221 program as a forced conversion softened by "pilot" language. Cost concerns were everywhere: appliance replacement, panel upgrades, rewiring, ongoing rate exposure. Written comments [in SDG&E’s appendix](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K016/604016117.PDF?ref=calregulatory.com) illustrate the cost pain: a fast-food franchisee estimating six-figure conversion costs per location, a solar homeowner facing higher electric bills without the ability to expand generation, and a resident unable to secure an electrical service upgrade. On equity, feedback across all four sessions converged on the same issue. Low-income households, renters, seniors on fixed incomes, and medically vulnerable customers are the least equipped to absorb upfront conversion costs. The program’s stated equity rationale (targeting disadvantaged communities) runs directly into its operational constraint. The populations most targeted are the least able to comply. The next phase of this proceeding will focus on program design: pilot structure, cost recovery, Priority Neighborhood Decarbonization Zone updates by **December 31**, and program requirements adoption by **July 1**. **INSTANT ANALYSIS**: The July 1 program design deadline is what actually matters. Cost recovery (who pays, how stranded gas assets get treated, whether utilities earn on electrification capital) determines whether large users engage or ignore this proceeding. Right now they are waiting for cost-recovery design to tell them whether these developments are worth their attention. SB 1221 requires 67% property owner consent before any pilot can be approved (a real constraint on deployment, but one whose mechanics haven't been designed yet). Priority Neighborhood Decarbonization Zone update criteria remain undefined. No utility recommended new census tracts with analytical confidence because the program details that would make such recommendations meaningful don't exist yet. The equity problem is baked in. If pilots front-load costs onto residents in disadvantaged communities without robust bill protection and appliance replacement funding, the CPUC will have built something politically and legally vulnerable from Day 1\. The public comment record says that in plain language. Whether the CPUC reads it that way is the question. --- ### RISK-BASED DECISION-MAKING California's major investor-owned utilities filed Safety Performance Metrics Reports under the CPUC's risk-based safety framework. The filings contain: - 10 years of historical metric data where available; - Narrative context linking metrics to operations; - Explicit executive compensation ties; - Bias control disclosures; and - Documentation of how metrics feed [RAMP](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/risk-assessment-and-mitigation-phase?ref=calregulatory.com) and General Rate Case commitments. The Sempra utilities cover different slices of the 32-metric framework. SDG&E [reports on 29 metrics](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K030/604030075.PDF?ref=calregulatory.com): the full set minus Metric No. 12 ("Natural Gas Storage Baseline Assessments"), which doesn't apply because SDG&E operates no storage facilities. SoCalGas [reports on the 20 metrics applicable to a gas-only utility](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K016/604016120.PDF?ref=calregulatory.com). Both filings emphasize multi-year trend narratives, safety management plan integration, workforce training, and public safety coordination, using metric outputs to document measurable safety improvements and satisfy RAMP and GRC process requirements. SCE's filing [ties specific metrics to corrective actions, contractor training and oversight, and continued deployment of its Safety Management System](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023785.PDF?ref=calregulatory.com), building a metric-by-metric record of what changed and why. Executive compensation linkages are detailed at the individual metric level, consistent with the CPUC's expectation that utilities not just track safety performance but actively drive organizational behavior through it. PG&E filed two documents. - Its [annual Safety Performance Metrics Report ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K085/604085923.PDF?ref=calregulatory.com)follows the same Commission-directed framework as the other utilities (metric tracking, compensation linkages, bias controls, and risk-spend context cross-referenced to its 2023 General Rate Case). - Separately, PG&E filed its [ninth semi-annual Safety and Operational Metrics Report covering January 1 through December 31, 2025](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K030/604030077.PDF?ref=calregulatory.com), a broader operational dataset that includes reliability indices ([SAIDI](https://en.wikipedia.org/wiki/SAIDI?ref=calregulatory.com), [SAIFI](https://en.wikipedia.org/wiki/SAIFI?ref=calregulatory.com)), outage performance, distribution and transmission ignition metrics, and gas system safety indicators. That report is anchored to PG&E's 2024 RAMP and pending 2027 General Rate Case. The two PG&E filings position the company's metrics as live management tools: tracking trends, triggering corrective actions, and maintaining system-wide risk visibility across both electric and gas operations. **INSTANT ANALYSIS:** Utilities are no longer arguing that their programs reduce risk. They are required to prove it through standardized, longitudinal data tied directly to spending, operations, and executive pay. And they are building their records differently. The Sempra IOUs lean on trend narratives and program alignment. SCE builds metric-by-metric through operational feedback and contractor accountability. PG&E runs two parallel tracks (one Commission-standardized, one operationally expansive) and uses both to project institutional control over system risk. The CPUC has created a common measurement language but it has not created a common truth. The next phase of litigation will center on whether these metrics reflect real risk reduction, or whether they can be gamed, redefined, or selectively framed to support rate requests. --- ### TIMELY ENERGIZATION California’s major electric IOUs filed their biannual energization reports in the CPUC's [Timely Energization docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com). The filings indicate that the Commission’s energization timeline is operational and largely being met, but the process remains constrained by factors utilities do not control. All three utilities report against the framework established by a 2024 CPUC decision ([D.24-09-020](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K806/540806654.PDF?ref=calregulatory.com)). They have implemented the required tracking systems and are producing more granular data, but energization is not linear. It spans engineering, permitting, construction, customer readiness, and upstream capacity, with many steps occurring in parallel and outside utility control. - Compliance rates are high. [PG&E reports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023792.PDF?ref=calregulatory.com) **95%** to **97%** of its projects meeting maximum timeline targets in 2025, with similar directional performance across the other utilities. - The constraint is execution. [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K533/603533572.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K030/604030059.PDF?ref=calregulatory.com) state that their legacy systems do not align cleanly with the CPUC’s eight-step framework, which limits precise tracking where responsibilities overlap. All three utilities point to ongoing system upgrades, but full alignment requires significant investment. - Operational limits drive outcomes. SCE cites permitting delays, material shortages, complex design, and outage constraints. SDG&E highlights overlapping workflows. PG&E quantifies the upper bound, with upstream upgrades taking **950** to **1,285** days. - Timelines are stable, not falling. PG&E reports flat performance from 2023–2025 with a slight late-period improvement. - PG&E states that [Senate Bill 410](https://calmatters.digitaldemocracy.org/bills/ca%5F202320240sb410?ref=calregulatory.com) support is sustaining its current performance and warns that gains will not continue without it. **INSTANT ANALYSIS:** The CPUC has a working system with high compliance but utilities control only part of the process. External factors set the pace. That gap will drive the next phase: disputes over who owns delays. Without continued funding, timelines will hold, at best. --- ### SHARED RENEWABLES The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K536/604536932.PDF?ref=calregulatory.com) that implements the California Shared Renewables Portfolio by establishing a Community Renewable Energy tariff on a [ReMAT](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com)/[PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant foundation and rejecting proposals for compensation above avoided-cost levels. Following the EPA’s termination of Solar for All funding and the reversion of the $33 million state appropriation, the PD proceeds without the external funding layer contemplated in a 2024 CPUC decision ([D.24-05-065](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K424/540424861.PDF?ref=calregulatory.com)). For Green Tariff programs, the PD shifts stranded cost recovery to each utility’s ERRA proceeding and reduces oversight by eliminating annual forums and advisory structures in favor of Procurement Review Group and ERRA oversight. Comments are due **April 27**. **INSTANT ANALYSIS:** The PD places the shared renewables portfolio within a strict avoided-cost framework. With Solar for All funding terminated and the $33 million appropriation reverted, the program loses the subsidy layer that was expected to support participation. The CPUC is advancing implementation, but prioritizing statutory compliance and ratepayer protection over project economics. By anchoring the tariff to ReMAT and rejecting adders above avoided cost, the Commission is signaling that nonparticipants will not subsidize the program. That preserves legal defensibility, but narrows the revenue stack for developers and makes financing more difficult. For Community Choice Aggregators and developers, the result is a viable tariff structure with limited pricing flexibility and weaker market-building incentives. --- ### ENERGY STORAGE/MICROGRIDS SDG&E filed its [compulsory cost-benefit report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023801.PDF?ref=calregulatory.com) for a 7.3 MW/14.6 MWh battery system at the [Borrego Springs microgrid](https://www.sdge.com/sites/default/files/documents/2025-07/2024%20SDGE%20BorregoSpringsMicrogrid%5FFact%20Sheet%5FFinal%5FDOE.pdf?ref=calregulatory.com), which is intended to absorb excess solar and support local reliability. This particular project – Advanced Energy Storage, or AES – reached CAISO commercial operation on August 12, 2025, operated as a dual-asset microgrid on November 5, 2025, and was treated as complete after February 2026 data validation. Total project cost to date is about **$33.1 million**, including a $4.913 million reduction tied to a denied hydrogen storage component. SDG&E says the battery is already creating value through CAISO market participation, energy arbitrage, and avoided Resource Adequacy procurement, while also providing resiliency, zero-emissions operation in some modes, and improved solar utilization. **INSTANT ANALYSIS:** SDG&E is positioning the AES project as proof of a new utility storage model: a single asset that can monetize wholesale market participation, defer or avoid RA procurement, and still serve as a local reliability tool when needed. The battery can switch roles cleanly between market asset and microgrid support asset without operational friction. The most important takeaway is that the CPUC appears willing to support battery-first deployments when they are tied to an authorized project scope and can show concrete operating value. But the Commission is not extending that tolerance to adjacent concepts like hydrogen storage that were not expressly authorized. This creates a strong regulatory signal: utilities can recover and operationalize batteries more easily when they fit within an approved framework, but they will face a much higher burden for speculative (or peripherally connected) technologies. --- ### ENERGY STORAGE INVESTIGATION At its **April 9** voting meeting, the CPUC is expected to [launch an investigation](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M604/K525/604525374.PDF?ref=calregulatory.com) to determine whether: - PG&E’s Elkhorn Energy Storage System has been out of service for nine or more consecutive months; and - The CPUC should eliminate consideration of the plant’s value or disallow associated expenses from rates under [Public Utilities Code §455.5](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-455-5/?ref=calregulatory.com#:~:text=%28b%29%20Every%20electrical%2C%20gas,commission%20when%20any%20portion%20of) or other statutory authority. The 182.5 MW/730 MWh battery system at Moss Landing has been offline since June 2, 2025 following a coolant leak during restart. PG&E reports it has no definitive return date and is planning for the facility to remain offline through the remainder of 2026\. While PG&E maintains that energy storage may not qualify as a “generation or production facility” under §455.5, it provided notice voluntarily, triggering the CPUC’s obligation to open this proceeding. The order launching this rulemaking also directs PG&E to establish a memorandum account to track its authorized revenue requirement and related revenues, with amounts accruing interest and subject to refund from the date the investigation is issued. The matter may ultimately be addressed in coordination with PG&E’s Test Year 2027 General Rate Case. **INSTANT ANALYSIS:** If the Commission finds that §455.5 applies to storage, the statute provides a direct path to disallow value and expenses tied to a prolonged outage. If it does not, the CPUC retains authority under “just and reasonable” standards to examine the same cost-recovery question. - The memorandum account does not determine outcomes, it preserves the ability to reconcile revenues and apply refunds with interest if the CPUC later finds that costs should not have been collected during the outage period. - The record points to extended uncertainty. PG&E has no restart timeline and is working with Tesla as the maintenance and warranty provider to address the coolant leak. That combination keeps the focus on outage duration, asset classification, and cost recovery rather than safety findings, which are being handled in separate investigations. At the end of the day, this is a cost-recovery proceeding anchored in outage duration and statutory interpretation, with potential downstream implications for how long-duration outages at utility-owned storage assets are treated in rates. ### CAISO Draft Plan: Congestion Surge Forces $7 Billion Transmission Buildout to Serve Load Growth URL: https://www.calregulatory.com/caiso-draft-plan-congestion-surge-forces-7-billion-transmission-buildout-to-serve-load-growth/ Last updated: 2026-04-08T14:53:21.000Z The CAISO [published its draft 2025–2026 Transmission Plan](https://www.caiso.com/about/news/news-releases/draft-transmission-plan-now-available-recommends-38-infrastructure-upgrades-to-meet-growing-electricity-demand?ref=calregulatory.com), which identifies 38 transmission projects totaling **$7 billion** over the next decade. These projects combine new infrastructure with upgrades to existing lines, plus the targeted use of grid-enhancing technologies to expand capacity at lower cost. The draft plan reflects a shift in California's transmission needs. Earlier planning cycles focused on accessing remote renewable resources. This one is driven by load growth (electrification, manufacturing, and data centers), with reliability needs now outweighing policy-driven renewables expansion. State forecasts underpinning the plan show load growth of **15 GW** by 2035 and **20 GW** by 2040, with installed resource capacity needing to increase by more than **74 GW** and **107 GW**, respectively. This will force a coordinated expansion of generation and transmission at a scale California has not previously planned for. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/ISO.png) Congestion is the central cost driver. [Path 15](https://en.wikipedia.org/wiki/Path%5F15?ref=calregulatory.com) congestion forecasts have increased tenfold in five years: the 2021–2022 plan projected 244 hours of congestion on the most limiting circuit by 2030\. The draft plan projects **3,256 hours** by 2035\. The CAISO frames transmission expansion explicitly as a tradeoff: upfront infrastructure cost versus sustained high-cost dispatch that shows up in energy charges. Geographically, the draft plan prioritizes the Greater Bay Area, the Central Valley, and key import corridors from the Southwest. It supports the planned buildout of **45 GW** of solar, **8 GW** of in-state wind, over **2 GW** of geothermal, **10 GW** of imported wind, and **4.5 GW** of offshore wind, with battery storage co-located at generation sites and positioned near major load centers. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/zones.png) Key projects include: - The Tesla–Trimble–Metcalf 230 kV corridor expansion for the south Greater Bay Area; - The Trout Canyon–Lugo 500 kV line for East of Pisgah resources; - Gates–Los Banos #3 500 kV series compensation for Path 15 congestion; and - A proposed Windhub–Tesla 500 kV line to further relieve Path 15, which requires additional engineering refinement and is not expected to be recommended for approval until the next planning cycle. Of the 38 projects, 12 include reconductoring, three of which use advanced conductors as the most cost-effective solution. The [CAISO Board of Governors](https://www.caiso.com/documents/boardofgovernorsroster.pdf?ref=calregulatory.com) will consider the draft plan at a virtual meeting on **May 19**. Prior to that, an **April 15** stakeholder call will review the draft plan and solicit feedback. ### **INSTANT ANALYSIS** This draft plan is load growth materializing in hard infrastructure. Data centers, electrification, and industrial demand are the primary drivers of transmission buildout, not renewables integration. The real story is the congestion curve turning vertical. Path 15 has moved from a manageable constraint to a persistent cost driver in a single planning cycle. A tenfold increase in forecast congestion hours forces the CAISO to justify large capital deployment as near-term cost containment, not long-lead planning. For market participants, this is a forward signal on basis risk and deliverability. Congestion will rise before these projects come online, which means localized price separation, curtailment risk in resource zones, and increasing value for assets positioned inside constrained load pockets. ### **WHO IS MOST AFFECTED** - **Large load developers (data centers, industrials):** These entities are driving the buildout and will face interconnection timelines, deliverability constraints, and cost-allocation battles. Siting decisions will determine whether they will hit delays or premium infrastructure costs. - **Investor-owned utilities (PG&E, SCE, SDG&E):** The IOUs inherit execution risk. Projects flow into rate base under rising affordability pressure and scrutiny over transmission spending. - **Noncore gas and large electric customers:** Transmission buildout tied to electrification raises delivered power costs, while parallel gas system underutilization drives a second layer of cost reallocation. - **Developers in constrained resource zones (Central Valley, imports, offshore wind):** Deliverability is the bottleneck. Projects without firm transmission access face curtailment risk and weaker economics until upgrades are in service. - **Traders and structuring desks:** The draft plan is a congestion map. Expect widening nodal spreads, more persistent basis risk, and increased value in congestion hedging around load pockets and constrained paths. - **Community Choice Aggregators and Load-Serving Entities:** Transmission timing mismatches with resource buildouts increase exposure to RA compliance costs and will force more expensive local procurement. - **Ratepayers:** These costs show up gradually but are real. Transmission is framed as cost avoidance via congestion relief, but near-term bills reflect layered infrastructure spend. Transmission is no longer a background constraint. It is becoming the primary determinant of where load can land and where generation can clear. ### MONDAY AGGREGATE: CPUC Scoping Memo Opens Fight Over PG&E Gas Cost Reallocation URL: https://www.calregulatory.com/monday-aggregate-cpuc-scoping-memo-opens-fight-over-pg-e-gas-cost-reallocation/ Last updated: 2026-04-07T01:51:07.000Z Today's briefing includes: - A scoping memo in the PG&E "CARD" proceeding; - An upcoming Aliso Canyon workshop; - SCE's wildfire cost recovery; - SCE's 2025 ERRA compliance; - PG&E's annual update on self-insurance programs; and - PG&E's climate-adaptation initiatives. --- ### PG&E NATURAL GAS RATES Commissioner **Christine Harada** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K030/604030125.PDF?ref=calregulatory.com) in [A.25-11-006](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050501.PDF?ref=calregulatory.com), establishing the framework for PG&E's proposed 2027–2030 gas cost-allocation and rate-design changes. For the first time, PG&E is combining its GCAP and GT&S cost-allocation and rate-design proposals into a single application. The ruling scopes 21 issue areas covering: - Rate forecasts; - Cost-allocation methodologies; - Storage procurement; - Backbone rate design; and - Customer class impacts. The primary dispute is PG&E's proposed shift from marginal to embedded cost allocation. This change reallocates recovery across customer classes as throughput declines, increasing pressure on noncore and large-volume users. Storage reliance on independent providers and Independent Storage Provider ownership concentration are also explicitly scoped. Intervenor testimony is due **July 16**; rebuttal is due **August 26**. **INSTANT ANALYSIS:** Consolidating the GCAP and GT&S CARD into one proceeding concentrates risk for all parties. Intervenors must now engage across distribution, transmission, and storage simultaneously. The embedded cost shift is a throughput-driven reallocation framed as a methodology update. Add ISP concentration and storage dependency, and this looks like a long-term restructuring of who bears PG&E's stranded gas infrastructure costs. --- ### ALISO CANYON WORKSHOP SoCalGas has scheduled a virtual Aliso Canyon Biennial Assessment Workshop for **April 15** (10:00 a.m. to 12:30 p.m.) in [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com), fulfilling a mandatory 90-day deadline under a 2024 decision ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)), not a strategic choice. At issue: Energy Division's [2025 Biennial Assessment recommends](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/2025%5Faliso%5Fcanyon%5Fbiennial%5Fassessment.pdf?ref=calregulatory.com) cutting Aliso Canyon's authorized inventory by 10 Bcf to **58.6 Bcf**. SoCalGas is contesting the pipeline deliverability inputs, receipt-point utilization, and storage withdrawal curves that produced that number. **INSTANT ANALYSIS:** SoCalGas isn't negotiating the size of the cut, it's attacking the analytical foundation that justifies any cut. April 15 is Round One. The downstream stakes are concrete: a 10 Bcf reduction triggers a corresponding cut to the Unbundled Storage Program, constraining noncore customer access to storage and increasing spot market exposure during peak events. If SoCalGas gains traction, Aliso Canyon remains a critical reliability asset through the late 2020s, a period in which the field's dispensability is conditioned entirely on infrastructure upgrades and demand declines that have not yet materialized. --- ### WILDFIRES Commissioner **Karen Douglas** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K941/603941306.PDF?ref=calregulatory.com) for SCE's [A.25-12-002](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800866.PDF?ref=calregulatory.com), where Edison seeks reasonableness findings on three buckets of wildfire mitigation and catastrophic event costs. The headline figure (**$47.7 million** in initial revenue requirement as of September 30, 2025) understates the underlying request. The actual pool under review is **$55.1 million** in O&M and **$77.9 million** in capital across: - Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account costs (primarily 2024 wildfire mitigation spending); - Catastrophic Event Memorandum Account sub-accounts tied to four named fire events (the [2017 Rye](https://en.wikipedia.org/wiki/Rye%5FFire?ref=calregulatory.com), [2018 Holiday](https://www.fire.ca.gov/incidents/2018/7/6/holiday-fire/?ref=calregulatory.com), [2020 Blue Ridge](https://www.fire.ca.gov/incidents/2020/10/26/blue-ridge-fire?ref=calregulatory.com), and [2021 French](https://en.wikipedia.org/wiki/French%5FFire%5F%282021%29?ref=calregulatory.com) fires); and - **$36.3 million** in 2022 capital denied in a 2025 decision ([D.25-06-051](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K383/571383364.PDF?ref=calregulatory.com)), recovery of which is contingent on a pending rehearing resolving in SCE's favor. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/rev.png) SCE's application also proposes a memorandum account to track jurisdictional cost shifts from [FERC Order 898](https://blog.protiviti.com/2024/10/01/understanding-ferc-order-898-implications-and-opportunities-for-public-utilities-and-licensees/?ref=calregulatory.com). Cal Advocates and TURN have protested the filing. Intervenor testimony is due **June 23**, with rebuttal testimony served by **July 17**. Opening briefs are due **August 31**, with reply briefs due **September 8**. **INSTANT ANALYSIS:** The $47.7 million revenue requirement is the rate impact number. The proceeding is actually about a much larger pool of O&M and capital costs and whether SCE retains the discretion to convert them into customer recovery over time. SCE already absorbed a $10 million shareholder haircut under the [Thomas Fire](https://en.wikipedia.org/wiki/Thomas%5FFire?ref=calregulatory.com) settlement before filing this. What remains is still contested, particularly the 2022 capital, which isn't a routine true-up but a second attempt at costs the Commission already declined to approve. If the rehearing fails, that piece falls away entirely. The FERC angle is small but worth tracking. As cost categories migrate between CPUC and FERC jurisdiction, who pays and on what timeline shifts with them. --- ### ERRA COMPLIANCE SCE filed its [2025 ERRA compliance application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K529/603529130.PDF?ref=calregulatory.com), seeking CPUC verification that its fuel and purchased power costs, contract administration, generation dispatch, and spot market transactions complied with its approved procurement plan for the January–December 2025 record period. Most balancing accounts are subject to after-the-fact audit rather than reasonableness review. SCE's fourteen memorandum accounts require explicit approval and carry a net **$11.531 million** undercollection that SCE wants transferred into rates. Bill impact is de minimis (about **$0.10/month** for a typical residential customer). Protests are due **May 6**. **INSTANT ANALYSIS:** SCE's request is small enough to discourage direct opposition, but the ERRA is where procurement behavior gets scrutinized and records get built. The real exposure is SCE's least-cost dispatch, gas procurement, GHG instrument strategy, and CAISO cost treatment, not the $11.5 million. If any of those get challenged successfully, this application moves from a mundane bookkeeping exercise to a prudence fight with downstream consequences. --- ### UTILITY SELF-INSURANCE PG&E's [Advice Letter 7880-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7880-E.pdf?ref=calregulatory.com) provides an annual update on wildfire and non-wildfire self-insurance programs, including prior-year activity and 2026 revenue requirements. Wildfire claims in 2025 totaled approximately **$50,000**, producing no change to the 2026 revenue requirement. The self-insurance fund (built primarily from CPUC ratepayers in 2023 and FERC transmission customers in 2024–2025) generated approximately **$40 million** in net investment income last year and is projected to reach **$1.036 billion** by year-end 2026\. PG&E also plans to refund about **$38 million** in excess FERC collections in December 2026. For non-wildfire liability, PG&E's hybrid insurance structure shifts Layer 2 coverage (**$75 million** to **$535 million**) to self-insurance. With zero recorded non-wildfire claims in 2025, PG&E proposes no 2026 revenue requirement adjustment while continuing to collect **$96 million** from CPUC customers to build toward a **$460 million** fund target. **INSTANT ANALYSIS:** PG&E's wildfire reserve is now in surplus. With negligible 2025 claims and a fund tracking above $1 billion, near-term rate pressure is absent; attention shifts to the $38 million FERC refund and how long excess balances persist before triggering return obligations. The non-wildfire program remains in buildout. Ratepayers are funding forward risk capacity against zero realized losses while PG&E accelerates accumulation toward the $460 million target. The deeper concern is capital governance. Large utility-controlled reserves are growing inside captive entities with limited oversight friction (this filing carries a Tier 2 designation requiring no CPUC resolution) while PG&E has self-directed a request to retain balances above $1 billion indefinitely. That is the issue worth watching: not today's rates, but tomorrow's refund, earnings treatment, and regulatory scrutiny once reserves substantially exceed modeled risk. --- ### CLIMATE ADAPTATION PG&E filed [Advice Letter 5193-G/7874-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5193-G.pdf?ref=calregulatory.com), its annual compliance update under a 2020 CPUC decision ([D.20-08-046](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K285/346285534.PDF?ref=calregulatory.com)), identifying the current composition and reporting structure of its Climate Resilience Team and summarizing activities from the past year. No new policy or cost recovery is proposed. Over the past year, PG&E advanced several workstreams: - Updated electric engineering design standards using climate projections; - Hourly climate load forecasting inputs drawn from the [State's Fifth Climate Assessment](https://lci.ca.gov/climate/docs/20260108-ClimateChangeAssessment-Factsheet.pdf?ref=calregulatory.com); and - Pilot projects embedding forward-looking climate data into asset failure and debris flow risk models. PG&E also participated in the CPUC's Climate Adaptation workshops and working groups throughout 2025 and is developing its 2027 Climate Adaptation Vulnerability Assessment under the updated framework established by a 2024 decision ([D.24-08-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M537/K988/537988980.PDF?ref=calregulatory.com)). **INSTANT ANALYSIS:** The load forecasting and asset risk model work is the thread to watch. Climate projections embedded now into planning inputs will surface later as demand forecast assumptions in General Rate Cases and risk justifications in wildfire mitigation cost narratives. The 2027 Climate Adaptation Vulnerability Assessment, shaped by D.24-08-005's revised methodology, is the vehicle through which those assumptions will acquire cost recovery rationale. This filing is the early administrative layer of that longer sequence. ### CAISO Draft LCR Report: LA Basin Capacity Is Getting More Expensive URL: https://www.calregulatory.com/wednesday-aggregate-20/ Last updated: 2026-04-09T05:21:49.000Z The CAISO's [Draft 2027 Local Capacity Technical Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K023/604023822.PDF?ref=calregulatory.com), filed April 3 in R.25-10-003, finds that total local capacity requirements in California will increase by approximately **602 MW** (2.6%) from 2026 to 2027, reaching **23,618 MW** across CAISO-defined local areas. The study follows the prior-year methodology: - 1-in-10 summer peak load forecast; - N-1/N-1-1/N-2 contingency criteria; and - [NERC](https://www.nerc.com/?ref=calregulatory.com)/[WECC](https://www.wecc.org/?ref=calregulatory.com) planning standards. Changes are locational, not uniform. LCR needs will decline in North Coast/North Bay, Big Creek/Ventura, Fresno, Stockton, Kern, and San Diego/Imperial Valley, driven by lower load forecasts, new transmission projects, and shifting contingency conditions. Needs will increase in Humboldt, Bay Area, Sierra, and the LA Basin. The Greater Bay Area carries the largest raw requirement (**8,315 MW**), but the LA Basin (at **6,823 MW**) has a more revealing story. Greater Fresno follows at **2,090 MW**. Several areas carry asterisked resource deficiencies, meaning load shedding is possible immediately following a first contingency at summer peak absent sufficient local procurement. --- R.25-10-003 · Draft 2027 LCT Report Local capacity requirements by area — 2026 vs. 2027 (MW) 2026 2027 Source: CAISO Draft 2027 Local Capacity Technical Report, filed April 3, 2026 · California Regulatory Intelligence Non-study estimates (no technical analysis conducted) show 2028 needs at **24,545 MW** and 2029 at **25,480 MW**, with the 2031 studied estimate reaching **26,271 MW**. --- R.25-10-003 · Draft 2027 LCT Report LCR trajectory by area, 2026–2031 (MW) — 2028/2029 estimated, no technical study conducted LA Basin Greater Bay Greater Fresno San Diego / Imperial Stockton Kern Source: CAISO Draft 2027 Local Capacity Technical Report, filed April 3, 2026 · California Regulatory Intelligence --- An [April 3 ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M604/K032/604032624.PDF?ref=calregulatory.com) grants the CAISO's motion to shift the draft LCR comment deadline from April 16 to **April 20**, with all subsequent milestones unchanged: the final LCR report is due **May 1**, comments **May 8**, reply comments **May 13**. ### **INSTANT ANALYSIS** The LA Basin's LCR increase is not primarily a load story. Re-rating of bulk transmission facilities is the driver, and unlike load forecasts, transmission ratings, once established, tend not to move. That makes this year's Basin requirement harder to reverse than the headline MW figure suggests, and raises the floor on procurement in that zone. The Basin is where constraint, siting difficulty, and transmission limits combine to create genuine capacity scarcity, the conditions that concentrate value and protect incumbents. New entrants there face permitting, siting, and interconnection barriers that existing resources don't. That gap is widening, not narrowing. The offsetting story is Stockton and Kern. New transmission is compressing local capacity value in both areas. That split widens through the 2028–2029 non-study estimates and shows no sign of closing. The resource deficiency designations are not academic. They mean a single contingency at summer peak can force load shedding if local procurement falls short. Those areas represent the CPUC's highest near-term reliability exposure and the clearest trigger for CAISO backstop procurement if LSEs underperform. Procedure-wise: **April 20** is the only opportunity to move the record. By May, it will be closed. ### **WHO IS MOST AFFECTED?** - **Load-serving entities/Community Choice Aggregators (LA Basin):** Procurement risk is rising in a zone where requirements are unlikely to reverse quickly, and thin or delayed procurement increases exposure to CAISO backstop capacity and unfavorable bilateral pricing. - **Existing in-basin generation (LA Basin):** Incumbents' position strengthens because requirements are rising for structural reasons (transmission re-ratings, not load drift) that are hard to undo, making capacity already sited in the Basin harder to substitute and supporting pricing power. - **Developers (new build/storage):** Location is the decision that matters most here: constrained load pockets will retain value while areas seeing transmission relief (Stockton, Kern) face compression, and interconnection timelines remain the binding constraint on new entry. - **Traders/capacity buyers:** Local area divergence is widening as the Basin tightens and transmission-relieved zones soften, which should produce more pronounced local price separation and fewer substitutes for Basin capacity. - **CPUC:** Resource deficiency designations across multiple areas mean a single contingency at summer peak can trigger load shedding, and if LSE procurement falls short, backstop costs will flow back to ratepayers through cost allocation. ### WEDNESDAY AGGREGATE: SoCalGas BTS 2026 — Capacity Scarcity and Price Risk Without an Exit URL: https://www.calregulatory.com/wednesday-aggregate-19/ Last updated: 2026-04-01T21:15:12.000Z Today's briefing is a microcosm of a gas system that is being redefined across infrastructure access and funding eligibility. SoCalGas is pushing more risk onto shippers competing for limited transport capacity, while the CPUC is narrowing the scope of ratepayer-funded gas innovation in PG&E’s RD&D program. The result is a more selective system: access leans on historical position, and future pathways (transport and technology) face higher bars for entry and cost recovery. --- ### BACKBONE TRANSPORTATION SERVICE On March 31, SoCalGas held a webinar on Backbone Transportation Service (BTS) for shippers and noncore customers in advance of the 2026 Open Season. BTS provides firm and interruptible access to the integrated SoCalGas and SDG&E natural gas transmission system. The Open Season is a three-step process (plus a re-contracting phase) through which eligible participants bid for that capacity, with different eligibility rules, bid types, and priority structures at each stage. - **Step 1** reserves set-aside capacity for core-related and legacy rights holders; - **Step 2** allows broader participation (noncore customers and marketers) with both baseload and monthly bids based on historical usage; and - **Step 3** opens remaining capacity to any creditworthy party, with contract terms ranging from 3 years, 1 month up to 20 years. Bidders cannot access years 4–20 if capacity is unavailable in years 1–3. Capacity awards are prorated when oversubscribed, with baseload bids prioritized over monthly bids, and are subject to system constraints and maintenance outages that can reduce available volumes or trigger reallocations. For 2026, SoCalGas is offering approximately **3,195 MMcfd** across major zones (Northern, Southern, Wheeler Ridge, Coastal, and Line 85), contingent on maintenance conditions. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/04/open-season.png) The Open Season timeline runs from **June 2026** through **September 2026**. Key structural changes this cycle include a one-time 37-month initial term to align future cycles to **November 1**, a return to Modified Fixed Variable rate design for BTS2, and the introduction of a new BTS5 volumetric option. After the auction, awarded capacity can be traded or reassigned via SoCalGas's Envoy platform, subject to a resale cap of 125% of the applicable G-BTS1/BTS2 reservation rate, with G-BTS5 resale capped at zero. Participants remain contractually obligated for awarded rights, rates float with future CPUC-approved tariff changes rather than locking in at award, and capacity generally cannot be returned prior to contract expiration. **INSTANT ANALYSIS**: SoCalGas is rebalancing access to constrained receipt points under tightening system conditions. Prorated awards, baseload priority, and maintenance-driven derates mean participants are competing for an increasingly uncertain slice of firm deliverability, especially in zones like Topock and the Southern system, where reductions are already embedded. Historical usage is doing more than setting bidding rights; it is increasingly dictating who can reliably secure capacity at all. The rate-design shifts and new BTS5 option add another layer. Moving BTS2 back to Modified Fixed Variable and introducing a volumetric pathway creates optionality, but also forces participants to make directional bets on load shape and utilization before the contract term begins. More consequentially, rates float with future CPUC decisions while capacity commitments are binding, meaning shippers absorb regulatory cost risk after they've locked in transport obligations they cannot exit. The zero-cent G-BTS5 resale cap compounds this: holders of volumetric capacity have no secondary market exit at all. --- ### NATURAL GAS RESEARCH PG&E resubmitted its [2024 and 2025 Gas Research, Development & Demonstration plans](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5181-G.pdf?ref=calregulatory.com) as directed by [Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K045/595045490.pdf?ref=calregulatory.com), which denied PG&E's original filings but preserved a path to approval. - The revised plans reduce the combined RD&D budget from $16.4 million to **$8.6 million**, including a steep cut in 2024 funding from approximately $8.1 million to **$1.9 million**. - Hydrogen-related research has been largely removed from the 2024 plan and eliminated entirely from the 2025 plan, citing unresolved guidance on ratepayer funding roles and potential duplication with ARCHES and hydrogen blending pilots. - The filing removes or narrows activities in emissions measurement, integrity management, and mandate-driven compliance work (Natural Gas Leak Abatement best practices, the [PHMSA Mega Rule](https://www.federalregister.gov/documents/2022/08/24/2022-17031/pipeline-safety-safety-of-gas-transmission-pipelines-repair-criteria-integrity-management?ref=calregulatory.com), CalGEM underground storage obligations). The Commission's position here is that ratepayer-funded research cannot claim benefit attribution for outcomes required by law. - Out-of-state projects have been removed from the 2025 plan except where affiliated with a federal laboratory. Consortia participation has been reclassified from RD&D expenditure to Program Administrative activity and placed within the applicable administrative cost cap. Benefit calculations have been strengthened using the EPIC Uniform Benefits framework, translating RD&D outputs into quantified, annualized ratepayer value. The initiative structure in the 2025 plan has been reorganized from six initiatives across two themes to three: - Innovative and Cost-Effective Integrity Management; - Advanced Leak Detection and Repair; and - Clean Fuels Integration **INSTANT ANALYSIS:** This filing is a capitulation document. The CPUC used Resolution G-3618 as more than a denial tool. It forced PG&E to self-apply eligibility standards the Commission had not fully codified — [even as PG&E sought rehearing of G-3618's retroactive denial of $7.2 million in 2023-2024 costs](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158474.PDF?ref=calregulatory.com). The hydrogen retreat is the most significant signal: PG&E couldn't secure Commission buy-in on the ratepayer funding rationale and stripped it rather than fight, reflecting a deeper unresolved question about hydrogen's role in the gas system that the CPUC has declined to answer. The budget math confirms the diagnosis. The 2024 cut is 76% while 2025 drops only 19%, meaning the 2024 plan was heavily loaded with exactly the categories that got stripped. The consortia reclassification looks like an accounting adjustment but limits how much PG&E can spend on industry coordination without eating into its administrative ceiling, a real operational constraint dressed as a compliance fix. --- ### BIOMETHANE Last week, [we reported on](https://www.calregulatory.com/parties-submit-opening-comments-on-cpucs-renewable-natural-gas-standard-pd/) parties' comments addressing a proposed decision that restructures the [Renewable Gas Standard](https://www.socalgas.com/newsroom/press-release/socalgas-applauds-establishment-of-first-renewable-gas-standard-in-the-united-state?ref=calregulatory.com) (which is on the agenda for the Commission's [**April 9** voting meeting](https://www.calregulatory.com/puc-april-9-voting-preview-new-rulemaking-forces-a-decision-on-who-pays-for-large-load/)). Since our briefing, multiple other parties' comments have surfaced in the CPUC's document feed. Our post [has been updated](https://www.calregulatory.com/parties-submit-opening-comments-on-cpucs-renewable-natural-gas-standard-pd/) accordingly. Note also that parties' reply comments are being filed today (**April 1**). ### PCIA Reset Incoming: Track 3 Opens the Door to Repricing Cost Responsibility URL: https://www.calregulatory.com/pcia-reset-incoming-track-3-opens-the-door-to-repricing-cost-responsibility/ Last updated: 2026-04-01T16:27:24.000Z ### EXECUTIVE SUMMARY Track 3 of [R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com) is shaping up to be the most consequential [PCIA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) proceeding since the CPUC's 2017 overhaul, with parties filing divergent comments on scope, sequencing, and data access. - The Joint Utilities (PG&E, SCE, and SDG&E) want fast and specific benchmark fixes; - CalCCA wants a full reset, gated behind a data-access protocol; and - TURN filed the most technically specific comments, targeting a broken RPS Market Price Benchmark and the lack of monthly granularity (issues with cost-recovery implications well beyond this proceeding). How the CPUC sequences these competing demands will determine whether Track 3 produces narrow rate stabilization outcomes by 2028 or a multi-year redesign of the fundamental cost-sharing bargain between bundled and departed load. --- **What Happened and When:** In February, the CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960141.PDF?ref=calregulatory.com) in the Energy Resource Recovery Account and Power Charge Indifference Adjustment reform rulemaking ([R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com)). The ruling directed the investor-owned utilities (and invited other parties) to file comments on the scope of Track 3. Parties were asked to identify scope, prioritization, data constraints, and timing. This is the phase where broader policy questions (deferred in earlier tracks) will be resolved. On March 27, parties submitted their comments. ### PARTIES' POSITIONS - The Joint Utilities [want to split Track 3 into two phases](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K533/603533523.PDF?ref=calregulatory.com): a fast track to fix the most volatile benchmark calculations now, and a slower track to tackle deeper structural questions, including whether negative PCIA charges should be returned to customers. They point to more than **$4 billion** in cumulative billing shortfalls for SCE customers alone to justify moving quickly on the first phase. - CalCCA [wants to reopen the entire cost-sharing framework from the ground up ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K478/603478676.PDF?ref=calregulatory.com)(including alternatives such as changes to cost allocation, financing mechanisms, and long-term PCIA design). Before any of that work begins, CalCCA wants a formal data-sharing protocol established so CCA representatives can access the utility portfolio data needed to evaluate proposals. This would be modeled on a process from the 2017 PCIA proceeding, with at least six months of analysis time after data is received. - TURN [focuses on two specific fixes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K478/603478672.PDF?ref=calregulatory.com): reforming the RPS Market Price Benchmark to include long-term fixed price contracts currently excluded from the calculation, and developing monthly rather than annual MPB values. The RPS MPB has risen nearly **500%** since 2022 due to reliance on a thin slice of short-term transactions, producing benchmark values that imply long-term contracts have zero or negative energy and Resource Adequacy value (a result TURN characterizes as illogical). - The Alliance for Retail Energy Markets and Direct Access Customer Coalition [support a broad reform scope](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K529/603529076.PDF?ref=calregulatory.com) and propose spreading large accumulated billing imbalances (which have reached **$2.2 billion** for PG&E alone) over 18 to 24 months rather than recovering them in a single year. - The California Large Energy Consumers Association [pushes for a careful, no-regrets schedule](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K483/603483121.PDF?ref=calregulatory.com) through mid-2027, prioritizing rate affordability, indifference across bundled and unbundled customers, and alignment with [Slice-of-Day RA ](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/resource-adequacy-compliance-materials/guides-and-resources/2025-ra-slice-of-day-filing-guide.pdf?ref=calregulatory.com)implementation. ### **INSTANT ANALYSIS** Track 3 is where parties are positioning to reset the cost-sharing bargain between bundled and departed load. - The utilities want targeted fixes that stabilize benchmarks before the broader framework hardens. CalCCA wants to reopen the design before those fixes become precedent. - The data-access dispute is the procedural lever. If the Commission adopts CalCCA’s sequencing, Track 3 becomes a multi-year redesign. If it follows the utility path, benchmark changes will flow into 2028 rates while deeper reforms slip. - TURN’s monthly MPB argument is the sleeper issue. The Diablo Canyon proceeding showed that annual averaging distorts cost recovery when expenses are time-skewed. That logic extends across ERRA and General Rate Case proceedings. This is not a niche fix: it is a potential rewrite of how timing mismatches are priced. ### Cost-Recovery Battle Begins for SB 1221: Rate Base, Regulatory Assets, or No Recovery at All? URL: https://www.calregulatory.com/cost-recovery-battle-begins-for-sb-1221-rate-base-regulatory-assets-or-no-recovery-at-all/ Last updated: 2026-04-01T12:00:19.000Z ### EXECUTIVE SUMMARY [Senate Bill 1221](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB1221&ref=calregulatory.com) has moved into a cost-recovery decision: whether pilots are treated as infrastructure or customer programs. Utilities are seeking near-parity with traditional gas investment economics, while other parties are trying to limit recovery or confine costs to participating customers. The CPUC's handling of this matter will determine whether pilots scale as a system-level transition tool or remain targeted, customer-funded projects. --- **WHAT HAPPENED AND WHEN:** On March 27, parties responded to [a CPUC ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K365/602365926.PDF?ref=calregulatory.com) that turns SB 1221 into a cost-recovery decision: who pays, how fast, and whether utilities earn on electrification. At issue is the tug of war between Public Utilities Code §663(b)(8), which prohibits a rate of return on Behind-the-Meter costs, and §663(b)(9), which requires the CPUC to set a rate of return and recovery period for zero-emission alternatives. The ruling frames three options: - **Option 1:** debt-cost carrying charge only; - **Option 2:** regulatory asset with reduced return; and - **Option 3:** debt recovery plus performance-based upside. Each encodes a different answer to the threshold question: whether SB 1221 pilots behave like infrastructure or customer programs. ### **PARTY POSITIONS** Utilities converge on one point: pilots won't scale unless they have financial symmetry with traditional gas investments. - PG&E [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K465/603465634.PDF?ref=calregulatory.com) for full authorized [Weighted Average Cost of Capital](https://www.investopedia.com/terms/w/wacc.asp?ref=calregulatory.com) (WACC) on regulatory assets (not a reduced rate), distinguishing regulatory asset treatment from capitalization while insisting the return level should be identical. - SCE [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K478/603478661.PDF?ref=calregulatory.com) full cost recovery, including time value of money but declines to endorse any of the ruling's three options. - SoCalGas/SDG&E [reject](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K466/603466588.PDF?ref=calregulatory.com) all three options as inadequate, arguing amortized investments should receive full WACC, and invoke the **July 1, 2026** statutory deadline to reinforce the need for workable rules fast. The most important split in the record is not utilities vs. advocates, but *within* the advocates. TURN [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K533/603533522.PDF?ref=calregulatory.com) that BTM costs should be amortized O&M expenses with carrying costs capped at the commercial paper rate. It opposes regulatory asset treatment as a prohibited return by another name, and argues that Options 2 and 3 both introduce an equity return component that §663(b)(8) forecloses. Sierra Club and the Natural Resources Defense Council [are closer to the utility position](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473633.PDF?ref=calregulatory.com): they propose a hybrid of Options 2 and 3 and explicitly state they would accept full WACC recovery as an alternative. Their data shows regulatory asset treatment over 10 years reduces Year 1 bill impacts by more than twelvefold versus immediate expense treatment. The Indicated Shippers [argue](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K529/603529072.PDF?ref=calregulatory.com) that BTM costs should not be recovered from ratepayers at all, through any mechanism, and instead should be borne by participating customers or non-ratepayer sources. Their position rests on cost-causation principles and §451's just and reasonable standard. The Shippers advance on-bill financing and the recently authorized Tariff On-Bill pilot (via [D.25-12-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K314/592314779.PDF?ref=calregulatory.com)) as the preferred alternative, keeping repayment responsibility with the benefitting customer. They also warn that socializing BTM costs would exacerbate affordability pressures for remaining customers and accelerate gas system contraction. If adopted broadly, their approach would confine SB 1221 to customer-funded pilots rather than system-level transition. The Coalition of California Utility Employees [reinforces](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K529/603529073.PDF?ref=calregulatory.com) this with legislative history: §663(b)(8) was added on April 25, 2024 specifically to prohibit BTM costs from receiving capital asset recovery, limiting the rate-of-return authority §663(b)(9) would otherwise provide. ### **UNRESOLVED DESIGN QUESTIONS** Three questions are decisive. - First, classification: system-level investment or customer-specific expenditure. - Second, timing: expense now or amortize over time. - Third, return: positions range from no ratepayer recovery (Shippers), to commercial paper rate (TURN), to midpoint debt/WACC (Sierra Club/NRDC), to full WACC (PG&E, SoCalGas/SDG&E). These choices cascade, and Option 3’s contingent shareholder incentive cuts across all three, making it the most consequential unresolved question in the record. ### **INSTANT ANALYSIS** - The utility coalition is more unified and more assertive than anything else in the record. PG&E and SoCalGas/SDG&E are asking for full WACC on regulatory assets (near-identical financial footing with traditional gas capex). That almost certainly exceeds what the CPUC will authorize, but it sets the ceiling. - Sierra Club and NRDC's willingness to accept full WACC recovery, combined with their quantitative case against expense treatment, gives the CPUC environmental cover to authorize a meaningful return on BTM regulatory assets. TURN and the Indicated Shippers will challenge that outcome aggressively, in reply comments and in whatever comes next. - Option 3 deserves more attention than it has received. The ALJ invested significant design work in that construct (debt-cost floor plus performance upside tied to demonstrated avoided costs). Whether a contingent shareholder incentive constitutes the "rate of return" §663(b)(8) prohibits is genuinely unsettled, and how the CPUC resolves it will have implications beyond this proceeding. The probable landing zone: regulatory asset treatment with a return below full WACC, likely Option 2 range, possibly with an Option 3 overlay. That caps utility earnings, which means participation skews toward projects with strong avoided-cost economics. The practical implication is selective rollout, not systemwide acceleration, unless the performance incentive proves robust enough to shift utility calculus on marginal projects. ### CPUC April 9 Voting Preview: New Rulemaking Forces a Decision on Who Pays for Large Load URL: https://www.calregulatory.com/puc-april-9-voting-preview-new-rulemaking-forces-a-decision-on-who-pays-for-large-load/ Last updated: 2026-03-31T21:22:04.000Z The CPUC published the [agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K615/603615276.pdf?ref=calregulatory.com) for its **April 9** business meeting. Items that are up for consideration include: - A major new rulemaking on electric rate design; - Utility remediation plans that address problems in their [Integration Capacity Analysis](https://www.calregulatory.com/r/34db80bc?m=bb484012-a69a-425c-839a-750c0bd64e46) tools; - Modification of the Renewable Gas Standard program; - PG&E's arrangement with [Citizens Energy Corporation](https://citizensenergy.com/?ref=calregulatory.com) for transmission entitlements; and - ERRA compliance findings for SDG&E and SCE. This agenda reflects a Commission increasingly focused on cost control, data accountability, and who ultimately bears system costs across rate design, procurement, and infrastructure investment. We will provide same-day coverage of the meeting's results next week. --- ### ELECTRIC RATE DESIGN The Commission is expected to launch a new rulemaking on advanced electric rate design. The focus is on cost causation, affordability, and clearer price signals for grid use, covering both residential and non-residential rate structures. - The proceeding carries forward unresolved issues from the Demand Flexibility rulemaking, including the Base Services Charge, dynamic rates, and electrification incentives. It also implements two new statutory requirements: a data-center cost impact assessment due to the Legislature by **January 1, 2027**, and an exemption from non-bypassable charges for certain industrial customers using process heat recovery technology ([Assembly Bill 2109](https://legiscan.com/CA/text/AB2109/id/2915472?ref=calregulatory.com)). - A [proposed consultant scope](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K838/603838663.pdf?ref=calregulatory.com) expands E3's existing public rate-design modeling tool and adds a new toolkit for large non-residential customers. Parties will be able to model bill impacts under different rate structures, including Time-of-Use periods, demand charges, and major cost drivers like transmission and wildfire costs. - An [Income Verification Process Working Group report](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M603/K849/603849545.pdf?ref=calregulatory.com) addresses one specific question: how to subdivide the current undifferentiated Tier 3 (all non-CARE, non-FERA customers) into separate moderate- and high-income tiers. The near-term framework uses American Community Survey census tract median income data for initial classification. A customer-initiated appeals process, administered by a third-party vendor using tax transcripts and income documents, handles exceptions. Classifications refresh on a five-year cycle. - The long-term direction points toward Franchise Tax Board tax data, but that requires legislative authorization that does not currently exist. The report is a consultant synthesis, not a consensus document. Advocate statements from TURN, Cal Advocates, Sierra Club, and others reflect significant remaining disagreement on methodology, cost, and accuracy tradeoffs. **INSTANT ANALYSIS:** This new OIR is a major reset. The CPUC is pulling unresolved issues from multiple proceedings into one venue, with affordability, electrification, and large-load growth now colliding in a single docket. Standardized tools will compress disputes on inputs. That pushes fights toward methodology, cost-allocation assumptions, and who controls the analytical frame. Two areas merit close attention. - First, income-based charges depend on a verification framework that carries real cost and misclassification risk. - Second, large-load treatment, especially data centers, sets up a direct allocation battle over who carries system costs. The [Senate Bill 57](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB57&ref=calregulatory.com) mandate frames that conflict explicitly around stranded costs and cost-shifting. The outcome of this proceeding will shape rate structure and whether new load is treated as a benefit or a burden. Interconnection economics are a natural downstream consequence, though not a stated scope item in this order. --- ### INTEGRATION CAPACITY ANALYSIS [Draft Resolution E-5440](https://www.calregulatory.com/r/a4aa5e58?m=bb484012-a69a-425c-839a-750c0bd64e46) approves, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their [Integration Capacity Analysis](https://www.calregulatory.com/r/34db80bc?m=bb484012-a69a-425c-839a-750c0bd64e46) tools. These tools estimate how much distributed energy can be added to the grid without upgrades. The draft resolution requires the utilities to correct data errors, reactivate inactive circuits on maps, improve the timeliness of map updates, and expand reporting so stakeholders can track when Integration Capacity Analysis results diverge from real interconnection outcomes. - It also establishes a formal concordance/discordance framework that categorizes interconnection and energization applications into one of four scenarios based on whether the ICA map value and the actual engineering outcome aligned. In so doing, it creates, for the first time, a structured taxonomy for measuring ICA usefulness across all three major electric utilities. - The draft resolution orders SDG&E to stop excessive redactions of generation data, directs all utilities to publish more complete system information (including substations up to the transmission level) on public planning portals, and establishes new metrics to measure whether Integration Capacity Analysis outputs align with actual engineering results. - The draft resolution codifies new definitions, distinguishing "ICA accuracy" (whether the utility correctly followed the approved methodology) from "ICA alignment" (whether ICA results match real-world engineering outcomes). **INSTANT ANALYSIS:** This draft resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. The draft resolution finds SDG&E explicitly out of compliance on redaction practices, reinforcing that these are enforceable obligations. For developers, DER providers, and large load customers, the main takeaway is that Integration Capacity Analysis outputs will become more auditable over the next six to 12 months as the new tracking and reporting requirements take effect. Utilities facing concordance scrutiny now have the incentive to understate available capacity. --- ### BIOMETHANE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846485.PDF?ref=calregulatory.com) modifies the CPUC's Renewable Gas Standard program created under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com) to modify biomethane procurement requirements for California's gas utilities. The PD concludes that the procurement framework adopted in a 2022 decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)) would impose excessive above-market costs on ratepayers given the early-stage biomethane market and limited feedstock supply. - To address this, the PD adopts a Cost Containment Mechanism that caps average program rate impacts at **1%** of each utility's bundled core customer revenue requirement with a maximum **3%** year-over-year increase. The Cost Containment Mechanism is the controlling constraint; the CPUC will not approve contracts that would cause rates to exceed it. - The PD also reduces the overall biomethane procurement target from 72.8 billion cubic feet annually to **36.4 billion cubic feet** and extends the compliance timeline from 2030 to 2035\. The prior short-term/medium-term structure is eliminated in favor of a single 2035 deadline. The Diverted Organic Waste procurement goal of 17.6 Bcf remains unchanged, tied to California's [Senate Bill 1383](https://www.wm.com/us/en/sb1383?ref=calregulatory.com) methane-reduction policy. - The PD opens all feedstocks to bid into utility solicitations while maintaining the dedicated Diverted Organic Waste target and directs utilities to revise their Renewable Gas Procurement Plans via Tier 2 Advice Letters. The 4% livestock biomethane procurement limit is retained. The PD removes the previous 2040 delivery cutoff so contracts can extend beyond that date, retains the [M-RETS](https://ww2.arb.ca.gov/sites/default/files/2020-10/101520presentation%5Fm-rets.pdf?ref=calregulatory.com) tracking system, and establishes an 80/10/10 Renewable Thermal Certificate unbundling framework: 80% of biomethane by volume stays bundled with Renewable Thermal Certificate retired by the utility; 10% allows the developer to retain the RTC; 10% allows the utility to market it. Unbundled volumes purchased at market rate do not count against the Cost Containment Mechanism. **INSTANT ANALYSIS:** The CPUC is walking back the scale of the Renewable Gas Standard after early procurement revealed high costs and limited biomethane supply. The PD cuts the overall target in half while preserving the full Diverted Organic Waste target, pushes the deadline to 2035, and imposes a strict Cost Containment Mechanism that halts procurement if program costs exceed a 1% average rate impact measured against each utility's bundled core customer revenue requirement. If the PD is adopted, RNG procurement will continue, but under strict affordability constraints. The program would shift from an aggressive decarbonization mandate to a controlled, ratepayer-limited market experiment. The 80/10/10 Renewable Thermal Certificate unbundling framework is a novel structure worth watching; if it demonstrates cost savings, expect expansion in future proceedings. In short, the CPUC is capping ambition because the economics failed early. --- ### TRANSMISSION PROJECTS A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K795/601795585.PDF?ref=calregulatory.com) in [A.24-03-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M527/K221/527221490.PDF?ref=calregulatory.com) allows PG&E to enter into a long-term investment arrangement with [Citizens Energy Corporation](https://citizensenergy.com/?ref=calregulatory.com), under which Citizens could lease partial transmission entitlements in future PG&E transmission projects. The proposal stems from a "Development, Coordination, and Option Agreement" executed in 2024 (and amended in 2025), allowing PG&E to offer Citizens up to five investment tranches totaling as much as **$1 billion** in transmission projects. For each tranche, Citizens could acquire up to **49.9%** of the transmission entitlement rights through a 30-year lease, paying PG&E a lump-sum “prepaid rent” based on the project’s capital cost share. PG&E would still develop, construct, own, operate, and maintain the transmission assets, while Citizens would receive a share of transmission revenues through the CAISO’s High-Voltage Transmission Access Charge system. **INSTANT ANALYSIS:** The CPUC does not fully approve PG&E's $1 billion Citizens Energy transmission financing program but allows the framework to proceed through a closely supervised, tranche-by-tranche process. Stated differently: third-party capital is being allowed in but is not yet trusted. The PD applies a heightened "public interest" standard and extensive reporting requirements, which reflect concern about undefined projects, potential rate impacts, and ratepayer-assistance accountability. --- ### ERRA COMPLIANCE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) approves (with modifications) SDG&E's 2023 Energy Resource Recovery Account compliance application, finding that the utility’s power procurement, contract administration, dispatch decisions, and related accounting were largely prudent and consistent with CPUC-approved plans. The PD adopts several negotiated changes, including revising the valuation of retained Resource Adequacy capacity, correcting the accounting of Renewable Energy Certificates for Renewable Portfolio Standard compliance, and reallocating certain battery storage revenues to a broader customer base. The PD also determines that SDG&E recorded a net undercollection of about **$214.6 million** across its procurement-related balancing accounts (excluding confidential subaccounts) and allows recovery of those costs through established mechanisms. --- Separately, [another PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846486.PDF?ref=calregulatory.com) approves SCE's 2023 Energy Resource Recovery Account compliance application. The PD determines that SCE prudently managed its utility-owned generation resources, administered energy contracts appropriately, and recorded costs in ERRA and related balancing and memorandum accounts accurately. As a result of account balances across several regulatory accounts, the PD directs SCE to reduce its revenue requirement by **$63.195 million** through a rate decrease and to return **$70,811** in unrealized revenues associated with four 2023 Public Safety Power Shutoff events. The key takeaway is what did not happen. The PD declines to escalate oversight of SCE's procurement despite pressure from Cal Advocates. For utilities and counterparties, this preserves (for now) the current ERRA framework as a retrospective accounting review, not a venue for expanding procurement enforcement. **INSTANT ANALYSIS**: These two PDs reinforce the Commission’s continued willingness to true-up procurement costs with limited disallowance risk, while using the ERRA forum to impose targeted accounting and allocation corrections rather than broad prudence challenges. SCE emerges with a straightforward compliance finding and a modest $63.2 million rate decrease tied to overcollection, while SDG&E's filing is approved with modifications that adjust Resource Adequacy valuation, RPS accounting, and battery storage revenue allocation, ultimately preserving cost recovery but redistributing impacts across customer classes. The PDs telegraph that the Commission is leaning into granular portfolio accounting scrutiny (RA, RPS, storage revenues, affiliate transfers) while avoiding disruptive second-guessing of procurement decisions under the reasonable manager standard. That keeps procurement risk relatively contained for investor-owned utilities, but expands exposure on how value streams are classified and allocated, particularly as storage, RA attributes, and program costs become more complex. For market participants, these actions suggest a process where cost recovery remains reliable, but margin and cost-allocation outcomes are shaped in compliance proceedings rather than forecasts or procurement approvals. ### MONDAY AGGREGATE: Edison's AMI 2.0 Program; an SPD-37 Fight; and PG&E's Diablo Canyon Year 3 Filing URL: https://www.calregulatory.com/monday-aggregate-edisons-ami-2-0-program-an-spd-37-fight-and-pg-es-diablo-canyon-year-3-filing/ Last updated: 2026-03-30T23:59:53.000Z Today's briefing covers: - SCE's application to deploy its AMI 2.0 program; - More conflict under Resolution SPD-37's requirements; - PG&E's third annual Diablo Canyon extended operations application; - A CPUC ruling on 2026 RPS Procurement Plans; and - Valuation methodologies for Pre-2019 Banked RECs. --- ### ADVANCED METERING INFRASTRUCTURE SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473599.PDF?ref=calregulatory.com) to deploy its AMI 2.0 program, driven by the looming obsolescence of its existing smart meters, which will lose vendor support by 2035. - Failure rates are rising across SCE's fleet of approximately 5.7 million meters. The sole replacement vendor isn't committed beyond 2029, the proprietary 1.0 network can't support a hybrid mix of old and new meters, and each year of delay past 2029 adds approximately **$140 million** in nominal costs deploying meters that will be stranded anyway. - SCE evaluated four replacement approaches and selected a "value upgrade" — next-generation meters with edge computing, an IP-based mesh/cellular/satellite network on open standards, and software for demand flexibility, fault detection, and granular usage analytics, claiming an incremental benefit-cost ratio of **7.56** versus baseline replacement. - A mass installation would run from 2029–2033, preceded by deployment readiness and small-scale field validation in late 2028\. SCE's total requested revenue requirement is **$1,865 million** over 2026–2033, with an average bundled rate impact of about **2.5%**. SCE proposes a 110% reasonableness threshold on **$444.6 million** in capitalized software costs, with tiered recovery mechanisms for overruns. The day after filing, SCE [moved to establish a memorandum account](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K478/603478669.PDF?ref=calregulatory.com) to track O&M and capital costs for deployment readiness that are incurred before a final decision (proposed for September 2027). Recovery is not automatic; recorded amounts transfer to a balancing account only upon final decision and are subject to reasonableness review. Critical context: the CPUC denied SCE a similar memorandum account in a 2025 General Rate Case decision ([D.25-09-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M580/K788/580788967.PDF?ref=calregulatory.com)). SCE is reframing its request around deployment costs rather than planning costs. **INSTANT ANALYSIS:** SCE is moving ahead of a 2027 decision and wants cost protection now. The memorandum account is the key: approximately 18 months of pre-decision spend after a prior GRC denial on essentially the same mechanism. The real conflict is scope. SCE is turning a meter replacement into a grid-edge platform with demand control, fault detection, and DER integration. The 110% software cost threshold and the 7.56 BCR will draw heavy intervenor scrutiny. --- ### UNDERGROUNDING PROJECTS The Joint IOUs (PG&E, SCE, and SDG&E) [responded](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473510.PDF?ref=calregulatory.com) to protests of their application to establish a standardized Benefit-Cost Ratio methodology, audit process, and cost-recovery framework for undergrounding projects under [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com). (*See CRI's coverage of the application* [*here*](https://www.calregulatory.com/ious-respond-to-resolution-spd-37-with-a-unified-playbook-for-senate-bill-884-cost-recovery/)*.*) [IOUs Submit Joint Playbook for Senate Bill 884 Cost RecoveryThe filing is a response to Resolution SPD-37.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-69.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-10-2026--5--1.png)](https://www.calregulatory.com/ious-respond-to-resolution-spd-37-with-a-unified-playbook-for-senate-bill-884-cost-recovery/) The IOUs defend their methodology as compliant with the CPUC's [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com) due to its use of risk-averse scaling, a preferred discount rate alongside the three required rates, and an uncertainty factor to address modeling limitations. The utilities propose moving O&M savings into the Benefit-Cost Ratio denominator as a cost offset and including broad enterprise risk-reduction benefits in the numerator, arguing the Risk-Based Decision-Making Framework requires reflecting the full set of benefits from incurred costs. The utilities oppose intervenor attempts to expand the scope beyond SPD-37 requirements, calling Cal Advocates' proposed evaluation criteria vague and EPUC's five proposed issues redundant. On auditing, the utilities argue that portfolio-level compliance is sufficient and oppose project-level auditing of risk-reduction benefits as infeasible (those values are counterfactual estimates, not observable outcomes). The utilities also seek to grandfather previously-scoped in-flight projects into the Expedited Undergrounding Plan even where updated risk models no longer support them, and defend the 2% variance threshold by noting the Commission approved 15% variance for PG&E system hardening in the 2020 General Rate Case. **INSTANT ANALYSIS:** The utilities are keeping this application in a policy lane, not a cost-adjudication lane, preserving flexibility and limiting near-term ratepayer scrutiny. On substance, they're anchoring to the Risk-Based Decision-Making Framework as cover while preserving discretion inside it. Risk scaling, uncertainty bands, portfolio-level judgment, and the previously-scoped projects carve-out all point to the same outcome: the IOUs maintain the ability to justify undergrounding even when Benefit-Cost Ratio signals are marginal. Moving O&M savings into the denominator and loading broad enterprise risk benefits into the numerator expands the universe of "cost-effective" projects without changing the headline metric. Portfolio-level auditing with no project-level compliance requirement means the accountability regime is as flexible as the methodology itself. Intervenors are asking "are these projects actually worth it?" but utilities are saying "does the methodology follow the rules we were given?" --- ### DIABLO CANYON PG&E's [third annual Diablo Canyon extended operations application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473512.PDF?ref=calregulatory.com) seeks **$595 million** in net revenue requirement for 2027\. Total forecast costs are **$1.34 billion**, offset by **$751 million** in CAISO market revenues (down from prior years while operational costs held flat). The statewide non-bypassable charge allocates **$340 million** to PG&E, **$208 million** to SCE, and **$47 million** to SDG&E. The system average bundled rate impact is 0.4%. Monthly residential bill increases are: $1.08 (PG&E); $0.65 (SCE); and $0.26 (SDG&E). The plant ran well in 2025, with an 89.7% capacity factor across a double refueling outage year. PG&E values the statewide Resource Adequacy contribution at about **$276 million** and projects 34.5 million metric tons of avoided emissions through 2030. On the Volumetric Performance Fee side, PG&E collected **$178.4 million** in 2025 and spent **$144 million**. Two VPF-funded programs blew their forecasts: - A major back-office technology overhaul (migrating PG&E's work management systems to a new platform) landed at $32.3 million against a $10 to $15 million range; and - Incremental grid safety spending (aerial inspections and emergency outage response above what the GRC funds) hit $64.5 million against $40 to $60 million. Neither variance triggered any consequence under the current framework. **INSTANT ANALYSIS:** The declining CAISO revenue trend is the number to watch. Operational costs aren't rising meaningfully: revenues are falling, and the difference lands directly on the non-bypassable charge. Bill impacts look modest in isolation but the charge is fully non-bypassable across all load, cumulative through 2030, and indexed to a market revenue forecast that keeps missing. --- ### RENEWABLE PORTFOLIO STANDARD The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K483/603483112.PDF?ref=calregulatory.com) directing all retail sellers to file standardized 2026 RPS Procurement Plans by **June 12**. Cornerstone RPS requirements remain: - Sellers must demonstrate progress toward 60% RPS by 2030 and 100% zero-carbon by 2045, with at least 65% of RPS procurement from contracts of 10+ years; and - Planning horizons extend through 2036. Every retail seller must provide renewable net short calculations, risk assessments with severity ratings and mitigation timelines, Minimum Margin of Procurement methodology, bid solicitation protocols including Least-Cost Best Fit criteria, cost quantification using standardized templates, and transportation electrification forecasts. Community Choice Aggregators and Electric Service Providers face the same reporting depth as investor-owned utilities, including cost data the CPUC uses for its [annual Padilla Report](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/office-of-governmental-affairs-division/reports/2025/2025-padilla-report%5Ffinal%5Fapproved.pdf?ref=calregulatory.com) to the Legislature. The ruling explicitly states that incomplete plans will be rejected, and non-compliant sellers may face fines. A notable new element is a table that requires retail sellers to cross-reference their RPS Plans against their individual Integrated Resource Plans due August 10\. This creates a direct accountability link between the two proceedings. For large IOUs only, the ruling requires their plans to include detailed [Senate Bill 1174](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202120220SB1174&ref=calregulatory.com) transmission and interconnection delay reporting e.g., project-level delay reasons, median delay times, dependent renewable/storage capacity at risk, permitting reform analysis, and mitigation efforts. Drafts are due **June 12**, with comments due **July 13**. **INSTANT ANALYSIS:** The CPUC is building a comparison engine. Standardized inputs, uniform templates, and the new IRP cross-referencing table mean every retail seller's procurement position, risk exposure, and cost structure will sit side by side. The 65% long-term contracting rule is key: sellers with short-term-heavy portfolios will have their gaps quantified and visible. The SB 1174 transmission reporting will expose exactly where and why utility interconnection delays are holding up renewable and storage capacity. [D.26-02-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K777/601777006.PDF?ref=calregulatory.com)'s directives (supplemental procurement) also show up in the IRP alignment table. --- ### ERRA/PCIA REFORM The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K533/603533506.PDF?ref=calregulatory.com) to introduce an Energy Division staff report. The report proposes four valuation methodologies for Pre-2019 Banked Renewable Energy Credits for use in calculating the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com). Parties must comment on the report alongside opening briefs by **May 22**, with reply briefs due **June 5**. The Commission is asking: - Whether staff accurately characterized positions and precedent; - Which methodology best captures REC value; - What modifications are warranted, and; - Whether a non-zero valuation creates problems for RPS compliance and LSE procurement (including whether compliance deferrals could mitigate those concerns). **INSTANT ANALYSIS:** This is a high-impact PCIA decision. How the Commission values these banked RECs directly affects the indifference calculation and, by extension, exit fees for departing load. Investor-owned utilities will likely argue that legacy procurement carries real value that should be reflected. Community Choice Aggregators and Electric Service Providers will argue it's a sunk cost that inflates the PCIA. The Commission's explicit focus on RPS compliance and procurement knock-on effects indicates awareness that getting the valuation wrong could distort market behavior beyond just cost allocation. ### CRI Seeks a Utility Partner — DOE Deadline April 9 URL: https://www.calregulatory.com/cri-seeks-a-utility-partner-doe-deadline-april-9/ Last updated: 2026-03-29T05:20:49.000Z CRI is seeking a load-serving entity to sign a Letter of Support for a Department of Energy grid cybersecurity project, i.e. the "[Digitizing Utilities Prize](https://www.herox.com/DigitizingUtilitiesPrizeRound3?ref=calregulatory.com)," which is focused on improving how utilities use data, manage risk, and integrate distributed resources. The deadline is **April 9.** We are partnering with a startup called **ZSub** on [a self-sovereign cryptographic mesh protocol (SSCM) for secure grid communications and federated data infrastructure](https://zsubmesh.net/doe/zsub-doe-onepager.html?ref=calregulatory.com). **In basic terms:** this is a security layer that enables coordination across utilities without exposing raw data. DOE requires us to have the letter of support to participate. (Note: this is **not** a funding commitment, just an expression of interest to explore a pilot with us.) The letter can be from any of the following entities. - Rural electric cooperatives - Utilities owned by a political subdivision of a state, such as a municipally owned electric utility - Utilities owned by any agency, authority, corporation, or instrumentality of one or more political subdivisions of a state - Investor-owned electric utilities - Regional transmission operators/independent system operators - Electric aggregators - Electric wire owning and/or operating entities. ## CRI’s readership includes many of you operating in these environments. If this is a potential fit, [please reach out directly](https://www.calregulatory.com/contact-us/) Our team for this project includes: - **Luke Arno** – 27 years building distributed systems and secure platforms across infrastructure startups; - **Sam Larson** –DOJ antitrust background, plus 15 years in fintech and data; - **Parker Mooney** –distributed computing infrastructure specialist; and - **Michael Cade** –founder of CRI and regulatory analyst for large commercial and industrial energy users in California. --- ### DOE Contest Details The DOE is inviting utilities and energy sector partners to work with software developers, data experts, and scientists to improve digital systems, data analytics, and risk-informed resource integration. This includes building systems for data processing, quality assurance, storage, and deletion. Selected solutions may be shared across the sector as examples of how to address these challenges. ### What ZSub Does As utilities go digital (smart meters, automated substations, distributed energy connections) they create more entry points for cyberattacks. The standard defenses (passwords, firewalls, VPNs) all share the same weakness: if an attacker steals the right credential, they're inside. At the same time, utilities can't easily share data with each other, even when doing so would help everyone detect threats faster and run more reliable grids. Privacy rules, competitive concerns, and a lack of secure infrastructure keep every utility defending on its own. ZSub's approach eliminates the central password database entirely. Instead of storing credentials on a server that can be hacked, every device and user generates its own cryptographic identity: no shared secrets, no central target. Think of it as a lock that doesn't need a key server, because each device is its own key. This same architecture also makes it possible for utilities to share operational data without exposing raw information to each other, solving the collaboration problem and the security problem in one layer. In short, ZSub enables secure coordination across utilities without introducing new attack surfaces. ### Parties Submit Opening Comments on CPUC's Renewable Gas Standard PD URL: https://www.calregulatory.com/parties-submit-opening-comments-on-cpucs-renewable-natural-gas-standard-pd/ Last updated: 2026-04-01T19:44:15.000Z Parties recently commented on CPUC President **John Reynolds**' [March 6 PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846485.PDF?ref=calregulatory.com), which restructures the [Renewable Gas Standard](https://www.socalgas.com/newsroom/press-release/socalgas-applauds-establishment-of-first-renewable-gas-standard-in-the-united-state?ref=calregulatory.com) (*see CRI's coverage* [*here*](https://www.calregulatory.com/monday-aggregate-senate-bill-1221-implementation-reining-in-rng-costs-pg-e-arrangement-with-citizens-energy-corporation/)). The parties converge on a single point: the Renewable Gas Standard has not produced a financeable market. **UPDATE*: Since this post was published, multiple other parties' comments have surfaced in the CPUC's document feed. Our briefing has been updated accordingly.* [Senate Bill 1221 Implementation; Reining in RNG CostsCommissioner Karen Douglas issued a third amended scoping memo in the CPUC’s Long-Term Gas Planning docket.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-67.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Mar-04-2026--62--1.png)](https://www.calregulatory.com/monday-aggregate-senate-bill-1221-implementation-reining-in-rng-costs-pg-e-arrangement-with-citizens-energy-corporation/) ## Background President Reynolds' PD modifies the Renewable Gas Standard program created under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com) to change biomethane procurement requirements for California's gas utilities. The PD concludes that the procurement framework adopted in a 2022 decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)) would impose excessive above-market costs on ratepayers given the early-stage biomethane market and limited feedstock supply. - To address this, the PD adopts a Cost Containment Mechanism that caps average program rate impacts at **1%** of each utility's bundled core customer revenue requirement with a maximum **3%** year-over-year increase. The Cost Containment Mechanism is the controlling constraint; the CPUC will not approve contracts that would cause rates to exceed it. - The PD also reduces the overall biomethane procurement target from 72.8 billion cubic feet annually to **36.4 billion cubic feet** and extends the compliance timeline from 2030 to 2035\. The prior short-term/medium-term structure is eliminated in favor of a single 2035 deadline. The Diverted Organic Waste procurement goal of 17.6 Bcf remains unchanged, tied to California's [Senate Bill 1383](https://www.wm.com/us/en/sb1383?ref=calregulatory.com) methane-reduction policy. - The PD opens all feedstocks to bid into utility solicitations while maintaining the dedicated Diverted Organic Waste target and directs utilities to revise their Renewable Gas Procurement Plans via Tier 2 Advice Letters. The 4% livestock biomethane procurement limit is retained. - The PD removes the previous 2040 delivery cutoff so contracts can extend beyond that date, retains the [M-RETS](https://ww2.arb.ca.gov/sites/default/files/2020-10/101520presentation%5Fm-rets.pdf?ref=calregulatory.com) tracking system, and establishes an 80/10/10 Renewable Thermal Certificate unbundling framework: - 80% of biomethane by volume stays bundled with Renewable Thermal Certificate retired by the utility; - 10% allows the developer to retain the RTC; - 10% allows the utility to market it; and - Unbundled volumes purchased at market rate do not count against the Cost Containment Mechanism. Utilities are also directed to advice letters addressing landfill eligibility and interconnection cost reductions, respectively. The earliest the CPUC will consider the PD is **April 9**. ## Parties' Positions ### The program is not functioning economically Developers, trade groups, and utilities all point to the same constraint: - No operating RNG project has recovered its costs; - Procurement targets have already been missed; and - Contract approvals remain sparse and delayed. Developers (e.g., landfill and dairy RNG operators) explicitly warn that if contract pricing is constrained or timelines remain uncertain, capital will shift to other markets where RNG commands stronger offtake terms. ### The Cost Containment Mechanism structure is under debate There is consensus among parties on on ratepayer protection, but not on the Cost Containment Mechanism design itself. - Most parties cannot evaluate whether procurement targets remain achievable under the cap - Key inputs (e.g., revenue requirement baselines, derivation of 1%/3%) are not transparent - Several parties argue the CCM is not tied to carbon-reduction value. The utilities seek flexibility or alternative calculation methods. Generators and trade groups question whether the program can function under the cap at all. Consumer and ratepayer advocates support strong cost controls but do not resolve feasibility. The Cost Containment Mechanism is now controlling the program without demonstrating it can support procurement. ### Supply constraints remain policy-driven, not physical The record identifies landfill gas as the most immediate scalable source of RNG. Developers and utilities emphasize that large volumes of landfill gas are currently flared or underutilized. Multiple parties argue that limiting landfill participation constrains near-term procurement. At the same time, dairy and livestock feedstocks are divided. Developers and agricultural groups push to remove the 4% cap and expand supply. And environmental groups argue that dairy procurement drives negative externalities and should be limited or excluded. On balance, parties indicate that supply exists, but access is being determined by policy tradeoffs, not availability. ### Unbundling introduces unresolved accounting risk The PD’s 80/10/10 RTC structure is one of the most contested elements. - Registry operators, utilities, and consumer advocates warn that unbundling without clear ownership rules creates double-counting risk; - Environmental groups argue unbundling may violate SB 1440 and weaken program integrity; - Developers and agricultural interests propose alternative frameworks where: - Compliance attributes remain bundled and retired; - Upstream methane-reduction value can be monetized separately. The utilities also raise a very specific issue: the PD treats Cap-and-Invest biogenic treatment and Carbon Intensity-based emissions benefits as separable, even though lifecycle frameworks already incorporate biogenic carbon and methane impacts. In sum, parties say the PD introduces market flexibility before defining a complete accounting system. ### Interconnection costs and process delays remain barriers There is broad agreement that California interconnection costs are significantly above national benchmarks and current timelines delay or deter project development. The PD defers cost solutions to workshops and future filings. At the same time, the contract approval process is viewed as a crucial juncture: - Developers, utilities, and trade groups argue that the lengthy process of Tier 3 advice letters introduces delays that are incompatible with project finance; and - Consumer and environmental advocates support stricter oversight, including Tier 3 review and disclosure requirements. The program is attempting to scale supply through a process that slows execution. ### Legal and policy tensions are now explicit New filings surface potential legal vulnerabilities: - Unbundling may conflict with SB 1440 requirements regarding environmental attributes; - Eligibility language changes may weaken statutory intent around in-state environmental benefits; - Some parties argue the program may not meet cost-effectiveness requirements under existing law. At the same time, competing policy objectives are now visible e.g., cost containment vs. market viability; supply expansion vs. environmental and local impacts; and speed vs. regulatory oversight. ## INSTANT ANALYSIS The record is unusually aligned on diagnosis and divided on remedy: The program has not produced a financeable project. Every major issue flows from that constraint. Consequently, the Commission is being pushed toward a reset that: - Accelerates approvals, - Clarifies and potentially loosens the Cost Containment Mechanism, - Expands access to scalable feedstocks, and - Defines accounting rules before enabling unbundling. If those changes are implemented, the Renewable Gas Standard becomes investable. If not, the program remains a compliance construct that cannot attract capital at scale. ### FRIDAY AGGREGATE: New Climate Credit Timing; SCE Dynamic Pricing Delayed URL: https://www.calregulatory.com/friday-aggregate-new-climate-credit-timing-sce-dynamic-pricing-delayed/ Last updated: 2026-03-27T20:18:59.000Z Today's report includes: - A new PD in the CPUC's Climate Credit rulemaking directing immediate interim changes to the state's Climate Credit program; - A new ALJ ruling indicating that the Commission is not ready to approve SCE's Large Power Dynamic Pricing framework; - A two-month, emergency SoCalGas curtailment on its North Valley System; - SoCalGas's renewal of interstate pipeline capacity contracts with [Transwestern Pipeline Company](https://twtransfer.energytransfer.com/ipost/main/index?asset=TW&ref=calregulatory.com); and - A PD approving Crimson California Pipeline L.P.’s request for a 10% rate increase on crude-oil transportation across its Southern California pipeline system. --- ### CLIMATE CREDIT CPUC President **John Reynolds** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K473/603473601.PDF?ref=calregulatory.com) in [R.25-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com) directing immediate, interim changes to California's residential [Climate Credit ](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com)program to improve bill affordability, primarily by shifting when credits are delivered rather than altering their size or eligibility. Historically, these credits (funded by [Cap-and-Invest](https://ww2.arb.ca.gov/our-work/programs/cap-and-invest-program?ref=calregulatory.com) allowance revenues) were issued in low-usage months (spring and fall), but the CPUC now finds that approach misaligned with affordability needs. - For 2026, large electric utilities (PG&E, SCE, SDG&E) are ordered to move electric bill credits to August and September, when usage and bills are highest. Small and multi-jurisdictional utilities (Bear Valley, Liberty, PacifiCorp) will shift their remaining 2026 credit to November to match winter peaks, then distribute in October and November beginning in 2027\. - Natural gas credits will move to February beginning in 2027; the April 2026 gas credit already went out and could not be redirected, given timing constraints. - The PD emphasizes speed and feasibility, adopting only timing changes that utilities can implement immediately, while deferring more complex reforms (e.g., eligibility changes, credit recalculation, baseline territory-level distribution) to Phase 1B. - In parallel, the PD implements statutory requirements under [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com) by directing electric utilities to remit **5%** of Cap-and-Invest allowance auction revenues to the State Treasury for deposit in the [California Transmission Accelerator Revolving Fund](https://autl.assembly.ca.gov/system/files/2026-01/01.15%5Ftx-accelerator-oversight-hearing-background.pdf?ref=calregulatory.com). Remittances are due within 15 days of final receipt of revenues from each auction, covering auctions held between **July 1, 2026** and **July 1, 2031**. - The PD updates Template D-1 within the utilities' Greenhouse Gas Revenue and Reconciliation Application Form, requiring standardized reporting on remittances through existing ERRA compliance, the Energy Cost Adjustment Clause, or advice-letter filings. - The PD also requires limited updates to customer outreach (primarily clarifying bill savings and attributing them to the Cap-and-Invest program) while avoiding expanded messaging that could reduce available credit funds. All changes are explicitly designated as interim, preserving flexibility for broader program redesign in subsequent phases of the rulemaking. The earliest the CPUC will consider this item is **April 30**. Comments are due **April 15**. **INSTANT ANALYSIS:** If adopted, this PD would shift Climate Credits into peak months, lowering summer and winter bills without increasing total value. It's a timing change, not new relief. The bigger move is upstream: AB 1207 requires 5% of allowance auction revenues to flow to the Transmission Accelerator Fund, reducing the pool available for bill credits. The CPUC is implementing a legislative mandate, not making a discretionary policy choice, but the effect is the same. Climate funds are starting to split between direct ratepayer relief and grid infrastructure buildout. Utilities get a simple, workable change on credit timing. Affordability reforms are deferred. --- ### DYNAMIC PRICING A [new ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998566.PDF?ref=calregulatory.com) modifies the procedural schedule for SCE's Large Power Dynamic Pricing proceeding and its related standard dynamic rate application. The ruling adds a supplemental testimony phase to address unresolved design and implementation questions. SCE must submit supplemental testimony by **April 24**, with rebuttal testimony due **May 26**. - The ruling focuses heavily on clarifying how SCE's proposed dynamic pricing structure will function across customer classes, particularly the role of subscription-based pricing versus alternatives like bill limiters for small and medium customers. - A recurring threshold in the ruling is **500 kW** of monthly demand, which surfaces as a potential dividing line for whether subscriptions should be mandatory or optional. Customers below that level may face a different protection framework than large power customers above it. - The ruling directs SCE to analyze customer protection mechanisms, revenue neutrality, billing complexity, and implementation cost impacts under different design choices, including whether subscriptions should be required at all for residential and small/medium commercial classes. - Additional questions probe how subscriptions should be updated over time, including the long-term bill impacts of annually recalculated versus static subscriptions for battery storage customers on [TOU-8-SEC](https://www.sce.com/sites/default/files/custom-files/PDF%5FFiles/Business/TOU-8%5FRate%5FFact%5FSheet%5F072025%5FAccessible.pdf?ref=calregulatory.com). - The ruling also asks how SCE will maintain revenue recovery under its proposed rate design, and whether a per-customer monthly charge could replace the flat volumetric charge SCE proposed to recover Equal Percentage of Marginal Cost-scaled customer revenues. - Other questions address system-wide versus locational distribution pricing, the appropriate venue for reasonableness review of implementation costs, and whether SCE's current dynamic rate pilots (set to expire **December 31, 2027**) need to be extended. **INSTANT ANALYSIS:** The CPUC is not ready to approve SCE's dynamic pricing framework and is forcing a deeper vetting of its mechanics before moving forward. The focus on subscriptions versus bill limiters, revenue recovery, and implementation cost indicates concern that the current design may be too complex for smaller customers and may not produce stable or predictable outcomes across classes. The CPUC is also testing whether SCE has over-engineered the rate. By asking for quantified cost and timeline reductions under simpler alternatives (including dropping subscriptions entirely for non-Large Power Dynamic Rate customers and adopting system-wide rather than locational distribution pricing), it's creating a pathway to scale back the proposal if needed. That puts pressure on SCE to justify not just the economics, but the operational burden of its design. What SCE shows on bill impacts, revenue neutrality, and customer protection will likely determine whether its framework proceeds as a broad tariff, a narrowed product limited to large customers above the 500 kW threshold, or a more incremental pilot extension past 2027. --- ### NATURAL GAS CURTAILMENT SoCalGas submitted Advice Letter 6614-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) to notify the CPUC of an emergency localized curtailment on its North Valley system that lasted from January 9 to March 18\. The curtailment was initiated to facilitate repairs on a natural gas pipeline and resulted in a full interruption of service to affected noncore customers during that period. SoCalGas says the curtailment was conducted in accordance with its tariff rules governing emergency service interruptions and that customers were notified through account managers and postings on its [ENVOY system](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome). Pipeline repairs remain ongoing. **INSTANT ANALYSIS:** A localized curtailment lasting over two months points to real constraints in the North Valley system, not routine operations. Noncore customers absorbed the impact, which means large-load exposure to infrastructure bottlenecks remains active. Service has resumed, but the underlying condition has not fully cleared. Repairs are still ongoing, and this event shows how long disruptions can persist once triggered. For operators, this is a reminder that localized pipeline issues can translate into extended service disruptions, even without a systemwide emergency. Reliability risk in constrained zones is real, and it can last longer than expected. --- ### INTERSTATE NG PIPELINE CAPACITY SoCalGas submitted Advice Letter 6615-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) requesting expedited CPUC approval of two renewed interstate pipeline capacity contracts with [Transwestern Pipeline Company](https://twtransfer.energytransfer.com/ipost/main/index?asset=TW&ref=calregulatory.com). The filing relies on the expedited advice letter process established in a 2004 decision ([D.04-09-022](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/39721.PDF?ref=calregulatory.com)), which permits streamlined approval when supported by Cal Advocates and TURN. Cal Advocates participated in the Capacity Consulting Group meeting and has indicated support. TURN did not participate in the review process. The contract terms are confidential due to market-sensitive content. **INSTANT ANALYSIS:** SoCalGas is maintaining interstate transport optionality into the L.A. Basin through Transwestern, with no visible change to procurement posture or tariff structure. What's worth noting here is that – even amid ongoing volatility around pipeline outages, storage constraints, and peak-day reliability concerns – SoCalGas is renewing upstream capacity rather than pulling back or reallocating exposure. Interstate capacity remains a solid reliability hedge, and there is no near-term shift toward reduced dependence on out-of-state supply corridors. --- ### CRUDE OIL TRANSPORTATION The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M603/K483/603483090.PDF?ref=calregulatory.com) approving Crimson California Pipeline L.P.’s request for a 10% rate increase on crude-oil transportation across its Southern California pipeline system, effective **August 1, 2025**. Crimson operates 300 miles of common-carrier crude oil pipeline connecting production fields to L.A. Basin refineries. The PD also authorizes retroactive collection of the difference between rates billed and the approved rates from that date forward, with interest at the 90-day commercial paper rate. The rate burden falls on commercial oil company shippers rather than end-use ratepayers. Crimson's Test-Year return on equity lands at **10.82%** with the increase applied. The PD denies Crimson's separate attempt to tack on an additional 3.16% increase on procedural grounds. The earliest the CPUC will consider this item is **May 14**. Comments are due **April 15**. **INSTANT ANALYSIS**: This is a straightforward validation of the self-executing 10% increase mechanism under the Public Utilities Code. The rejection of the 3.16% add-on is the only other action worth highlighting – the CPUC won't let applicants bootstrap additional rate relief through filings that amount to substantive amendments submitted after the scoping memo. ### WEEKEND NEWS CODEX: Assembly Bill 1777; Senate Bill 913; and California vs. the Defense Production Act URL: https://www.calregulatory.com/weekend-news-codex-12/ Last updated: 2026-03-27T17:09:52.000Z - **"We're Harvesting the Sun" – a Huge Solar Project Grows in California:** "A sweeping plan to build 21 gigawatts of solar plus batteries on 136,000 acres could be a lifeline for Central Valley farmers facing devastating water shortages."[ **CANARY MEDIA**](https://www.canarymedia.com/articles/solar/were-harvesting-the-sun-solar-project-california?ref=calregulatory.com) - **BOEM Moves to Fast-Track Environmental Review for Offshore Fracking at Platform Gilda**: "In a March 18, 2026 [notice of intent](https://www.federalregister.gov/documents/2026/03/18/2026-05319/notice-of-intent-to-prepare-an-environmental-impact-statement-on-platform-gilda-well-stimulation?ref=calregulatory.com), BOEM said it will prepare an [environmental impact statement](https://www.boem.gov/regions/pacific-ocs-region/environmental-impact-statement-platform-gilda-well-stimulation-treatment?ref=calregulatory.com) to evaluate a proposal to authorize well stimulation treatments, including fracking, across existing wells at the site. Platform Gilda, located approximately nine miles offshore in the Santa Barbara Channel, is part of the Santa Clara Unit and is operated by DCOR LLC." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/boem-moves-to-fast-track-environmental?ref=calregulatory.com) - **California Bets on an Obscure Tool to Replace Clean Air Authority Trump Revoked:** " [Assembly bill 1777, ](https://calmatters.digitaldemocracy.org/bills/ca%5F202520260ab1777?ref=calregulatory.com)authored by [Democrat **Robert Garcia**,](https://calmatters.digitaldemocracy.org/legislators/robert-garcia-109905?ref=calregulatory.com) who represents parts of San Bernardino County, would give California air regulators authority to hold ports, warehouses and railyards accountable for the pollution they draw to nearby communities — using a regulatory tool called the indirect source rule." [**CAL MATTERS**](https://calmatters.org/environment/2026/03/indirect-source-air-quality-trump/?ref=calregulatory.com) - **California Bill Would Unlock Distributed Energy Participation in Grid Resource Adequacy Market:** "California Senator **Josh Becker** (D-Menlo Park) has [introduced legislation](https://sd13.senate.ca.gov/news/press-release/march-24-2026/becker-introduces-sb-913-to-make-better-use-customer-owned-clean?ref=calregulatory.com) aimed at integrating customer-owned energy resources into the state’s grid as a formal reliability tool. The bill, SB 913, would require the California Public Utilities Commission to update its Resource Adequacy rules to allow aggregated distributed energy resources, including home batteries, electric vehicles, and smart thermostats, to compete alongside traditional power plants. Proponents argue the measure could lower ratepayer costs by reducing the state’s reliance on expensive gas peaker plants during periods of high demand." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/03/26/california-bill-would-unlock-distributed-energy-participation-in-grid-resource-adequacy-requirements/?ref=calregulatory.com) - **California Sues to Block Federal Order Restarting Sable Pipeline:** "California’s complaint argues the \[Defense Production Act\] does not authorize the federal government to override state environmental laws, judicial orders, or permitting requirements. It also contends that the statute does not permit the Department of Energy to compel private companies to enter into commercial arrangements with other private entities." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-sues-to-block-federal?ref=calregulatory.com) - **CalReg CPUC Docket Monitor**: "California electricity bills have surged roughly 39% over the last six years – the highest increase in the nation." [**JONES-AWAN CONSULTING**](https://www.jonesawan.com/calreg.html?ref=calregulatory.com) - **CARB Seeks Contractor to Help Identify UCO Mixed with Virgin Oils:** "According to CARB, the selected vendor will utilize existing laboratory practices and other analytical or process-based methods to analyze biodiesel and renewable diesel feedstocks or finished diesel fuels to identify the existence of virgin oils. Information provided by the vendor will be used by CARB and third-party verification bodies to support administration of the Low Carbon Fuel Standard." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/carb-seeks-contractor-to-help-identify-uco-mixed-with-virgin-oils?ref=calregulatory.com) - **Chevron Raises Alarm Over California Energy Crisis as Imports Slow:** "Chevron’s refining chief, **Andy Walz**, described the potential consequences as his 'worst fear.' Cities such as San Francisco and Los Angeles could face shortages of jet fuel and gasoline, critical not only for civilian transportation but also for military operations, given that the state hosts more than 30 military bases..." [**YAHOO NEWS**](https://finance.yahoo.com/sectors/energy/articles/chevron-raises-alarm-over-california-142000111.html?ref=calregulatory.com) - **Data Center Approvals in San Jose and Sunnyvale:** "STACK will design, procure, and construct the 115 kV Ringwood Switching Station in San Jose to serve a 90 MW data center load, then transfer ownership to PG&E. The switching station is expected to be operational by **April 2026**." [**CRI LINKEDIN**](https://www.linkedin.com/pulse/data-center-approvals-san-jose-sunnyvale-michael-cade-p3lie/?trackingId=%2BqI2AxjFcRsUNdKt227XSw%3D%3D&ref=calregulatory.com) - **Data Centers and California Electric Policy:** "California should accommodate data center growth while avoiding unnecessary infrastructure investments by making more effective use of its existing electric grid through smarter planning. This includes incentivizing and prioritizing targeted transmission upgrades and strategic data center siting, encouraging the clean and flexible use of backup power resources, and leveraging load shifting to support the grid during periods of peak demand." [**LITTLE HOOVER COMMISSION**](https://lhc.ca.gov/wp-content/uploads/LHC-Report-292-Data-Centers-California-Electricity-Policy-FINAL-PUBLIC-3.3.26.pdf?ref=calregulatory.com) - **California Report Outlines Framework to Manage Data Center Power Demand: "**In its [report](https://lhc.ca.gov/wp-content/uploads/LHC-Report-292-Data-Centers-California-Electricity-Policy-FINAL-PUBLIC-3.3.26.pdf?ref=calregulatory.com) *Data Centers and California Electricity Policy*, the Little Hoover Commission evaluates how the state should manage rising electricity demand from data centers through updated rate design, financing mechanisms, and regulatory tools. Data centers—particularly those supporting artificial intelligence—are identified as a major new source of load growth and a potential driver of grid investment and modernization." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-report-outlines-framework?ref=calregulatory.com) - **Here Comes the Western Spadefoot:** "The western spadefoot is a toad-like species that gets its name from shovel-like growths on its back legs it uses for digging. Its habitat has declined over the years due to “agriculture, extractive development, and roads,” according to the Center for Biological Diversity’s [petition](https://nrm.dfg.ca.gov/FileHandler.ashx?DocumentID=236784&inline&ref=cleanpowercalifornia.org)...The spadefoot petition risks putting the species on a collision course with clean energy plans that, by the Public Utilities Commission’s [latest calculations](https://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&docid=595083681&ref=cleanpowercalifornia.org), call for 36 gigawatts of new solar and 18 gigawatts of storage by 2031." [**THE CURRENT**](https://www.cleanpowercalifornia.org/here-comes-the-western-spadefoot/?ref=calregulatory.com) - **How Sacramento Built an Energy Crisis and Called it a Climate Policy:** "A state that produces its own CARBOB in sufficient volume, with a Gulf Coast connection as backup, protects both its air quality and its energy security. Sacramento has built a structure that protects neither. The governors of Nevada and Arizona have standing to demand federal action. The commanders of 40 military installations have operational reasons to require it." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/california-blow-up-how-sacramento-built-an-energy-crisis-and-called-it-a-climate-policy/?ref=calregulatory.com) - **I Don't Have the "Capacity" for That Right Now:** "Capacity – what we in the West call 'resource adequacy'– is a hard concept to get right. It doesn’t exist in other 'commodity' markets. In the old era of individual utilities building out a system to meet its needs, “capacity” was a term of art, not an accurately quantified term of a utility’s portfolio that was to represent a possibility of maximum capability. The need to more precisely define it and quantify it was to allow for utilities to share resources once we evolved to a system of moving or sharing power. This evolution developed after the slowdown of rapid economic growth in the first three quarters of the 20th century; the industry could not rely upon constant large load growth as demand grew much more slowly." [**WESTERN POWER TRADING FORUM**](https://www.wptf.org/i4a/pages/index.cfm?pageid=3295&ref=calregulatory.com) - **Joint Workshop on Safety Culture Assessments:** "Multiple surveys from different agencies and internal departments lead to lower participation and employee burnout. SDG&E noted a drop in participation and stopped its internal survey to focus on the Energy Safety survey." [**MEETING BRIEFS**](https://www.meetingbriefs.ai/?ref=calregulatory.com#/meetings/07ba504d-37ad-402d-9e0e-496b77d6b0f4) - **Over 400 Million Barrels Will be Added to the Oil Market Soon – What are Strategic Reserves and What Can They Do?** "Starting in 1912, Congress set aside several [petroleum-rich areas in the U.S.](https://www.energy.gov/hgeo/opr/naval-petroleum-reserves?ref=calregulatory.com), including Elk Hills in California and [Teapot Dome in Wyoming](https://www.senate.gov/artandhistory/senate-stories/one-hundred-years-since-teapot-dome.htm?ref=calregulatory.com). In times of need, oil wells could be drilled in those regions to produce fuel for the Navy." [**THE CONVERSATION**](https://theconversation.com/over-400-million-barrels-will-be-added-to-the-oil-market-soon-what-are-strategic-reserves-and-what-can-they-do-278370?ref=calregulatory.com) - **Replacing California's Peaker Plants with Long-Duration Energy Storage:** "LDES systems, which store and deliver electricity for 10–12 hours or more, offer a cost-effective and reliable alternative. LDES systems store excess electricity when supply exceeds demand and discharges it when needed—covering evenings, multi-day renewable droughts, and other periods of grid stress." [**KLEINMAN CENTER FOR ENERGY POLICY**](https://kleinmanenergy.upenn.edu/commentary/blog/replacing-californias-peaker-plants-with-long-duration-energy-storage/?ref=calregulatory.com) - **Stored Potential – Focus Group Perspectives on California's Battery Boom:** "Participants across groups demonstrated very low baseline awareness of utility-scale battery energy storage systems. Most had never heard of the technology before the discussion. While a few participants initially said they were familiar with battery storage, it quickly became clear that they were referring to household-level battery systems paired with rooftop solar, rather than large, grid-scale facilities. Personal experience with residential renewable technologies — especially solar panels, electric vehicles, and home battery systems — provided a useful entry point for understanding the concept of battery storage for the grid. Framing BESS as essentially 'home batteries, but for many houses' helped participants grasp how the technology functions at a larger scale." [**DATA FOR PROGRESS**](https://www.filesforprogress.org/reports/Stored%5FPotential%5FCA%5FFocus%5FGroup%5FPerspectives.pdf?ref=calregulatory.com) - **The Meek Must Not Inherit California's Electricity Bills:** "California has the second-highest residential electricity rates in the country, roughly double the national average. Rates have risen 39 percent since 2019, the largest increase of any state in the nation. For a low-income family in California, electricity already eats up about 4.4 percent of their annual income. For a wealthy household, the same bill represents just 1.5 percent. The Public Policy Institute of California stated that in April 2025, 1.9 million California households had overdue electricity bills. 50,000 had their power cut off." [**LA SENTINAL** ](https://lasentinel.net/the-meek-must-not-inherit-californias-electricity-bills.html?ref=calregulatory.com) - **Transmission Infrastructure Gets Top Billing at March 19 CPUC Voting Meeting:** "'These decisions,' said **Commissioner Harada**, 'are about what every Californian expects – that when we flip on a switch, the light turns on. When we plug in our EV – it actually charges. That we've got a family member who needs medical equipment to run through the night – that it does.'" [**ENERGY CENTRAL**](https://www.energycentral.com/energy-biz/post/transmission-infrastructure-gets-top-billing-at-march-19-cpuc-voting-898Ru0W9l4o90G9?ref=calregulatory.com) - **Utilities Weigh Regional Resource Adequacy Under New Western Market:** "**Anna McKenna**, vice president of market design and analysis for the California Independent System Operator, said that once the EDAM launches, CAISO will be 'spending a lot of time evaluating \[its\] performance' and providing monthly reports as the launch marks a 'very important, significant market design change.'" [**UTILITY DIVE**](https://www.utilitydive.com/news/western-utilities-weigh-a-new-resource-adequacy-program-under-rowe/815043/?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: CPUC Moves to Enforce Energization Timelines; SDG&E Challenges EE Model; PG&E Exits Ruby Capacity URL: https://www.calregulatory.com/wednesday-aggregate-18/ Last updated: 2026-03-26T04:17:35.000Z Today's regulatory roundup looks at: - Enforcement tools the CPUC is developing for energization timelines; - A holistic build sequence for DER orchestration; - A Line 225 force majeure event on [SoCalGas](https://www.linkedin.com/company/socalgas/?ref=calregulatory.com)'s system; - PG&E's exit from contracted NG capacity with Ruby Pipeline; - New IOU energy-efficiency business plan applications; - SDG&E's request for borrowing authority before its next capital cycle; and - A PG&E Corporation joint venture with Lockheed Martin, et al. SDG&E's energy-efficiency submission is notable because it asks the CPUC to *reject* the filing and adopt a separate, pending request (A.25-04-014) that would significantly scale back its EE programs. --- ### ENERGIZATION CPUC President **John Reynolds** issued an [amended Phase 2 scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K999/602999018.PDF?ref=calregulatory.com) in the Commission's Timely Energization rulemaking ([R.24-01-018)](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/energization?ref=calregulatory.com), expanding the proceeding beyond the timeline-setting work completed in a 2024 decision ([D.24-09-020](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K806/540806654.PDF?ref=calregulatory.com)) and into enforcement, auditing, and process improvement. The new scoped issues fall into four categories. - First, the CPUC is asking how it should enforce compliance with previously adopted energization targets under the Public Utilities Code: - What triggers remedial action; - What remedial actions are appropriate; - How compliance with those orders should be monitored; and - Whether the existing Enforcement Policy ([Resolution M-4846](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M350/K405/350405017.PDF?ref=calregulatory.com)) satisfies [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com)'s requirement for an enforcement policy "that includes penalties" or whether additional measures are needed. - Second, the ruling scopes auditor selection and implementation under SB 254, which requires utilities to retain third-party auditors to review energization planning and business processes. PG&E and SDG&E already have auditors in place under [SB 410](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB410&ref=calregulatory.com), so coordination between the two audit tracks is a live issue. The scoping memo asks whether large investor-owned utilities should jointly retain a single SB 254 auditor, how audit costs should be treated for ratemaking (notably, SB 410 prohibits ratepayer funding while SB 254 is silent) and what role nonbinding auditor recommendations should play. - Third, the Commission asks whether it should take steps to implement the reporting requirements of the Public Utilities Code. - Fourth, the ruling invites comment on whether energization processes should be further standardized across utilities and whether additional actions beyond SB 410 and [Assembly Bill 50](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240AB50&ref=calregulatory.com) are warranted to improve timelines. **INSTANT ANALYSIS:** This phase marks the transition from setting energization timelines to building the machinery to enforce them. The most consequential fights will be over audit design (joint vs. separate auditors, shareholder vs. ratepayer cost allocation, and whether nonbinding recommendations acquire binding force through Commission action). The enforcement policy question is equally significant: whether Resolution M-4846 is adequate or whether the CPUC constructs something new will shape penalty exposure for years. In the background, SB 254 requires the Commission to report to the legislature by **January 1, 2027**, on whether to tie executive compensation to energization performance. The latter is not yet a scoped issue, but a sign of where legislative pressure is heading. --- ### DISTRIBUTED ENERGY RESOURCES Commissioner **Darcie Houck**'s [March 23 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997407.PDF?ref=calregulatory.com) in the [High DER Future docket](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/distribution-planning?ref=calregulatory.com) (R.21-06-017) moves Track 2 from a workshop phase into a structured build sequence for DER orchestration. Under this approach, PG&E, SCE, and SDG&E would each file formal applications to develop Distribution System Operator-led orchestration frameworks, preceded by two CPUC-led workshops (the first on the application process itself, the second on DER visibility to the CAISO and Transmission System Operator-Distribution System Operator coordination). The ruling identifies five priority operational areas from the Gridworks Future Grid Study: - DER visibility to the Distribution System Operator; - DER visibility to the CAISO; - Dispatchability/control; - Open access to the distribution system; and - Reliability coordination at the transmission-distribution interface. Rather than treating these items separately, the ruling proposes a holistic framework in which utilities use real-time data, forecasting, and control signals to align DER output with grid needs (explicitly framed as targeted signaling, not full command-and-control). The ruling contains seventeen stakeholder questions, which cover objectives, valuation, guiding principles, phased implementation, aggregator participation, [ADMS/DERMS](https://www.gevernova.com/software/blog/adms-derms-differences?ref=calregulatory.com) investment, interoperability, and real-time pricing compatibility. The ruling also asks whether Integration Capacity Analysis quarterly workshops should shift to biannual cadence and proposes a standardized template for biennial grid modernization reporting. Comments are due **April 13**, with replies due **April 20**. Workshop presentations must be served by **April 22** (the first workshop, addressing the application process, is **April 29**. The second workshop, addressing Transmission System Operator/Distribution System Operator/CAISO coordination, is TBD.) **INSTANT ANALYSIS:** The sleeper provision is Question 6 (whether IOUs should propose a shared savings mechanism allowing them to share in net cost savings when DER solutions displace traditional infrastructure). If adopted, that fundamentally realigns utility incentives away from capital deployment. The other critical variable is what "open access" actually means once utilities control the orchestration layer. The ruling lists this as a guiding principle, but operational definitions (eligibility, data flows, participation pathways) will be set in the application phase. Aggregators and third-party providers should watch Questions 15-17, which address aggregator coordination and performance standards, additional technology investments required for orchestration, and whether those capabilities should be customer-owned or utility-owned. --- ### SOCALGAS SYSTEM RELIABILITY SoCalGas [reports on Envoy](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome) that it is continuing to respond to a force majeure event on Line 225 near the I-5 corridor in Castaic. A geotechnical assessment of the affected area is complete and engineers are designing a repair plan. Construction is expected to begin in **May 2026** and will take multiple months, with timelines subject to adjustment. Separately, SoCalGas will conduct safety checks and a required pressure test on a different section of Line 225 in Castaic between March and May 2026\. The company states this work will not interfere with the repair schedule. **INSTANT ANALYSIS:** Line 225 is a major transmission artery feeding the LA Basin, which means a force majeure with a multi-month construction window is not a short-duration outage, it is a sustained reliability challenge on a consequential segment. SoCalGas has not announced blanket capacity reductions, but it is already directing customers to the Envoy Capacity Utilization page for cycle-by-cycle available capacity. That language suggests variability is present now, and is not hypothetical. The overlap of repair construction and pressure testing on different sections of the same pipeline in the same corridor compounds operational risk, even if SoCalGas says the two work scopes are independent. This is early-stage, but the escalation path is legible: any constraints on scheduling flexibility move this into SoCal Citygate price exposure and curtailment risk for noncore loads. --- ### PG&E NATURAL GAS CAPACITY PG&E filed [Advice Letter 5190-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5190-G.pdf?ref=calregulatory.com), notifying the CPUC that it will not renew any portion of its contracted capacity on the [Ruby Pipeline](https://en.wikipedia.org/wiki/Ruby%5FPipeline?ref=calregulatory.com) when the amended contract expires **October 31**. The filing follows the procedure established in a 2021 decision ([D.21-12-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M432/K752/432752633.PDF?ref=calregulatory.com)), which requires PG&E to first consult with the Core Gas Supply Stakeholder Group (Cal Advocates, the CPUC's Energy and Legal Divisions, and TURN) before filing a Tier 1 advice letter with the Commission. PG&E completed the stakeholder consultation on March 11\. Protests are due **April 13**. **INSTANT ANALYSIS:** This is a full exit from a legacy interstate pipeline position. PG&E will not retain even a partial capacity commitment beyond October. No replacement procurement strategy is disclosed in the filing. The advice letter includes standard Tier 1 language representing no rate impact, no service withdrawal, and no tariff conflict, which tells you PG&E views the capacity as surplus to current needs. The longer-term questions are significant: how does PG&E reconstitute its supply stack without Ruby capacity, what does that mean for winter reliability and basis risk, and does this accelerate reliance on storage and spot market procurement? The move is consistent with declining gas demand forecasts and growing political pressure on long-duration pipeline commitments in California, but it shifts risk from fixed-term contract obligations to market exposure. --- ### ENERGY EFFICIENCY [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K766/602766097.PDF?ref=calregulatory.com), [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347227.PDF?ref=calregulatory.com), [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347530.PDF?ref=calregulatory.com), and [SoCalGas](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K898/602898909.PDF?ref=calregulatory.com) all filed applications for eight-year energy-efficiency business plans (2028-2035) paired with four-year portfolio plans (2028–2031). - PG&E and SoCalGas present relatively conventional, growth-oriented filings that lean into the CPUC’s Total System Benefit framework and long-term decarbonization trajectory, proposing large multi-billion-dollar portfolios (**$1.78 billion** for PG&E; about **$1.25 billion** for SoCalGas, excluding Regional Energy Networks) with an emphasis on building electrification, load flexibility, and market transformation. - SCE takes a more constrained approach, explicitly aligning with state affordability directives by proposing a materially downsized portfolio (about **$997 million** for 2028–2031, a 40% reduction from the prior cycle). However, Edison still targets strong performance metrics (Total System Benefit above goals and improved Total Resource Cost), and pairs that with a set of policy reforms to reduce administrative burden, loosen third-party requirements, and improve cost discipline. - SDG&E is the outlier. It submitted a compliant EE plan (about **$565 million**, or **$1 billion** including the [San Diego Regional Energy Network](https://sdren.org/?ref=calregulatory.com)). However, SDG&E is not actually asking the CPUC to approve it. Instead, SDG&E is urging the CPUC to reject its filing and adopt a separate, pending application ([A.25-04-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M564/K628/564628009.PDF?ref=calregulatory.com)) that would significantly scale back its EE programs or exit regional administration altogether, citing affordability concerns and past underperformance. **INSTANT ANALYSIS:** These filings fall into two camps: PG&E and SoCalGas are pushing full-scale EE investment, SCE is trimming within the model, and SDG&E is challenging the model itself. SDG&E’s request to reject its own filing in favor of a lower-cost alternative introduces a real off-ramp. That raises precedent risk and gives the Commission a path to reset EE spending. The CPUC's response will determine whether EE continues as a large, systemwide investment or shifts toward a constrained, performance-driven model. --- ### UTILITY FINANCES In a [new filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347096.PDF?ref=calregulatory.com) at the CPUC, SDG&E requests **$2.583 billion** in new long-term debt authority and **$1.348 billion** in rollover authority to fund capital investments through 2029\. Existing authorization from a 2022 decision ([D.22-12-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K511/499511248.PDF?ref=calregulatory.com)) is nearly used up: only about **$167 million** in unused new-debt authority will remain after planned 2026 issuances. On the other side, SDG&E forecasts **$2.75 billion** in new debt needs and **$1.35 billion** in maturing bonds to refinance. The capital program is driven by wildfire safety and grid hardening, EV infrastructure, energy storage, grid modernization, and gas system integrity. These investments were largely approved in the Test-Year 2024 General Rate Case decision ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)), or anticipated in future filings. SDG&E requests the same financing toolkit and hedging authority approved in D.22-12-011\. That includes the full range of secured and unsecured instruments, foreign market access, tax-exempt debt, variable-rate structures, and derivative-based hedging. A [concurrent motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K365/602365880.PDF?ref=calregulatory.com) seeks to seal six financial schedules containing forward-looking construction, cash flow, and capitalization data. **INSTANT ANALYSIS:** SDG&E is securing the borrowing authority it needs ahead of a heavy 2027–2029 capital cycle. The $3.9 billion combined request is driven by wildfire mitigation, grid hardening, and electrification investment that has already been approved, or is expected to be approved. The financing toolkit gives SDG&E flexibility on timing and cost, but also leaves room for how debt costs ultimately flow into rates. --- ### WILDFIRES PG&E filed [Advice Letter 5189-G/7864-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5189-G.pdf?ref=calregulatory.com), notifying the CPUC of a new affiliate relationship with [EmberPoint LLC](https://emberpoint.co/?ref=calregulatory.com). EmberPoint is a joint venture between [Lockheed Martin Evolve LLC](https://www.lockheedmartin.com/en-us/index.html?ref=calregulatory.com), [PG&E Corporation](https://www.pgecorp.com/?ref=calregulatory.com), [Salesforce](https://www.salesforce.com/?ref=calregulatory.com), and [Wells Fargo](https://www.wellsfargo.com/?ref=calregulatory.com) focused on developing next-generation wildfire mitigation solutions. PG&E Corporation acquired its interest on **January 23**, via a Simple Agreement for Future Equity funded by shareholders. Although EmberPoint's business purpose does not directly relate to gas or electric service, PG&E is treating it as an affiliate under both Rule I.A and Rule II.B of the [Affiliate Transaction Rules](https://docs.cpuc.ca.gov/published/Graphics/63089.PDF?ref=calregulatory.com) (the latter explicitly described as an abundance-of-caution measure) and will apply its existing 2025 compliance plan to all transactions with the entity. **INSTANT ANALYSIS:** The Rule II.B designation is the key move here. PG&E didn't have to apply the full affiliate transaction restrictions to a holding-company-level investment in a venture with no direct utility nexus, but chose to anyway. That's a sign the company is already thinking about how wildfire mitigation spending, data access, and procurement could raise cross-subsidy or preferential treatment questions. ### MONDAY AGGREGATE: CPUC Approves SCE Rate-Design Settlements, Denies SoCalGas $266M for Angeles Link Hydrogen Pipeline URL: https://www.calregulatory.com/monday-aggregate-cpuc-approves-sce-rate-design-settlements-denies-socalgas-266m-for-angeles-link-hydrogen-pipeline/ Last updated: 2026-03-23T21:37:36.000Z Today's roundup examines: - A proposed decision largely approving SCE's 2024 General Rate Case Phase 2 settlements; - A PD denying SoCalGas's request to recover $266 million from gas ratepayers for Angeles Link hydrogen pipeline engineering work; - A ruling in the CPUC's Building Decarbonization proceeding soliciting input on scaling beyond pilot programs toward a formal action plan; and - A workshop report in the High DER Future proceeding exploring flexible grid connections that would allow faster customer energization under "operating envelopes." --- ### SCE 2024 GENERAL RATE CASE PHASE 2 A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998920.PDF?ref=calregulatory.com) at the CPUC approves nine of 10 settlement agreements resolving SCE's 2024 General Rate Case Phase 2 on marginal costs, revenue allocation, and rate design. The PD denies a Vehicle-to-Grid Rate Proposal Settlement Agreement and declines to adopt three contested proposals (deferring PRIME Plus and baseline allowance expansion to future rulemakings, and finding the [Solar Energy Industry Association](https://seia.org/about/?ref=calregulatory.com)'s transmission marginal cost proposal outside the proceeding's scope). The PD adopts a [comprehensive settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998820.PDF?ref=calregulatory.com) on marginal cost methodology and revenue allocation, agreed to by utilities, consumer advocates, and large customer groups. It sets key cost inputs (a **$132.72/kW-year** generation capacity marginal cost, [Avoided Cost Calculator](https://www.cpuc.ca.gov/dercosteffectiveness?ref=calregulatory.com)\-based energy costs, and [Real Economic Carrying Charge](https://www.lawinsider.com/dictionary/real-economic-carrying-charge?ref=calregulatory.com)\-based customer costs) and uses these to allocate SCE's revenue requirement across customer classes. The settlement applies a revenue-neutral allocation framework built on an illustrative **$17.5 billion** consolidated revenue requirement (approximately $17,466 million as of October 2024), with rates ultimately updated to actual authorized revenues at implementation. To limit bill volatility, the PD introduces "collars" that constrain how far class revenues can move from current levels: +**4.0%**/**−6.0%** for delivery revenues around the System Average Percentage Change, and +**0.97%**/**−1.9%** for generation revenues for bundled service customers. - A major element is the treatment of wildfire-related costs, which are allocated using a hybrid formula: **21.5%** tied to distribution cost causation and **78.5%** spread broadly based on system revenues, balancing cost causation with rate stability. The formula will be updated annually and governs until the next GRC Phase 2 proceeding. - The V2G settlement was the only opposed agreement, with Cal Advocates arguing that using the Avoided Cost Calculator to set EV export compensation is premature. The ALJ agrees, finding that the CPUC has not sufficiently evaluated the accuracy of Avoided Cost Calculator-based versus real-time marginal-cost-based credits, customer behavior regarding export rates, or export flexibility under different compensation structures. Existing dynamic pricing pilots should be used until that evaluation is complete, which portends broader implications for the Avoided Cost Calculator's expanding role in ratemaking. - On residential rate design, the approved settlement establishes a four-year glide-path moving Time-of-Use period rate differentials toward 80% of settled marginal cost ratios, with adjustments occurring each **October 1** from 2026 through 2029\. The TOU-D-PRIME seasonal differential increases from 2.4 to **6 cents/kWh**, moving toward 100% of marginal cost levels over the same period. - SCE's PRIME Plus proposal (a demand-based residential rate variant) was not rejected on its merits. The PD defers it to an anticipated industry-wide rulemaking on residential Time-of-Use rate structures, preserving the concept for future consideration. - TURN's baseline allowance proposal raised a substantive issue: residential solar adoption is depressing metered usage and thereby shrinking baseline quantities, disproportionately harming non-Net Energy Metering customers. The ALJ acknowledges the problem but rules that the statutory definition of "residential consumption" under the Public Utilities Code refers to utility-delivered energy, not customer-generated energy. The issue was referred to a future rulemaking affecting all large electric investor-owned utilities. - The Economic Development Rate settlement raises the EDR discount from 12% to **20%**, increases the MW cap from 200 to **300 MW**, expands the small customer demand threshold from 150 kW to **200 kW**, and includes a limited Economic Development Rate program for host sites supporting the 2028 Olympic Games. Comments are due **April 9**. The earliest the CPUC will consider this item is **April 30**. **INSTANT ANALYSIS:** The PD carries four main implications. - **Cost causation loses to rate stability (by design)**. The collaring mechanism and System Average Percentage Change-heavy wildfire allocators blunt large redistributions. - **Wildfire costs are being socialized**. The 78.5% System Average Percentage Change weighting spreads most wildfire burden broadly across load. This reduces class-specific exposure, especially for distribution-intensive customers. - **The Avoided Cost Calculator's role in ratemaking is now contested ground**. The V2G rejection suggests that the CPUC is not prepared to extend Avoided Cost Calculator-based compensation beyond the Net Billing Tariff without further study. Parties pushing Avoided Cost Calculator-derived values into new rate structures (dynamic rates, export credits, marginal cost proceedings) now face a higher evidentiary bar. - **A playbook for the next GRC cycle**. The settlement governs allocation mechanics until the next Phase 2\. Future battles will shift from methodology to inputs: load forecasts, revenue requirement, and program costs. The baseline allowance and PRIME Plus deferrals ensure those fights will also play out in parallel rulemakings. --- ### HYDROGEN/ANGELES LINK The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K997/602997613.PDF?ref=calregulatory.com) denying SoCalGas's request to recover **$266 million** from natural gas ratepayers to fund Phase 2 front-end engineering and design work for the [Angeles Link](https://www.socalgas.com/sustainability/innovation-center/angeles-link?ref=calregulatory.com) hydrogen pipeline project. The project proposes dedicated hydrogen transmission pipelines to deliver renewable hydrogen into the Los Angeles Basin for hard-to-electrify sectors including power generation, industrial uses, and heavy-duty transportation. The PD finds that the project remains speculative, with no specific customer base identified – as required by a 2022 decision ([D.22-12-055](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K167/500167327.PDF?ref=calregulatory.com)) – no guarantee of construction, and no demonstrated direct benefits to existing natural gas ratepayers. - The record shows significant opposition from consumer advocates, environmental groups, and shippers, who argue that the project's benefits are indirect and uncertain, and that shifting early-stage development costs onto ratepayers would violate core cost-causation principles. Phase 2 cost estimates have nearly tripled since the project was initially proposed, rising from $92 million to $266 million. - SoCalGas declined federal [IIJA](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com) funding through [ARCHES](https://archesh2.org/?ref=calregulatory.com) ( funding the CPUC had specifically directed the utility to pursue in D.22-12-055 to offset ratepayer exposure) arguing that federal compliance costs would not serve ratepayer interests. The PD notes this means no federal offset exists for the proposed costs. - The PD concludes that ratepayer funding is not justified at this stage, emphasizing that the project is still in planning, has seen cost estimates rise sharply, and lacks clear alignment with established standards requiring projects to be "used and useful" before cost recovery. The PD does not adopt TURN's alternative proposal to track Phase 2 costs in a memorandum account for future recovery once the project becomes operational. - The PD declines to resolve jurisdictional questions around whether the project would qualify as a pipeline under Public Utilities Code Section [227](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-227/?ref=calregulatory.com)/[228](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-228/?ref=calregulatory.com) or a gas plant under Section [221](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-221/?ref=calregulatory.com)/[222](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-222/?ref=calregulatory.com), finding such determinations both premature (because the project is not constructed or dedicated to public use) and unnecessary given the denial of cost recovery. The application is denied in full and the proceeding is closed, leaving SoCalGas to pursue the project, if at all, without ratepayer-backed funding for Phase 2. Comments are due **April 9**. The earliest the CPUC will consider this item is **April 30**. **INSTANT ANALYSIS:** The CPUC is rejecting the idea that speculative, pre-construction hydrogen infrastructure can be funded by legacy gas ratepayers, though it is not permanently foreclosing ratepayer recovery if the project is eventually constructed and demonstrated to be used and useful. For now, the PD is pushing hydrogen out of the mainstream utility cost-recovery model and into a merchant or contract-backed lane. The refusal of federal funding compounds the problem: SoCalGas eliminated the one mechanism the CPUC itself identified to cushion ratepayer impact, then asked ratepayers to absorb the full cost anyway. Developers will need anchor customers, bilateral deals, or external capital. --- ### BUILDING DECARBONIZATION A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998922.PDF?ref=calregulatory.com) in the CPUC's Building Decarbonization rulemaking seeks stakeholder input on lessons learned, best practices, and next steps for scaling building decarbonization programs in California. The ruling places into the record draft evaluation reports for the [BUILD](https://www.energy.ca.gov/programs-and-topics/programs/building-initiative-low-emissions-development-program-build?ref=calregulatory.com) and [TECH](https://www.caclimateinvestments.ca.gov/tech-clean-california?ref=calregulatory.com) pilot programs (established under [Senate Bill 1477](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1477?ref=calregulatory.com) and [D.20-03-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M331/K772/331772660.PDF?ref=calregulatory.com)) and directs parties to comment on both those reports and a recent workshop that examined program performance, coordination, and long-term strategy. The ruling frames this effort as part of Phase 4 of the proceeding, which is focused on developing a formal Building Decarbonization Action Plan. It builds on a January 2026 workshop and a staff-developed framework that identifies six categories of best practices for program design: integrated program offerings, measure-specific successes, right-sizing electric service, recognizing remediation needs, customer buy-in, and data and analytics, along with broader considerations like workforce development, codes and standards, and long-term system planning. Through an extensive set of questions, the CPUC is probing gaps in current programs, coordination challenges across agencies and market actors, funding strategies, equity considerations, and infrastructure constraints. This includes the role of thermal energy networks and networked geothermal, zonal electrification lessons from PG&E's CSU-Monterey Bay project, and utility pilot authority under [Senate Bill 1221](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/sb-1221-implementation?ref=calregulatory.com), with the goal of shaping a more coherent, scalable, and cost-effective statewide decarbonization strategy. Opening comments are due **April 10**, with replies due **April 17**. **INSTANT ANALYSIS:** This is a record-building step ahead of a formal action plan. The CPUC is forcing parties to convert workshop input into concrete program design recommendations. The focus is on scaling beyond pilots. The explicit attention to thermal energy networks, CSUMB zonal electrification, and SB 1221 pilot authority signals where the Commission sees actionable near-term pathways. Expect movement toward integrated, zonal electrification tied to grid capacity, funding, and customer adoption. Outcomes here will feed into General Rate Cases, gas planning, and cost allocation. --- ### DISTRIBUTED ENERGY RESOURCES SCE filed an [all-party workshop report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K998/602998929.PDF?ref=calregulatory.com) in the CPUC's High DER Future proceeding regarding a February 20 Flexible Connections workshop. The report explains that as electrification and DER adoption accelerate, traditional grid planning and infrastructure upgrades alone may not be sufficient to meet growing demand quickly or cost-effectively. To address this, regulators and stakeholders are exploring “flexible connections,” which allow customers to connect to the grid under time-varying or conditional limits (operating envelopes) so that existing grid capacity is used more efficiently without compromising safety or reliability. The workshop brought together utilities, regulators, and industry stakeholders to evaluate the implementation of these flexible approaches. Discussions focused on enabling technologies such as: - Advanced grid management systems ([ADMS/DERMS](https://www.gevernova.com/software/blog/adms-derms-differences?ref=calregulatory.com)); - AMI data and metering capabilities (noting that PG&E cautioned against reliance on existing [AMI 1.0](https://www.net2grid.com/post/from-ami-1-0-to-ami-2-0-what-utilities-need-to-know-for-a-smooth-transition?ref=calregulatory.com) data for secondary-level operating envelopes due to data latency and limited load diversity, and that [EPIC](https://www.energy.ca.gov/programs-and-topics/programs/electric-program-investment-charge-epic-program?ref=calregulatory.com)\-funded pilots are exploring [AMI 2.0](https://www.utilitydive.com/spons/how-ami-20-is-powering-the-grid-of-the-future/803806/?ref=calregulatory.com) capabilities to address these gaps); - Communication protocols (specifically the debate between utility-preferred [IEEE 2030.5](https://www.gevernova.com/software/blog/ieee-20305-distributed-energy-resources?ref=calregulatory.com) and aggregator-preferred [OpenADR](https://en.wikipedia.org/wiki/Open%5FAutomated%5FDemand%5FResponse?ref=calregulatory.com) for scalability); and - Aggregators. Discussions also focused on critical policy questions including: - Customer participation and the shift from utility-controlled "top-down" models to elective "bottom-up" models; - Cost-benefit considerations, with the Vehicle Grid Integration Council pointing to New York’s [Load Management Technology Incentive Program](https://jointutilitiesofny.org/ev/lmtip?ref=calregulatory.com) as a potential model for upfront incentives; and - The distinction between "bridging" solutions (temporary limits to allow faster connection before upgrades) and "non-bridging" solutions (ongoing flexible service that could defer or replace infrastructure investments). Participants generally agreed that flexible connections (especially bridging solutions) offer immediate value by speeding up customer energization and reducing upgrade costs. However, they expressed differing views on technical readiness and scalability. PG&E highlighted real-world "[Flex Connect](https://www.pge.com/assets/pge/docs/clean-energy/electric-vehicles/flexible-service-connection-pilot-overview.pdf?ref=calregulatory.com)" deployments already in use on primary distribution systems, while SDG&E emphasized that it is not currently positioned to deploy a standardized, systemwide dynamic operating envelope offering, characterizing its current status as proof-of-concept and stating that the need for such an offering has not yet been demonstrated. Stakeholder groups stressed the importance of transparency, consistent cost-benefit analysis, and regulatory clarity regarding compensation to ensure equitable and effective adoption. **INSTANT ANALYSIS:** The CPUC is shifting from a "build-first" model to an "operate-first" model. Flexible connections let utilities constrain load and connect customers now, rather than wait for years of infrastructure upgrades. - Near-term impact: Speed-to-power. PG&E is already using this approach for faster interconnections and avoided costs, specifically for large new loads on primary systems. - The Scalability Constraint: The major hurdle is "non-bridging" (permanent) flexible service. Without clear rules on financial compensation, upfront hardware incentives (like New York's [LMTIP](https://jointutilitiesofny.org/ev/lmtip?ref=calregulatory.com)), and a transition from "top-down" utility control to "bottom-up" customer election, long-term flexible service will not scale. - Technical Readiness: PG&E's DERMS-enabled Flex Connect is operational on primary feeders today. Secondary-level success for residential and small business customers depends on multiple factors: the rollout of AMI 2.0, resolution of communication protocol standards, DERMS deployment and full secondary-system modeling (SCE targets 2027-2028), and validation through pilots currently underway. ### WEEKEND NEWS CODEX: Balcony Solar Legislation; Gas Tax Relief Bill; Casa Diablo IV URL: https://www.calregulatory.com/weekend-news-codex-11/ Last updated: 2026-03-20T01:19:01.000Z - **California's Declining Oil Refinancing Capacity as an Adaptation Bottleneck**: "California has the most environmental regulations in the nation and this sector has borne the brunt of these costs." [**ENVIRONMENTAL & URBAN ECONOMICS**](https://matthewekahn.substack.com/p/californias-declining-oil-refining) - **California's Economy Faces Threats with New Energy Policy Changes:** "California refineries supply a broad range of transportation fuels, including aviation fuels that are critical to commercial and military operations, and they operate near major ports, military installations, and strategic hubs serving the Pacific region. Continued erosion of California’s refining capacity risks increased reliance on imported fuels that are slower to arrive, more exposed to global supply disruptions, and less reliable during emergencies or periods of heightened geopolitical risk."[ **CHEVRON**](https://www.chevron.com/newsroom/2026/q1/californias-economy-faces-threats-with-new-energy-policy-changes?ref=calregulatory.com) - **California's Lawmakers Urge Attorney General to Investigate AI Astroturf Campaign Targeting Clean Air Rules:** "The campaign targeting SCAQMD was organized by a public affairs consultant affiliated with California Strategies, a major lobbying firm whose clients include Sempra, the parent company of Southern California Gas Co., a leading opponent of the rules. In their letter, lawmakers warn that the potential use of artificial intelligence to submit false or misleading comments in constituents’ names could misrepresent public opinion and undermine the integrity of the public comment process." [**CLEAN TECHNICA**](https://cleantechnica.com/2026/03/18/california-lawmakers-urge-attorney-general-to-investigate-ai-astroturf-campaign-targeting-clean-air-rules/?ref=calregulatory.com) - **Did Fake Comments Sink SoCal Clean Heat Rules? Advocates Want Answers:** "Last year, Southern California’s air regulators rejected landmark rules that would have encouraged the switch from polluting gas heaters to electric heat pumps in the smoggiest region in the country. Now, environmental and public health advocates are pressing state and local officials to investigate whether opposition in the run-up to the decision was largely faked. Members of the regulatory board [voted 7–5 against](https://www.canarymedia.com/articles/heat-pumps/socal-gas-heaters-rules-nox?ref=calregulatory.com) the proposed rules in June, after receiving more than 20,000 public comments opposing them. It was ​'an unusually high number,' said **Rainbow Yeung**, spokesperson for the South Coast Air Quality Management District, which regulates the air quality for more than 17 million residents across Los Angeles, Orange, Riverside, and San Bernardino counties." [**CANARY MEDIA**](https://www.canarymedia.com/articles/heat-pumps/did-fake-comments-sink-socal-clean-heat-rules?ref=calregulatory.com) - **California Brings Multiple Legal Challenges to Block Sable Pipeline Restart:** "California launched a legal effort to stop Sable Offshore Corp.’s restart of the Las Flores Pipeline System serving the offshore Santa Ynez Unit. The response to the recent restart of the pipeline system could signal an escalating conflict between California and the Trump administration over federal emergency powers and state environmental authority." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-brings-multiple-legal?ref=calregulatory.com) - **California Geothermal Leader CTR to Go Public in $4.7 Billion Merger to Power AI and EV Boom:** "The business combination is designed to jumpstart Stage 1 construction at CTR’s flagship 'Hell’s Kitchen' project in the Imperial Valley." [**IMPERIAL VALLEY PRESS** ](https://www.ivpressonline.com/news/california-geothermal-leader-ctr-to-go-public-in-4-7-billion-merger-to-power-ai/article%5F85570d7e-de01-4656-aa5b-7a026fb60374.html?ref=calregulatory.com) - **California Moves Ahead with Balcony Solar Bill:** "The new legislation, Senate Bill 868 – also known as the Plug and Play Solar Act – would allow people in California to install small systems of up to 1,200 watts (AC) to a building’s electrical system and exempt them from requiring to interconnect the small systems to the electrical distribution system." [**PV TECH**](https://www.pv-tech.org/california-moves-ahead-with-balcony-solar-bill/?ref=calregulatory.com) - **California Senate Enviro Committee Democrats Kill Gas Tax Relief Bill:** "Wednesday in the California [Senate Environmental Quality Committee](https://www.senate.ca.gov/media-archive?ref=calregulatory.com), Democrats killed [Senate Bill 1035](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB1035&ref=calregulatory.com) by Senator **Tony Strickland** (R-Huntington Beach), which would have provided immediate relief for California drivers at the gas pump by lowering the price of a gallon of gas by $1.08\. [SB 1035](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB1035&ref=calregulatory.com), the [Gas Tax Relief Act](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB1035&ref=calregulatory.com), would have offered a lifeline for drivers." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ca-senate-enviro-committee-democrats-kill-gas-tax-relief-bill/?ref=calregulatory.com) - **How Blue California and Red Texas Became Green Powerhouses:** "The California and Texas examples illustrate that whether the power sector is heavily regulated by climate-minded policymakers or unshackled in a permissive free market, clean energy now dominates new electricity deployments. That’s because solar and wind have become the cheapest sources of new electricity, battery costs to firm up their intermittency [have likewise plummeted](https://www.canarymedia.com/articles/batteries/chart-surprise-batteries-got-cheaper-again?ref=calregulatory.com), and they don’t face the same [supply chain limitations](https://www.utilitydive.com/news/mitsubishi-gas-turbine-manufacturing-capacity-expansion-supply-demand/759371/?ref=calregulatory.com) as natural gas turbines. Clean energy is the cheapest and fastest option to meet today’s rapidly growing [demand](https://www.eenews.net/articles/data-centers-share-of-us-electricity-seen-doubling-by-2030/?ref=calregulatory.com)." [**YALE CLIMATE CONNECTIONS**](https://yaleclimateconnections.org/2026/03/how-blue-california-and-red-texas-became-green-powerhouses/?ref=calregulatory.com) - **Why California and Texas Actually Agree on Powering Their Future with Batteries**: "In California, energy policy is driven by goals to generate electricity from emissions-free sources, which led the state to become an early adopter of wind, solar and batteries. In Texas, the philosophy is more free-market, and renewables have flourished amid increasing demand for power and in part because the main power grid, ERCOT, makes plugging into the system faster than other parts of the country." [**SAN.COM**](https://san.com/cc/why-california-and-texas-actually-agree-on-powering-their-future-with-batteries/?ref=calregulatory.com) - **New Central Valley Solar Fees Would Burn California Ratepayers:** "Solar paired with storage is the [cheapest, fastest](https://www.evergreenaction.com/blog/clean-energy-is-still-the-cheapest-energy-states-must-deploy-it-fast?ref=cleanpowercalifornia.org) energy you can build today, thanks in part to California’s pioneering support of the technology that goes back two decades. But as the state embraces an abundance agenda to speed housing and clean energy buildouts, affordability needs to be guarded — including from excessive fees that drive up costs. Case in point: a Fresno County Fire Protection District plan to charge solar and storage developers huge fees for basic services." [**THE CURRENT** ](https://www.cleanpowercalifornia.org/new-central-valley-solar-fees-would-burn-california-ratepayers/?ref=calregulatory.com) - **Ormat Signs Amended PPA for Casa Diablo IV Geothermal Power Plant in California:** "[Ormat Technologies](https://www.ormat.com/en/home/a/main/?ref=calregulatory.com) (Ormat) has announced the signing and approval of amendments to existing power purchase agreements with two community choice aggregators for a portion of the output from the 35-MW Casa Diablo IV power plant, part of the Mammoth geothermal complex in California. This is part of Ormat’s strategy of pro-actively re-contracting existing agreements ahead of expiration to secure improved, demand-driven economics." [**THINK GEOENERGY**](https://www.thinkgeoenergy.com/ormat-signs-amended-ppa-for-casa-diablo-iv-geothermal-power-plant-in-california/?ref=calregulatory.com) - **Ormat Technologies Begins Commercial Operations at 320 MWh California BESS:** "Geothermal and battery storage firm Ormat Technologies’ 80MW/320MWh Shirk battery energy storage system in Visalia, California, US, has reached commercial operation." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/ormat-technologies-begins-commercial-operations-at-320mwh-california-bess/?ref=calregulatory.com) - **Sacramento's Idea of a Transition**: "California is dangerously exposed. It has no inbound oil pipelines." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/sacramentos-idea-of-a-transition/?ref=calregulatory.com) - **Seeing Shortage, California Seeks 6 GW of Clean Power Capacity:** "Capacity under the CPUC order will be rated on its ‘effective load carrying capability,' measured in ‘net qualifying capacity.' Determined by both the scaling of ELCC/NQC, a standalone solar plant would be worth about 10% of its AC capacity. This low figure reflects how much daytime solar is already deployed on the grid. In contrast, a four or eight-hour battery is currently rated at 90–95% of its capacity output. Technically, standalone solar is not even eligible for this procurement." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/03/17/seeing-shortage-california-seeks-6-gw-clean-power-capacity/?ref=calregulatory.com) - **The Fight Over California's Community Solar Plan is Heating Up:** "**Kerry Fleisher**, the CPUC’s director of distributed energy resources, defended the agency’s actions at last month’s hearing. She cited analysis proffered by utilities and by the CPUC’s Public Advocates Office, which is tasked with protecting utility customers, that found that the NVBT ran the risk of increasing costs for customers of the state’s three big utilities. 'These are costs that end up on all customer bills,' Fleisher said. ​'So we need to be really mindful at this time, when affordability is such a challenge, to keep costs as low as possible.'" [**CANARY MEDIA**](https://www.canarymedia.com/articles/solar/fight-over-california-community-solar-plan-heating-up?ref=calregulatory.com) - **Utilities Have Made $200B+ in Profit Since 2021, New Report Says:** "In 2025, Southern California Edison (26.11%), Georgia Power (22.57%), and AEP Texas (22.19%) took positions three, four and five as Florida Power & Light (27.44%) and MidAmerican Energy (27.16%) swapped spots at the top." [**UTILITY DIVE**](https://www.utilitydive.com/news/utilities-have-made-200b-in-profit-since-2021-new-report-says/814940/?ref=calregulatory.com) ### March 19, 2026 CPUC Voting Meeting Results: Commissioner John Reynolds' First Meeting as President URL: https://www.calregulatory.com/march-19-2026-cpuc-voting-meeting-results-2/ Last updated: 2026-03-19T21:34:43.000Z CPUC commissioner [**John Reynolds**](https://www.cpuc.ca.gov/about-cpuc/commissioners/page-content/profile-list/president-john-reynolds?ref=calregulatory.com)presided over his first voting meeting today following his appointment to president. Additionally, Commissioner [**Christine Harada**](https://www.cpuc.ca.gov/about-cpuc/commissioners/page-content/profile-list/commissioner-christine-harada?ref=calregulatory.com) made her debut appearance, bringing prior experience from the California Government Operations Agency and the U.S. Office of Management and Budget. --- As detailed in [our update yesterday](https://www.calregulatory.com/current-status-of-march-19-2026-cpuc-voting-meeting-agenda/), the CPUC delayed action on several items. Two matters move to April 9: - [Draft Resolution E-5440](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?ref=calregulatory.com) ([Integration Capacity Analysis](https://irecusa.org/blog/regulatory-engagement/key-lessons-from-the-california-integrated-capacity-analysis/?ref=calregulatory.com) remediation plans for PG&E, SCE, and SDG&E); and - [SDG&E's 2023 ERRA compliance](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) (**$215 million** cost recovery). And [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com) (DG statistics website funding) is now set for **April 30**. Items that carried today include actions on data-center and transmission infrastructure, a pause of the spring 2026 residential electric [Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com), and an extension of California's Flex Alert campaign. Meeting results also include issues related to Provider of Last Resort, SCE's finances and EV load management, PG&E's "RAMP" closure, the Self-Generation Incentive Program, petroleum pipelines, and crude oil transportation. A recurring theme is the advancement of infrastructure ahead of full economic resolution. Increasingly cost recovery, valuation, and rate impacts are deferred to later consideration, while approvals move forward based on reliability, load growth, and system need. For easy reference, the table below breaks down the day's major transmission and data-center moves, followed by a more comprehensive summary of all notable energy items. | Project / Asset | Primary Driver | Financial Scale | Recovery Mechanism | Strategic Risk Profile | | ------------------------------------------ | --------------------------- | ----------------- | ---------------------- | ---------------------------------------------------------------- | | **Power Santa Clara Valley** (LS Power) | Reliability / Load Growth | $1.593B (Cap) | CAISO Rates (FERC) | **Moderate:** High cost but reliability need is established. | | **Power the South Bay** (LS Power) | System Overload | $813.2M (Cap) | CAISO Rates (FERC) | **Low:** Statutory presumption of need applied. | | **Alberhill System** (SCE) | Resilience / N-1 Redundancy | $481.7M | GRC / Rate Base | **Major Utility Win:** Rejects TURN’s lower-resilience metrics. | | **Ringwood Station** (STACK Data Center) | 90 MW Load Transfer | Customer Funded | 75% Revenue Refund Cap | **Sequential Execution:** Build first, sort economics later. | | **Sunnyvale Data Center** (Menlo Equities) | 49 MW Data Center | Actual Cost basis | Revenue-Linked True-up | **High Developer Risk:** 15-year window; no speculative refunds. | --- ## TRANSMISSION INFRASTRUCTURE The meeting's regular agenda included two decisions involving LS Power Grid California: the 'Power Santa Clara Valley Project' and the 'Power the South Bay Project,' with each carrying 5-0\. "These decisions," said **Commissioner Harada**, "are about what every Californian expects – that when we flip on a switch, the light turns on. When we plug in our EV – it actually charges. That we've got a family member who needs medical equipment to run through the night – that it does." Commissioner Harada framed the approvals as foundational to reliability and economic growth, emphasizing that transmission should not constrain load growth in rapidly expanding regions. ### Power Santa Clara Valley Project A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K738/602738106.PDF?ref=calregulatory.com) grants [LS Power Grid California](https://www.lspowergrid.com/utilities/ls-power-grid-california/?ref=calregulatory.com) a certificate to construct the [Power Santa Clara Valley Project](https://www.lspowergrid.com/wp-content/uploads/Power-Santa-Clara-Valley-2-Pager.pdf?ref=calregulatory.com), a **$1.593 billion** (cap) transmission upgrade initially approved to address reliability issues in the San José area's 115-kV system. The project was subsequently modified in November 2024 to respond to load forecast increases from 2,100 MW to potentially 4,200 MW through a new HVDC link between major substations. The decision finds the project necessary despite significant environmental impacts, adopts an environmentally superior alternative configuration (AC-1) with mitigation measures, and authorizes cost recovery through CAISO transmission rates subject to FERC oversight. While the decision declines to apply the statutory presumption of need due to inconsistencies in project cost estimates (including exclusion of PG&E interconnection costs), it nevertheless finds an independent reliability need based on substantial record evidence. --- ### Power the South Bay Project A separate [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K351/599351814.PDF?ref=calregulatory.com) grants LS Power a Certificate of Public Convenience and Necessity to construct the [Power the South Bay Project](https://www.lspowergrid.com/wp-content/uploads/Power-the-South-Bay-2-Pager.pdf?ref=calregulatory.com), a roughly 12-mile 230-kV transmission line connecting PG&E's Newark substation to [Silicon Valley Power](https://www.siliconvalleypower.com/?ref=calregulatory.com)'s Northern Receiving Station to address reliability risks and rising demand in the San José area. Identified by the CAISO in its 2021–2022 Transmission Plan, the project will largely be built underground to relieve system overloads and support future load growth. Construction is authorized beginning March 2026 with a CAISO-required in-service date of **June 1, 2028**. The maximum cost cap is **$813.24 million** ($677.7 million base plus 20% contingency), recovered through CAISO transmission rates subject to FERC oversight. The decision applies the statutory presumption of need under the Public Utilities Code without dispute and finds the project necessary to resolve identified system overloads.While most environmental impacts are mitigated to less-than-significant levels, air-quality impacts remain significant and unavoidable in part because the Commission lacks jurisdiction over Silicon Valley Power’s mitigation measures. --- ### Alberhill System Project A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K823/602823258.pdf?ref=calregulatory.com) grants SCE a CPCN to construct the [Alberhill System Project](https://ia.cpuc.ca.gov/environment/info/ene/alberhill/Docs/CPUC%5FAlberhill%20System%20Project%20Staff%20Report%5F09152023.pdf?ref=calregulatory.com), a new 1,120 MVA 500/115 kV substation and associated transmission infrastructure in western Riverside County, at a cost cap of **$481.7 million** in 2023 dollars, including 15% contingency. - The project addresses the Valley South System, an islanded radial network serving roughly 560,000 people and the only one of SCE's 56 sub-transmission systems with no tie-lines to adjacent networks. The system is already operating beyond safe capacity thresholds. Peak demand hit **1,103 MW** in Summer 2024 (99% of nameplate capacity assuming tie-lines that don't exist, and 23% above the 896 MW single-transformer emergency rating that actually governs operations). - The Commission finds that capacity, reliability, and resilience needs constitute overriding considerations under CEQA, sufficient to justify unavoidable impacts on air quality, noise, and aesthetics. - TURN's arguments were rejected across the board. Valley Substation has five 560 MVA transformers (two serving Valley South, two serving Valley North, and a fifth spare required by SCE's internal planning criteria for emergency backup). - TURN argued the spare should be treated as a permanent load-serving asset, which would triple the system's apparent available capacity and undercut the case for Alberhill. The decision rejects this, finding that stripping the spare of its backup function leaves 560,000 customers with no fallback if a load-serving transformer fails. - The decision also rejects TURN's lower resilience event frequencies and alternative metrics as bases for denying the project. ### **Instant Analysis of Transmission Infrastructure Decisions** The CPUC is moving into a preemptive transmission build cycle across multiple regions, approving large projects based on forecasted load, system vulnerability, and resilience to low-probability events. Cost scrutiny can disrupt formal presumptions but is not blocking approvals. Environmental impacts continue to be outweighed by reliability needs. The Alberhill project demonstrates the evolution: resilience and contingency risk are now sufficient on their own to justify major infrastructure. --- ## DATA CENTERS ### Ringwood Switching Station in San Jose [Resolution E-5447](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K207/602207312.pdf?ref=calregulatory.com) approves PG&E [Advice Letter 7653-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7653-E.pdf?ref=calregulatory.com), a non-standard Engineering, Procurement, and Construction (EPC) agreement with [STACK Infrastructure](https://www.stackinfra.com/?ppc%5Fkeyword=stack%20infrastructure&gad%5Fsource=1&gad%5Fcampaignid=17068178771&gbraid=0AAAAACVjc4r35zmm0hA6afEsh5C%5FJYYDv&gclid=Cj0KCQjwve7NBhC-ARIsALZy9HU7WRkXmG%5Fsm5ngTUoAsZ4oQDHik5OqSjE7iAyzB9rW0hmLrRJYKLUaAotaEALw%5FwcB&ref=calregulatory.com) under the exceptional case provisions of Electric Rules 15 and 16\. STACK will design, procure, and construct the 115 kV Ringwood Switching Station in San Jose to serve a 90 MW data center load, then transfer ownership to PG&E. The switching station is expected to be operational by **April 2026**. - This resolution is scoped to construction and transfer terms only. Cost responsibility, refunds, and the broader energization framework were addressed in the prior [Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K498/586498115.PDF?ref=calregulatory.com) (*see CRI's coverage* [*here*](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/)), which approved an Agreement to Perform Work and Special Facilities Agreement and capped refunds at 75% of PG&E's annual net revenues from STACK. - Cal Advocates protested, arguing PG&E should not earn a return on a customer-financed asset and that the refund framework could expose ratepayers to cost overruns. The resolution declines to address either issue here, finding them outside the scope of an EPC agreement approval and properly reserved for FERC transmission owner rate proceedings and other ratemaking venues. The resolution notes that the refund cap and PG&E's stated post-construction cost review provide adequate safeguards. **INSTANT ANALYSIS:** The Commission is reinforcing a clear pattern: once a load-serving framework is approved, follow-on execution agreements move through approval with little resistance. The two-year gap between EPC execution and regulatory filing underscores the sequencing: developers can build first and regularize later. Rate-base treatment, returns, and cost recovery remain unresolved and will surface at FERC, but for large-load customers, a pathway is now well-established: - Fund; - Build; - Transfer; and - Sort out the economics. --- ### Sunnyvale Data Center for Menlo Equities [Resolution E-5433](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K365/602365009.pdf?ref=calregulatory.com) approves PG&E’s agreement to energize a [49 MW data center in Sunnyvale for Menlo Equities](https://therealdeal.com/san-francisco/2026/02/13/menlo-equities-toggles-to-data-center-plan-in-silicon-valley/?ref=calregulatory.com), but rewrites the refund mechanics to address risk. The standard "Base Annual Revenue Calculation" method would allow near-immediate recovery by treating one year of revenue as evidence of a long-term stream, meaning refunds could exceed actual first-year net revenues by a wide margin. Resolution E-5433 rejects that structure and instead ties recovery to realized revenues. Menlo pays upfront for transmission upgrades, including a 0.6-mile 115 kV underground line deemed the optimal design due to siting constraints (and fully eligible for refund), while a separate redundant line is treated as a non-refundable Special Facility. PG&E will design and build the facilities, and all work is performed on an actual cost basis. Refunds are capped at **75%** of annual net transmission revenues, with an added Income Tax Component of Contribution gross-up (24%) that increases the allowable refund but does not reflect infrastructure cost. The refund window is extended to 15 years. PG&E opposed the cap (citing precedent, existing protections, and development risk) and proposed a 100% alternative. The resolution rejects all arguments and holds the modified structure, while removing additional ownership charges on any unrefunded balance to preserve a path to full recovery if load materializes **INSTANT ANALYSIS:** This resolution resets the recovery model for large loads. The Commission is discarding forward-looking revenue assumptions and replacing them with a backward-looking annual true-up. Refunds now follow cash actually collected, not projected demand trajectories. That closes the gap where one year of revenue could justify full repayment. The 75% cap splits the economics. Customers carry performance risk if load falls short. At the same time, a portion of revenue is retained to cover broader system costs tied to transmission service. The Income Tax Component of Contribution gross-up softens the cap, and the 15-year window plus removal of ownership charges keeps the project financeable. Large load developers now face a slower, revenue-dependent recovery path in California. --- ## CLIMATE CREDIT A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K742/602742724.pdf?ref=calregulatory.com) pauses the spring 2026 residential electric [Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) for PG&E, SCE, and SDG&E customers. The credits (currently distributed in April and October) will be held so the CPUC can redirect them into high-billed summer months, with a follow-on decision expected shortly. This move traces back to [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com), which requires electric Climate Credits to be distributed in high-billed months to maximize affordability. Delivering the first post-enactment credit in April (an historically low-bill shoulder month) would conflict with the new statutory mandate. The 2026 credits are also substantially smaller than 2025: - PG&E dropped from $58.23 to **$36.18**; - SCE from $56.00 to **$36.00**; and - SDG&E from $81.38 to **$49.36**. These constitute **40–60%** reductions. Smaller credits make delivery timing more consequential; landing them during peak billing periods maximizes their visibility and impact. CalCCA and the Environmental Defense Fund opposed the move, citing procedural concerns and potential harm to customers whose bills don't peak in summer. The decision acknowledges variation across customer groups but holds that average statewide billing patterns justify the pause. **INSTANT ANALYSIS:** The Climate Credit is being converted from a conservation-signal instrument into an affordability tool. The legacy design intentionally placed credits in low-usage months to preserve price signals but AB 1207 inverts that approach entirely. Once timing resets into summer peaks, the credit becomes a more visible and politically salient rate offset as bills climb. --- ## FLEX ALERTS A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K742/602742657.pdf?ref=calregulatory.com) extends California's [Flex Alert](https://www.flexalert.org/?ref=calregulatory.com) paid media campaign through December 31, 2026, with a **$15 million** budget, down from $22 million in prior years, reflecting the end of the [Power Saver Rewards](https://www.highsierraenergy.org/power-saver-rewards?ref=calregulatory.com) program and an inflation adjustment to legacy funding levels that arose from a 2021 decision ([D.21-03-056](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M373/K745/373745051.PDF?ref=calregulatory.com)). SCE must execute a contract extension with [Doyle Dane Bernbach](https://en.wikipedia.org/wiki/DDB%5FWorldwide?ref=calregulatory.com) (or a successor) for services beginning no later than **June 1, 2026**. Cost allocation follows the existing CAISO peak load split: - 45% SCE; - 45% PG&E; and - 10% SDG&E These amounts are recovered from all distribution customers, including Community Choice Aggregator and Direct Access entities. The decision declines to modify program design for 2026 due to timing constraints, and does not adopt party recommendations on competitive bidding, alternative funding structures, or targeted marketing (though none of those doors are closed for 2027). Cal Advocates and SDG&E opposed the extension on affordability and [Emergency Order N-5-24](https://www.dwt.com/blogs/energy--environmental-law-blog/2024/11/newsom-order-targets-california-electricity-cost?ref=calregulatory.com) grounds; the CPUC overrode on reliability. **INSTANT ANALYSIS:** The Flex Alert apparatus survives for summer 2026 but at a budget reset closer to legacy levels now that emergency-era Demand Response programs have wound down. The Commission's willingness to override Emergency Order N-5-24 affordability arguments on reliability grounds tells a revealing story: behavioral DR retains institutional support when the grid is stressed, even as the cost justification diminishes. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/03/iterograph_Wed-Mar-18-2026--66-.png) --- ## PROVIDER OF LAST RESORT [Resolution E-5411](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K178/602178048.pdf?ref=calregulatory.com) denies SDG&E's request to preemptively establish a memorandum account to track incremental costs from a potential mass return of customers to Provider of Last Resort service. The resolution affirms staff's earlier rejection, finding that SDG&E's proposal conflicted with a 2024 decision ([D.24-04-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M529/K986/529986322.PDF?ref=calregulatory.com)), which contemplated such accounts during an involuntary return, not as a preemptive standing measure. The CPUC clarifies that SDG&E may file a Tier 1 Advice Letter when a Community Choice Aggregator Tier 2 financial trigger indicates material risk of involuntary return. The resolution reinforces that memorandum accounts are optional tools for calculating reentry fees, not the primary cost recovery mechanism. It notes that utilities recover procurement costs through existing ERRA processes regardless of whether an account is opened (the memorandum account only affects reentry fees assessed directly to returned customers). The resolution also points to existing safeguards, including financial monitoring of Community Choice Aggregators and a six-month notice period, as sufficient to prepare utilities for potential customer returns. Staff commits to notifying the Provider of Last Resort when it believes a CCA is at material risk of failure, subject to confidentiality obligations. **INSTANT ANALYSIS:** This move addresses timing and discretion. The CPUC keeps the option to track actual costs but refuses to let utilities default into that path in advance. SDG&E has to wait for a real CCA distress signal before electing the memorandum account, which preserves the CPUC's ability to steer cost recovery back toward the Financial Security Requirement-based framework in most cases. That keeps re-entry fee mechanics predictable and avoids opening the door to broader, after-the-fact cost claims tied to volatile procurement conditions. - The resolution also shows that the CPUC is comfortable relying on its monitoring regime rather than utility pre-positioning. Staff commits to notifying IOUs if a CCA shows distress, which puts the CPUC in the role of gatekeeper for when Provider of Last Resort cost-tracking tools activate. - The naming of [San Diego Community Power](https://sdcommunitypower.org/?ref=calregulatory.com) and [Clean Energy Alliance ](https://thecleanenergyalliance.org/?ref=calregulatory.com)as contrasting scenarios (catastrophic failure versus small planned return) provides a window into the CPUC's proportionality logic: the memorandum account is a heavy tool reserved for heavy situations. The net effect: utilities retain the tool, but not the initiative. Expect this to matter in a real CCA stress event, where the timing of that Tier 1 filing and the choice between Financial Security Requirements vs. tracked costs could shape who ultimately bears procurement risk. --- ## UTILITY FINANCES A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K762/602762078.pdf?ref=calregulatory.com) authorizes SCE to issue up to **$9.85 billion** in debt and **$1.155 billion** in preferred equity, $525 million less than originally requested after SCE voluntarily reconciled its forecast to its 2025 General Rate Case final decision. Over 55% of the debt authority (**$6.075 billion**) is earmarked for refinancing previously issued securities; the remainder funds capital expenditures for Transmission & Distribution reliability, wildfire mitigation, grid modernization and DER integration, and covers outstanding wildfire liability payments from the 2017/2018 fires. The authorization spans a broad instrument menu (secured and unsecured debt, commercial paper, hybrid securities, preferred equity) with hedging, swaps, and credit enhancements. **INSTANT ANALYSIS:** The CPUC is reaffirming settled doctrine: utilities get wide latitude to raise capital ahead of need while prudency and cost recovery are litigated later. Cal Advocates fought hard (arguing evidentiary deficiencies, double-recovery risk, and even requesting denial without prejudice) and lost on every point. Small Business Utility Advocates' concerns about overborrowing landed similarly. The decision treats both sets of objections as conflating financing authority with cost recovery. By walling off financing from recovery, the CPUC preserves future leverage over billions that will flow into GRCs, Cost of Capital cases, and wildfire proceedings. Expect those venues to carry the substantive disputes: - Equity thickness; - Debt cost pass-through; - Hybrid securities treatment; and - Whether ratepayers absorb financing tied to wildfire exposure. The Affiliate Transaction Rules and authorized capital structure compliance add another constraint layer that could become contested if SCE's equity ratio drifts. Near-term, SCE gets the flexibility it needs through 2028\. Medium-term, the decision sets up heavier litigation over how much of that financing ultimately surfaces in bills. --- ## ELECTRIC VEHICLE LOAD MANAGEMENT [Resolution E-5452](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K741/602741239.pdf?ref=calregulatory.com) approves SCE's ORCHARD program, a utility-orchestrated EV charging scheme funded by **$22.9 million** in [Low Carbon Fuel Standard](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification/charging-infrastructure-deployment-and-incentives/low-carbon-fuel-standard?ref=calregulatory.com) holdback revenue. The program embeds a software layer into SCE's [DERMS](https://www.next-kraftwerke.com/knowledge/derms?ref=calregulatory.com) to directly coordinate residential EV charging times, targeting circuits with less than 1 MW of available capacity and at least 100 EVs. The goal is to mitigate the secondary distribution peak created when drivers pile onto off-peak Time-of-Use windows starting at 9 p.m. SCE's enrollment target is 25,000 customers with annually declining participation incentives. The resolution denies SCE's proposed bidirectional equipment rebates without prejudice, finding the Vehicle-to-Everything justification insufficient and that SCE: - Failed to clarify whether participants would operate in Momentary Parallel or Isolated mode; - Couldn't demonstrate Original Equipment Manufacturer willingness to enable grid-parallel software updates, and - Proposed no export compensation mechanism. **INSTANT ANALYSIS:** This resolution is the CPUC formally endorsing utility-controlled EV load orchestration as a distribution deferral tool, a significant step beyond passive TOU signals into active, localized grid management. The bidirectional denial keeps vehicle-grid integration squarely in the managed charging lane until interconnection costs and export compensation frameworks mature, likely through [R.25-08-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M576/K867/576867418.PDF?ref=calregulatory.com) (the "Update Distribution Level Interconnection Rules and Regulations" docket). If ORCHARD performs, it gives SCE a scalable alternative to transformer upgrades with direct implications for distribution planning assumptions and future rate base. --- ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/03/iterograph_Wed-Mar-18-2026--11-.png) ## RISK ASSESSMENT MITIGATION PHASE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K740/602740008.pdf?ref=calregulatory.com) closes PG&E's 2024 RAMP ([A.24-05-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M531/K552/531552896.PDF?ref=calregulatory.com)), the front-end risk framework for its Test Year 2027 General Rate Case. The RAMP report covers PG&E's top 12 safety risks and mitigation cost-benefit analyses for 2027–2030 under the new Phase II Risk-Based Decision Making Framework. This methodology monetizes safety and reliability in dollar terms. The CPUC's Safety Policy Division found the RAMP filing compliant but noted significant concerns: - Expressing safety in dollars rather than unitless scores reduces its relative influence on risk rankings; - PG&E's proposed and alternative mitigations are not modeled against the same risk areas (making cost-benefit ratios incomparable); and - Previously approved mitigation programs appear to carry forward without rigorous re-justification even when their cost-benefit ratios fall below 1.0\. Intervenors reinforced these concerns and pressured on undergrounding-versus-covered-conductor, Public Safety Power Shutoff/Enhanced Powerline Safety Settings modeling, PG&E's hybrid Value of Statistical Life, ratepayer bill impacts, and circuit-segment granularity. An April 2025 ruling required PG&E to address four deficiencies: - Provide risk-neutral scaling analysis; - Identify regulatory requirements for each mitigation; - Supply disaggregated reliability cost calculations; and - Remove risk tolerance as a mitigation justification. PG&E complied, using the newly released "[Interruption Cost Estimate](https://www.icecalculator.com/?ref=calregulatory.com)" 2.0 calculator for disaggregated reliability (a change the decision cites as subject to GRC litigation). The decision declines Cal Advocates' push to impose new RAMP requirements through this closure, ruling those belong in a rulemaking applicable to all utilities. **INSTANT ANALYSIS:** Monetizing safety collapsed PG&E's implied Value of Statistical Life from $100 million to **$15.2 million**, fundamentally reranking which mitigations clear the cost-benefit bar. The main GRC fights are now established: - Undergrounding's **$6.5 billion c**ost versus **$1.7 billion** in covered conductor; - Whether risk-averse scaling inflates budgets beyond risk-neutral support; - Interruption Cost Estimate 2.0 calculator effects; and - Whether alternatives will ever be modeled on equal footing. --- ## SELF-GENERATION INCENTIVE PROGRAM A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K444/602444218.pdf?ref=calregulatory.com) denies [ENGIE North America](https://www.engie-na.com/?ref=calregulatory.com)’s [petition to modify](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K757/542757352.PDF?ref=calregulatory.com) a 2021 CPUC decision ([D.21-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M387/K064/387064243.PDF?ref=calregulatory.com)), which sought an exemption for wastewater treatment plants from the SGIP requirement that biogas used in internal combustion engines meet a **96%** methane standard. ENGIE argued that typical wastewater biogas (approximately **60%** methane) makes compliance economically infeasible, even with SGIP incentives. The decision does not reach the merits of that argument. Instead, it denies the petition on procedural grounds. Consequently, the 96% methane standard remains in place and the proceeding stays open. **INSTANT ANALYSIS:** The 96% methane standard remains intact, continuing to screen out most raw wastewater biogas projects from SGIP eligibility. Any future effort to revisit SGIP fuel-quality thresholds will need a forward-looking policy track or new rulemaking phase, not a modification petition tied to a single project. --- ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/03/iterograph_Wed-Mar-18-2026--14-.png) ## PETROLEUM PIPELINES A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K814/602814679.PDF?ref=calregulatory.com) approves Shell California Pipeline Company LLC's request to withdraw its Carson-to-LAX and Carson-to-Van Nuys petroleum pipelines from common carrier service and, upon satisfaction of specified conditions, terminate Shell California's status as a public utility entirely. The factual record is unusually clean. Neither pipeline has ever served a non-affiliated customer since being offered for common carrier service (the Van Nuys line since 1992, the LAX line since 1996). Both lines serve only Shell affiliates and are not part of any larger interconnected pipeline system. No protests were filed. No physical or operational changes are planned, which means CEQA does not apply. **INSTANT ANALYSIS:** This decision confirms that common-carrier status must be justified by actual public use: it is not a default regulatory condition. The decision relies explicitly on [*Richfield Oil Corp. v. Public Util. Com.* (1960)](https://law.justia.com/cases/california/supreme-court/2d/54/419.html?ref=calregulatory.com) for the principle that, where a pipeline no longer provides service to the public, continued regulation is unnecessary. As a result, Shell California will no longer be a CPUC-regulated entity once conditions are met. The facts in this case (zero third-party customers across three decades, no interconnections, no protests) are about as frictionless as a withdrawal gets. For operators holding legacy common carrier classifications on affiliate-only systems, the decision opens a clear path to reclassification as private infrastructure. For assets with any history of third-party service or system interconnection, the path will be considerably more contested. --- ## CRUDE OIL TRANSPORTATION A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K430/602430281.pdf?ref=calregulatory.com) approves Crimson California's request to withdraw the southern segment of the Seal Beach Pipeline (approximately **5.87 miles** of crude oil line running from Seal Beach to Signal Hill) from public utility service. The pipeline's sole customer, [DCOR](https://dcorllc.com/?ref=calregulatory.com), ceased using the line and withdrew its protest, leaving the application uncontested. The Commission finds the segment is not necessary or useful for public utility service, has no current or prospective customers, and is not part of a broader interconnected system. Crimson will purge the pipeline of hydrocarbons, fill it with nitrogen, and isolate it in place under "out-of-service deferment" status overseen by the [Office of the State Fire Marshal](https://osfm.fire.ca.gov/?ref=calregulatory.com), while retaining ownership. Continued operation was uneconomic due to low throughput, saltwater-driven corrosion, and costly upcoming relocations and repairs. Crimson has indicated it will seek recovery of deferment costs in a future General Rate Case. **INSTANT ANALYSIS:** The CPUC is letting a common carrier oil pipeline segment exit public utility status once it loses its sole shipper and serves no broader network function. The Commission is not forcing continued operation for optionality. If the asset is economically dead and commercially irrelevant, it can be idled. - By approving withdrawal while the asset remains in place under OSFM oversight, the Commission is limiting its active involvement to assets with live public utility function. That approach will recur when other operators look to reclassify or sideline assets to reduce compliance burden. - Cost recovery is unresolved. Ratepayers could still absorb shutdown and preservation costs. ### Current Status of March 19, 2026 CPUC Voting Meeting Agenda URL: https://www.calregulatory.com/current-status-of-march-19-2026-cpuc-voting-meeting-agenda/ Last updated: 2026-03-19T21:39:14.000Z Some substantive energy items on the March 19 CPUC voting meeting agenda have [been delayed until April](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K825/602825562.PDF?ref=calregulatory.com). ### CPUC Voting Meeting Hold List - **ICA Tools:** [Draft Resolution E-5440](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?ref=calregulatory.com) approves remediation plans submitted by PG&E, SCE, and SDG&E to fix problems in their "[Integration Capacity Analysis](https://irecusa.org/blog/regulatory-engagement/key-lessons-from-the-california-integrated-capacity-analysis/?ref=calregulatory.com)" tools, which estimate how much distributed energy can be added to the grid without upgrades. This item moves to the **April 9** meeting agenda. - **ERRA Compliance:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) approving SDG&E's 2023 ERRA compliance application also moves to the April 9 agenda. As currently worded, the PD would grant SDG&E cost recovery of **$215 million**. - **Distributed Generation**: [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com) increases funding for the California [Distributed Generation Statistics platform](https://www.californiadgstats.ca.gov/?ref=calregulatory.com). It moves to the **April 30** meeting agenda. If authorized, this item would nearly triple the DG website's current funding and position the platform as a long-term backbone for forecasting, planning, and enforcement. ### Consent Agenda Additions Additionally, the CPUC moved two key Regular Agenda matters to the Consent Agenda, meaning there's a very high likelihood that both will carry. Those items are: - [Draft Resolution E-5447](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K895/598895478.PDF?ref=calregulatory.com), which authorizes an agreement between PG&E and [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com) for construction of the 115 kV Ringwood Switching Station in San Jose; and - [Draft Resolution E-5433](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K319/599319897.PDF?ref=calregulatory.com), which approves PG&E’s agreement to energize a new 49-MW data center and computing lab in Sunnyvale for [Menlo Equities](https://www.menloequities.com/?ref=calregulatory.com). Our full preview of the March 19 meeting is available at the link below. [Transmission-Level Planning Problems on March 19 AgendaDraft Resolution E-5447 authorizes PG&E’s non-standard Engineering, Procurement, and Construction agreement with STACK Infrastructure.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-66.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Mar-04-2026--54-.png)](https://www.calregulatory.com/march-19-2026-cpuc-voting-preview-transmission-level-planning-problems-take-center-stage/) ### WEDNESDAY AGGREGATE: PG&E Challenges CPUC Denial of $172M in Vegetation Management Costs URL: https://www.calregulatory.com/wednesday-aggregate-17/ Last updated: 2026-03-19T21:40:51.000Z Today's update covers: - PG&E's wildfire mitigation costs; - Zonal decarbonization pilots; and - SoCalGas's Distribution Integrity Management Program. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/03/iterograph_Wed-Mar-04-2026--51--1.png) --- ### WILDFIRE MITIGATION PG&E [filed for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K365/602365928.PDF?ref=calregulatory.com) of [D.26-02-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K079/599079334.PDF?ref=calregulatory.com), seeking to overturn the CPUC's denial of approximately **$172 million** in cost recovery for 2022 Enhanced Vegetation Management work. PG&E's original application sought recovery of about **$353 million** in Enhanced Vegetation Management expenditures exceeding the 120% threshold authorized in the 2020 General Rate Case. The initial proposed decision would have disallowed the full amount; a revised PD, adopted February 5, reduced the disallowance but still denied recovery for work performed after October 2022, when the CPUC determined PG&E should have recognized diminishing cost-effectiveness and scaled back. (*See CRI's coverage* [*here*](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/)*.*) [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-65.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-03-2026-4.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) PG&E advances three independent grounds for reversal. - On jurisdiction, PG&E argues the Legislature transferred Wildfire Mitigation Plan oversight to the [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) (Energy Safety) in 2021, leaving the CPUC authority to review how utilities implement approved work, not whether that work should have been performed. The disallowance is based on disagreement with the Energy Safety judgment, which the statute assigns to Energy Safety alone. - On abuse of discretion, PG&E notes the Commission ratified its 2022 Wildfire Mitigation Plan without raising Enhanced Vegetation Management concerns, then disallowed costs four years later. The record shows Energy Safety was presented with the identical cost-effectiveness arguments (TURN urged Energy Safety to cut PG&E's Enhanced Vegetation Management target by 99%) and Energy Safety rejected them. PG&E argues it would have been both procedurally impracticable and substantively futile to seek a mid-year change. - On constitutional grounds, PG&E raises takings and due process claims, distinguishing [*Duquesne*](https://www.law.cornell.edu/supremecourt/text/488/299?ref=calregulatory.com) by arguing that PG&E was compelled by a regulator to perform specific work under threat of penalties, unlike the discretionary utility investments at issue in that case. **INSTANT ANALYSIS:** This is a jurisdictional fight that will define CPUC authority over every wildfire mitigation dollar. If PG&E prevails, Energy Safety will control what gets done, the Commission will review how. If the decision holds, utilities face retroactive cost risk on all Wildfire Mitigation Plan spending, rationally incentivizing underinvestment in Energy Safety-approved safety work and defeating the purpose of the 2019 restructuring. The constitutional claims add a second vector: if takings or due process arguments gain traction on appeal, the CPUC's disallowance authority could be constrained well beyond Wildfire Mitigation Plans. --- ### LONG-TERM GAS PLANNING A new [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K365/602365926.PDF?ref=calregulatory.com) in the Long-Term Gas Planning docket seeks additional input from stakeholders to support implementation of [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com), with a focus on how utilities should recover costs associated with zonal decarbonization pilot projects. The ruling reflects that prior comments were insufficient for resolving key policy questions, particularly around how to treat behind-the-meter zero-emission alternative costs, which SB 1221 prohibits from being recovered as traditional capital investments afforded a full rate of return. The threshold question is whether two provisions of the statute are in conflict. - [Section 663](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-3/article-11/section-663/?ref=calregulatory.com)(b)(8) prohibits capital cost recovery with a rate of return for BTM expenditures. - While Section 663(b)(9) directs the Commission to establish an appropriate rate of return and recovery period for implementing zero-emission alternatives. The ALJ is asking parties to address whether these provisions can be harmonized, and if so, how. The Commission is pressing parties to weigh in on whether utilities should be allowed to recover BTM costs from ratepayers at all, and if so, what accounting treatment should apply (including expensing versus regulatory asset treatment with defined amortization periods and depreciation schedules). The ruling lays out three potential frameworks for compensating utilities if BTM costs are recoverable: - **Option 1**: Treating BTM expenditures as expenses amortized over time with a carrying cost equal to the utility's authorized cost of debt (currently **5.04%** for PG&E, **5.02%** for SoCalGas, and **4.59%** for SDG&E per a 2025 decision, [D.25-12-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K833/591833054.PDF?ref=calregulatory.com)). - **Option 2**: Granting regulatory asset treatment with a hybrid rate of return set at the midpoint between the utility's cost of long-term debt and its authorized capital rate of return, resulting in **6.325%** for PG&E, **6.27%** for SoCalGas, and **6.00%** for SDG&E, compared to their full capital returns of 7.61%, 7.52%, and 7.41% respectively. BTM assets under this option would be amortized over a shorter period and depreciate faster than traditional gas capital assets. - **Option 3:** Combining cost-of-debt recovery with a performance-based shareholder incentive tied to measurable outcomes (infrastructure retirement, customer conversions, and budget adherence). Under this model, utilities could earn up to **25%** of net system cost savings, adjusted by a tiered performance multiplier, while the remaining benefits flow to ratepayers. The ruling illustrates the concept with a scenario producing **$30 million** in net savings and a mid-tier performance score, yielding a **$3.75 million** shareholder reward. Comments are due **March 27**, and replies are due **April 3**. **INSTANT ANALYSIS:** This ruling shifts the proceeding into financial design territory. The question is no longer whether pilots happen, but how utilities get paid, and the statutory tension between 663(b)(8) and 663(b)(9) is the fulcrum. Capital-style returns for BTM expenditures are almost certainly off the table given the explicit statutory prohibition. The real debate is between straight cost-of-debt recovery and performance-based incentives. Option 3 stands out; the ALJ devoted the most detailed treatment to it, building out a full formula and worked example, which suggests where the Commission's analytical thinking may be heading. For utilities, the spread between cost-of-debt (approximately 5%) and the Option 2 hybrid (approximately 6% to 6.3%) represents the financial stakes of this design choice. For ratepayer advocates, the question is whether any return above cost of debt is justified for assets the utility will not own or maintain. --- ### NATURAL GAS DISTRIBUTION INTEGRITY A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K280/602280083.PDF?ref=calregulatory.com) in SoCalGas's Distribution Integrity Management Program Balancing Account (DIMPBA) proceeding finds that Cal Advocates' testimony is internally inconsistent and requires clarification before the proceeding can move forward. The ruling identifies major discrepancies in Cal Advocates' testimony, including conflicting recommendations on how much of SoCalGas' requested costs should be disallowed and unclear calculations underlying those figures. The ruling also notes SoCalGas's allegation that Cal Advocates recommended disallowing capital revenue requirements already approved by [Resolution G-3610](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K964/574964459.PDF?ref=calregulatory.com). In response, the ruling directs Cal Advocates to submit supplemental testimony clearly explaining what portion of SoCalGas' requested DIMP costs should be deemed unreasonable and how prior CPUC approvals factor into that assessment. Cal Advocates must serve supplemental testimony by **April 17**, with supplemental rebuttal testimony to follow by **May 18**. The ruling also modifies the proceeding schedule, establishing a meet-and-confer deadline of **May 28**, a joint case management statement due **June 1**, a potential evidentiary hearing window in July 2026, and briefing through September 2026\. The joint case management statement must address whether parties will stipulate to the scoped issues and whether an evidentiary hearing is necessary. **INSTANT ANALYSIS:** The ALJ is forcing Cal Advocates to fix inconsistent testimony, which weakens their current position but gives them a chance to reframe the case. SoCalGas gains near-term breathing room, as the Commission is not relying on the existing disallowance claims. The real issue is whether prior approvals of DIMP costs (particularly those under Resolution G-3610) hold. If they do, SoCalGas is in a strong position. If not, a meaningful reduction in recovery remains in play. ### San Diego Gas & Electric: PCIA Bill Transparency URL: https://www.calregulatory.com/san-diego-gas-electric-pcia-bill-transparency/ Last updated: 2026-03-17T22:27:49.000Z SDG&E filed Advice Letter 4817-E today for approval to change how the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) is presented to bundled customers, in compliance with [D.25-09-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K153/601153093.PDF?ref=calregulatory.com) (SDG&E's 2024 General Rate Case Phase 2 decision, from last September). --- Instead of embedding PCIA costs within bundled generation rates, SDG&E proposes to show a distinct, volumetric PCIA line item on bundled customer bills and in its Electric Energy Commodity Cost tariffs. SDG&E will calculate class-specific PCIA rates using existing generation allocation factors and forecasted sales, mirroring the structure already used for unbundled customers and avoiding any cost shifts across classes. The change is framed as a transparency measure, making clear that PCIA is not a fixed charge but a usage-based cost tied to departing load obligations. SDG&E has also established a new PCIA Billing Change Memorandum Account (authorized under the same decision and created via AL 4738-E) to track the incremental costs of implementing the billing, tariff, and rate changes, indicating that it intends to recover implementation expenses from ratepayers. However, SDG&E notes that implementation will require substantial billing system development, testing, and coordination with other planned 2026 system changes, including a broader cloud migration. Consequently, SDG&E does not expect to implement the new billing format until 2027 at the earliest. Protests are due **April 6**. ### **INSTANT ANALYSIS** This is a transparency-driven billing change, but the significance is political and perceptual, not financial. SDG&E is taking a cost that has long been embedded in bundled rates and surfacing it as a visible line item, which will make PCIA more salient to customers. That matters in a landscape where PCIA remains one of the most contested cost-recovery mechanisms between investor-owned utilities and Community Choice Aggregators. There is no rate impact or cost reallocation. But by explicitly labeling PCIA on bundled bills, SDG&E aligns bundled customers with the same cost visibility long experienced by departing load customers. That move implicitly reinforces the idea that PCIA is a system obligation tied to past procurement, not a discretionary or avoidable charge. The delayed implementation timeline is significant. Pushing implementation to 2027 suggests that billing system constraints are real, but it also gives the Commission and stakeholders time to continue debating PCIA reform while the visibility shock is postponed. The memorandum account setup indicates that SDG&E isn't just complying, it's laying groundwork to bill ratepayers for the cost of compliance. ### **WHO SHOULD CARE?** - **CCAs:** Breaking out the PCIA on bundled bills makes the charge more visible and easier to scrutinize. While this might fuel anti-PCIA narratives, it also reinforces that the charge applies broadly, not just to CCA customers. Expect this to become a standard ask in every IOU GRC Phase 2 going forward. - **IOUs (SDG&E, SCE, PG&E):** The move strengthens the framing of PCIA as a system obligation tied to legacy procurement, not a penalty tied to choice. - **Large C&I customers and Direct Access Entities:** The change increases transparency and comparability across customer types and lays the groundwork for future disputes over allocation, vintaging, and exit cost design. ### MONDAY AGGREGATE: Stipulation Charts a Course for $1.951 Billion Woolsey Fire Securitization URL: https://www.calregulatory.com/monday-aggregate-stipulation-charts-a-course-for-1-951-billion-woolsey-fire-securitization/ Last updated: 2026-03-17T02:46:44.000Z Today's top item is a [joint stipulation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347216.PDF?ref=calregulatory.com) between SCE and Cal Advocates in A.26-01-007, where Edison seeks authority to issue **$1.951 billion** in recovery bonds to finance costs related to the [2018 Woolsey Fire](https://en.wikipedia.org/wiki/Woolsey%5FFire?ref=calregulatory.com). The stipulation resolves all contested issues in the proceeding. On the Sempra front, SDG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347096.PDF?ref=calregulatory.com) for authority to issue up to **$2.583 billion** in new long-term debt and **$1.348 billion** in additional roll-over debt authority for 2027–2029\. Additional items of note include: - A ruling in the SGIP docket establishing new cost-verification requirements for SGIP Residential Solar and Storage Equity projects; - A California Resources Production Corporation application for rehearing of a CPUC decision last month ([D.26-02-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870224.PDF?ref=calregulatory.com)); and - A SoCalGas request for expedited approval of two interstate natural gas capacity contract renewals with [El Paso Natural Gas Company](https://pipeportal.kindermorgan.com/portalui/DefaultKM.aspx?SP=EPGD&ref=calregulatory.com). --- ### WOOLSEY FIRE SCE and Cal Advocates [filed a joint stipulation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347216.PDF?ref=calregulatory.com) resolving all contested issues in [A.26-01-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com), which seeks authority for SCE to issue **$1.951 billion** in recovery bonds to finance costs related to the [2018 Woolsey Fire](https://en.wikipedia.org/wiki/Woolsey%5FFire?ref=calregulatory.com). (*See CRI's coverage* [*here*](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/?ref=california-regulatory-intelligence-newsletter)*.*) [IRP Cycle 2024-2026 Changes; Woolsey Fire Financing OrderCovers: IRP; Woolsey Fire; Aliso Canyon; 2026 ERRA Forecasts of PG&E and SCE![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-63.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/photo-1688040637388-d2c0aa7b9907-7)](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/?ref=california-regulatory-intelligence-newsletter) - The parties agree that the wildfire costs recorded in SCE's Wildfire Expense Memorandum Account were previously found just and reasonable in a 2025 decision ([D.25-12-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894945.pdf?ref=calregulatory.com)), allowing them to be financed through securitization. Structure and tenor were the only issues in material dispute. The stipulation caps the transaction at a 22-year weighted average life and 33-year maximum maturity, and concludes that issuing the bonds is just, reasonable, and consistent with the public interest. - The bonds would be issued through a bankruptcy-remote special purpose entity and repaid through a nonbypassable "Fixed Recovery Charge" on SCE electric customers, with [CARE and FERA customers](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/care-fera-program?ref=calregulatory.com) exempt. Because CARE and FERA customers are exempt from the Fixed Recovery Charge, securitization eliminates their bill impact entirely; they would otherwise face a **$2.78** monthly increase under a five-year amortization. - The parties argue that securitization produces an estimated **$827 million** in present-value savings compared with traditional utility financing at SCE's authorized 7.59% rate of return, and approximately **$304 million** compared with five-year amortization using long-term debt. The stipulated structure would produce an estimated **$1.19** monthly increase for non-CARE residential customers compared with **$4.27** under five-year amortization. The parties request that the Commission expedite issuance of a financing order. **INSTANT ANALYSIS:** The joint stipulation clears the path for approval of SCE's $1.951 billion Woolsey Fire securitization. With SCE and Cal Advocates aligned, no contested issues remain, and the CPUC can move directly to a financing order. Structure and tenor were the only points in material dispute (Cal Advocates protested the application on these grounds) and the parties agreed to cap the bonds at a 22-year weighted average life and 33-year maximum maturity. This compromise spreads wildfire cost recovery over decades while limiting the longest tail of ratepayer charges. The moral of the story is that securitization is now a default recovery tool, converting liabilities into long-term recovery bonds backed by nonbypassable charges. --- ### WILDFIRE MITIGATION SDG&E filed a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347217.PDF?ref=calregulatory.com) opposing Protect Our Communities Foundation’s [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083307.PDF?ref=calregulatory.com) of [D.26-01-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K291/596291467.PDF?ref=calregulatory.com) in the utilities’ 2024 General Rate Case proceeding. (*See CRI's coverage of that application* [*here*](https://www.calregulatory.com/wednesday-aggregate-13/)*.*) [Stanpac Transaction Scrutiny; Wildfire Cost ChallengeTopics covered: natural gas transmission assets, wildfire mitigation, ERRA compliance![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-62.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-10-2026--89--1.png)](https://www.calregulatory.com/wednesday-aggregate-13/) - SDG&E argues that Protect Our Communities Foundation failed to identify any legal error in the Commission’s decision approving recovery of certain Wildfire Mitigation Plan Memorandum Account costs associated with 2019–2022 spending. - According to SDG&E, Protect Our Communities Foundation’s rehearing request largely repeats arguments the CPUC already considered and rejected, including claims that the decision improperly allowed recovery of post-2022 costs, considered securitization, or authorized a future proceeding for 2024–2025 costs. SDG&E contends these arguments reflect misunderstandings of how capital expenditures are recovered over time and of the statutory framework governing wildfire mitigation cost recovery. - SDG&E's response also defends the CPUC’s use of the “prudent manager” standard for evaluating whether previously incurred utility costs are just and reasonable. SDG&E maintains that this standard reflects long-standing ratemaking practice and statutory review requirements, and that Protect Our Communities Foundation’s challenge merely attempts to relitigate policy disagreements rather than demonstrate legal error. Last, SDG&E argues that the CPUC acted within its discretion in allowing additional evidentiary development for certain Drone Inspection and Repair program costs rather than immediately disallowing them, and that Protect Our Communities Foundation mischaracterizes both the decision and the governing statutes. **INSTANT ANALYSIS:** SDG&E frames the dispute as a misunderstanding of ratemaking mechanics, particularly the approval of 2019–2022 wildfire mitigation spending versus the later recovery of associated capital costs through depreciation and return. One notable procedural wrinkle is SDG&E’s suggestion that one ordering paragraph in D.26-01-021 may conflict with the Public Utilities Code regarding recovery pathways for 2024–2025 wildfire mitigation costs. --- ### UTILITY FINANCES SDG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347096.PDF?ref=calregulatory.com) seeking CPUC authority to issue up to **$2.583 billion** in new long-term debt and **$1.348 billion** in additional roll-over debt authority for 2027–2029\. The roll-over amount covers **$1.35 billion** in planned re-financings of Series QQQ, DDD, and AAA maturities in 2026 and 2028, plus **$500 million** in pre-positioned authority to act on opportunistic re-financing that could reduce embedded debt costs. The application reflects capital spending driven by wildfire mitigation, grid hardening, electric-vehicle infrastructure, energy storage, gas system integrity, and risk mitigation strategies from SDG&E's 2025 RAMP filing ([A.25-05-013](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K243/566243429.PDF?ref=calregulatory.com)). SDG&E has already consumed **$2.331 billion** of the **$4.1 billion** authorized under a 2022 decision ([D.22-12-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K511/499511248.PDF?ref=calregulatory.com)) and expects to exhaust remaining authority by year-end 2026. SDG&E seeks flexibility across a full menu of debt instruments: - First-mortgage bonds; - Fall-away bonds; - Debentures; - Foreign-market securities; - Direct long-term loans; - Variable-rate debt; - Tax-exempt financings; and - Accounts-receivable-backed obligations, along with hedging and derivative tools including interest-rate swaps, caps, collars, and currency swaps. **INSTANT ANALYSIS:** The combined $3.93 billion request represents roughly 19% of SDG&E's $21 billion total regulatory capitalization and confirms the utility's capital cycle remains heavily debt-dependent through decade's end. The financing tracks spending approved in the Test-Year 2024 General Rate Case ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)) and the 2025 RAMP proceeding, a financial echo of the CPUC's own capital approvals. SDG&E's current structure (47.2% long-term debt vs. a 45.25% authorized target) is already running above the CPUC's blueprint. Each successive debt application of this scale makes it harder to stay within those bounds without Sempra putting more equity in to keep pace. --- ### SELF-GENERATION INCENTIVE PROGRAM Commissioner **Karen Douglas** issued a [ruling establishing new cost-verification requirements](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K365/602365885.PDF?ref=calregulatory.com) for SGIP Residential Solar and Storage Equity projects whose reported Total Eligible Project Cost exceeds specified thresholds relative to the maximum incentive for the system size. The Residential Solar and Storage Equity program launched in June 2025 with **$252 million** in incentives for low-income solar and storage installations. It is 99% reserved with over 3,200 projects waitlisted. However, an analysis by Energy Division found reported costs significantly above industry averages and historic SGIP benchmarks, prompting stronger verification before incentive payments are issued. - All Residential Solar and Storage Equity projects with Total Eligible Project Cost above **90%** of the maximum incentive must now submit equipment and labor documentation at the Incentive Claim Form stage. Projects above **100%** must additionally provide invoices supporting each cost category and a supplemental verification form signed by the developer or system owner and delivered to the host customer. - Developers with multiple projects may establish a baseline Total Eligible Project Cost using program-wide documentation, but must provide project-specific justification for any project exceeding that baseline. Any Total Eligible Project Cost that cannot be verified must be reduced, and the Program Administrator must warn the developer to reduce Total Eligible Project Cost across all other SGIP applications. Program Administrators will review projects in three prioritized groups. - **Group A:** Projects below 100% of the maximum incentive, plus projects above 100% that applied for interconnection before **February 20, 2026**. - **Group B: P**rojects above 100% with customer out-of-pocket costs under $3,000 and multifamily projects not in Group A. - **Group C:** All remaining projects, subject to random audit sampling. Program Administrators may withhold 30% or more of the incentive for any project pegged for an audit. Handbook updates are due within five days. Comments are due **March 18** as part of responses to the assigned commissioner's ruling. **INSTANT ANALYSIS:** The CPUC is intensifying cost oversight in the Residential Solar and Storage Equity program after finding project pricing well above market benchmarks. Commissioner Douglas's ruling creates payment friction for higher-cost developers by requiring documentation before incentives are released, and gives Program Administrators authority to withhold at least 30% of incentives and force portfolio-wide Total Eligible Project Cost reductions when costs can't be verified. The CPUC's concern is that inflated pricing consumes limited equity-program funds meant to maximize low-income installations. Similar scrutiny could emerge in other equity or storage programs if pricing anomalies surface. --- ### NATURAL GAS INFRASTRUCTURE/PIPELINE REGULATION California Resources Production Corporation filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K347/602347221.PDF?ref=calregulatory.com) of a decision last month ([D.26-02-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870224.PDF?ref=calregulatory.com)), which dismissed its application for designation as a public-utility gas corporation and for a Certificate of Public Convenience and Necessity to operate the Union Island natural-gas pipeline. (*See CRI's coverage* [*here*](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/)*.)* [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-61.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-03-2026-3.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) The Commission dismissed the application without prejudice, finding the matter unripe because parallel litigation and local proceedings concerning franchise rights and pipeline ownership remain unresolved. D.26-02-003 replaced an earlier proposed decision that had denied the application on the merits. In its request for rehearing, CRPC argues the decision: - Misinterprets the Public Utilities Code by requiring present ownership of the entire pipeline before granting public-utility status, an interpretation the Commission expressly rejected in a 2011 decision ([D.11-12-056](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/155837.PDF?ref=calregulatory.com)), where it called that reading an "absurd result"; - Departs from longstanding CPUC precedent allowing CPCNs based on prospective operation of utility infrastructure, and misrepresents the record in the [WesPac](https://docs.cpuc.ca.gov/published/Graphics/69695.PDF?ref=calregulatory.com) and [Wickland](https://docs.cpuc.ca.gov/published/Final%5Fdecision/20913-14.htm?ref=calregulatory.com) decisions it cites to distinguish (including incorrectly characterizing WesPac's pipeline as "unopposed" when the City of Gardena actively litigated against it); - Ignores that a CPCN would confer eminent domain authority enabling CRPC to perfect ownership of the pipeline segments at issue, making the ripeness rationale circular, a path the CPUC has endorsed in prior CPCN grants to Independent Storage Providers (Wild Goose, Gill Ranch, Lodi) and that California courts upheld in [*Shell v. City of Compton*](https://law.justia.com/cases/california/court-of-appeal/4th/35/1116.html?ref=calregulatory.com) and [*Unocal v. Conway*](https://caselaw.findlaw.com/court/ca-court-of-appeal/1761053.html?ref=calregulatory.com); and - Improperly introduced a ripeness theory outside the scoped issues of the proceeding. CRPC also contends the CPUC violated [its own scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M520/K706/520706044.PDF?ref=calregulatory.com), procedural rules, and due-process requirements by resolving the application on grounds expressly reserved for a later evidentiary phase and adopting a revised decision shortly before the vote without giving parties an opportunity to address the new rationale. **INSTANT ANALYSIS:** The rehearing request challenges the CPUC’s shift from denying CRPC’s CPCN application on the merits to dismissing it as “unripe.” CRPC argues the Commission misapplied the law and departed from precedent allowing public-utility status based on prospective operation of infrastructure. The eminent domain argument is the strategic core: CRPC contends a CPCN would give it the condemnation authority needed to resolve the very ownership uncertainties the Commission cited as grounds for dismissal, and that the Commission has granted public-utility status for exactly this purpose in prior proceedings. The case tests whether the CPUC can determine pipeline utility status before ownership and franchise disputes are resolved. If the ripeness approach stands, developers may need clearer asset control before seeking CPCN authority. The dispute also reflects conflict between statewide infrastructure oversight and local franchise control, with potential implications for future pipeline and energy-facility proceedings. --- ### NATURAL GAS CAPACITY SoCalGas filed Advice Letter 6612-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) requesting expedited approval of two interstate natural gas capacity contract renewals with [El Paso Natural Gas Company](https://pipeportal.kindermorgan.com/portalui/DefaultKM.aspx?SP=EPGD&ref=calregulatory.com). The filing is made under the interstate capacity acquisition framework authorized in a 2004 CPUC decision ([D.04-09-022](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/39721.PDF?ref=calregulatory.com)), which allows expedited review when stakeholders such as Cal Advocates support the transaction. Cal Advocates participated in the relevant Capacity Consulting Group discussions in February 2025 and indicated support for the renewals, while TURN did not participate. The specific commercial terms of the contracts are confidential and included in a protected attachment because they contain market-sensitive information related to SoCalGas’s gas procurement and capacity management strategies. SoCalGas states that the contracts will not modify tariffs, withdraw service, or impose new service conditions. Protests are due **March 23**. **INSTANT ANALYSIS:** SoCalGas continues to maintain contracted interstate transport capacity into the Southern California gas system rather than relying purely on spot transportation or market flexibility. That reinforces the utility’s long-standing reliability strategy: secure firm upstream capacity to manage winter demand, storage injections, and operational volatility across the constrained SoCal basin. The key implication is continuity, with no immediate effect on gas procurement costs, scheduling, or balancing arrangements for core or noncore customers. ### WEEKEND NEWS CODEX: NEM 3.0 Upheld by Appeals Court URL: https://www.calregulatory.com/weekend-news-codex-10/ Last updated: 2026-03-16T01:24:35.000Z - **Appeals Court Upholds California's Net Metering 3.0:** "The 2022 changes to California’s net metering tariff, which substantially reduced the price utilities pay for customer-generated power, were upheld Monday by a [decision from the California First Appellate District Court of Appeals](https://www4.courts.ca.gov/opinions/documents/A167721A.PDF?ref=calregulatory.com)." [**UTILITY DIVE**](https://www.utilitydive.com/news/appeals-court-upholds-californias-net-metering-30/814307/?ref=calregulatory.com) - **California Court Upholds NEM 3.0, Dealing Blow to Rooftop Solar:** "The appellate court’s decision maintains the “Net Billing Tariff,” which transitioned the market away from NEM 2.0 and cut export credits by approximately 75% to 80%. In its ruling, the court deferred to the CPUC in its assessment of the costs and benefits of distributed generation." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/03/10/california-court-upholds-nem-3-0-dealing-blow-to-rooftop-solar/?ref=calregulatory.com) - **NEM 3.0 Decision – 1st Appellate District Affirms Original Opinion in Center for Biological Diversity v. Public Utilities Commission:** "On March 9, 2026, the First Appellate District [affirmed](https://www.scribd.com/document/1010579152/2026-03-09-Appeals-Court-Opinion-on-Remand?ref=calregulatory.com) in full the CPUC’s D.22-12-026 decision in Center for Biological Diversity v. Public Utilities Commission (Case No. [A167721](https://appellatecases.courtinfo.ca.gov/search/case/mainCaseScreen.cfm?dist=1&doc%5Fid=2578017&doc%5Fno=A167721&request%5Ftoken=NiIwLSEnPkw8WyBNSCM9WEhIIFg6UVxfJSMuWzhTICAgCg%3D%3D&ref=calregulatory.com)). The First Appellate District original opinion affirming the CPUC decision was appealed to the California Supreme Court, which issued an [opinion](https://www4.courts.ca.gov/opinions/documents/S283614.PDF?ref=calregulatory.com) in August 2025 not on the questions specific to the CPUC’s action on NEM 3.0’s net billing tariff and related matters (See CPUC [D. 22-12-056](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043682.PDF?ref=calregulatory.com); See Proceeding Docket for [R. 20-08-020](https://apps.cpuc.ca.gov/apex/f?p=401:59::::::&ref=calregulatory.com)), but on how appellate courts are to apply the judicial review standards found in Public Utilities Code §§ 1757 and 1757.1 to the CPUC." [**EPIC ENERGY**](https://epicenergyblog.com/2026/03/10/nem-3-0-decision-1st-appellate-district-affirms-original-opinion-in-center-for-biological-diversity-v-public-utilities-commission/?ref=calregulatory.com) - **Solar Panel Reimbursements to Remain Low Under California Appeals Court Ruling:** "Three appeals court judges ruled that the California Public Utilities Commission was justified in reducing the rate utilities pay customers for excess energy the customers’ solar panels generate." [**CAL MATTERS**](https://calmatters.org/economy/2026/03/net-metering-defeat-for-rootftop-solar-in-california-courts/?ref=calregulatory.com) - **Arevon Secures $920 Million for New California Energy Storage Project:** "Renewable energy developer Arevon Energy announced that it has secured $920 million in financing for its large-scale battery facility in California, Nighthawk Energy Storage Project. The new project, currently under construction in Poway, California, is expected to become operational this year. According to Arevon, with a capacity of 300 MW, the facility will be capable of powering 385,000 homes for up to four hours during peak demand periods." [**ESG TODAY**](https://www.esgtoday.com/arevon-secures-920-million-for-new-california-energy-storage-project/?ref=calregulatory.com) - **Balcony Solar is Taking State Legislatures by Storm:** "A [proposal in California](https://www.canarymedia.com/articles/solar/california-bills-balcony-solar-heat-pumps?ref=calregulatory.com) — a potentially massive market as the state with the [second-highest electricity prices](https://www.eia.gov/electricity/monthly/epm%5Ftable%5Fgrapher.php?t=epmt%5F5%5F06%5Fa&ref=calregulatory.com) and largest state economy in the nation — is in committee. Stryker anticipates that still more lawmakers will announce legislation for the up-and-coming tech this year." [**GRIST**](https://grist.org/buildings/balcony-solar-is-taking-state-legislatures-by-storm/?ref=calregulatory.com) - **California's Data Centers Should be Models of Affordable, Clean Energy:** "Requiring facilities to install on-site generation and storage that can be dispatched by the California independent system operator, and to actively reduce demand when the grid is stressed can support the state’s goals for reliable and affordable electricity. Data centers should also be incentivized to rely entirely on zero carbon energy resources to power their facilities."[ **CAL MATTERS**](https://calmatters.org/commentary/2026/03/data-centers-electricity-california/?ref=calregulatory.com) - **Why Data Centers Will Create Electricity Abundance:** "The price of electricity is bound to come down. Innovation across every possible source of electricity – large and small scale nuclear, natural gas, solar, geothermal (a big wild card), novel solutions such as [linear motors](https://www.mordorintelligence.com/industry-reports/linear-motion-system-market?ref=calregulatory.com) and other advances we can’t possibly predict – ensures that the days of grossly overpriced electricity are numbered." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/why-data-centers-will-create-electricity-abundance/?ref=calregulatory.com) - **California's High Gas Prices Are About More Than the Conflict in Iran:** "Currently, the few remaining California refineries are undergoing maintenance and switching to the state’s summer-blend gasoline, which brings on a seasonal price increase. Some state [lawmakers have proposed](https://abc30.com/post/lawmakers-propose-pausing-california-gas-tax-prices-climb/18646608/?ref=calregulatory.com) a temporary pause in California’s gas tax to ease pump price increases. Higher prices result from numerous factors, including refinery maintenance, reduced output, and higher production costs for summer-blend fuel. [Summer-blend gasoline is formulated](https://nypost.com/2026/03/02/us-news/ca-gas-prices-set-to-surge-and-its-unrelated-to-iran/?ref=calregulatory.com) with a lower Reid Vapor Pressure to reduce evaporation at higher temperatures, a requirement to combat air pollution in California’s summer months. Other states begin making the switch to summer-blend gasoline closer to May 1, while California refineries start much earlier because some areas require summer-blend fuel on April 1." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/international-issues/californias-high-gas-prices-are-about-more-than-the-conflict-in-iran/?ref=calregulatory.com) - **California Passed a Law to Curb Spikes in Gas Prices – Why Isn't It Using Those Powers Now?** "Economists say California’s biggest challenge may be infrastructure. Valero plans to close its Benicia refinery, which produces about 10% of the state’s gasoline, next month. In an [analysis posted last year](https://nealemahoney.substack.com/p/an-analysis-of-the-valero-benicia), Stanford economist **Neale Mahoney** and \[**Ryan\] Cummings** said California could offset lost refinery production with gasoline imports – if permitting allows refineries like Benicia to convert to fuel import terminals." [**CAL MATTERS**](https://www.ijpr.org/environment-energy-and-transportation/2026-03-13/california-passed-a-law-to-curb-spikes-in-gas-prices-why-isnt-it-using-those-powers-now?ref=calregulatory.com) - **California's New Governor Must Hold Down Clean Energy Costs, Drive Innovation:** "...the new governor should extend Diablo Canyon’s operation. It’s California’s largest source of carbon-free electricity, and it works. End the outdated ban on small modular reactors. Nuclear is clean, stable and here." [**CAL MATTERS**](https://calmatters.org/commentary/2026/03/new-governor-california-energy-cost/?ref=calregulatory.com) - **California Gas Utilities Say Research Supports Up to 5 Percent Hydrogen Blending:** "Southern California Gas Co., San Diego Gas & Electric and Southwest Gas filed a petition for modification in February asking the CPUC to remove the requirement for projects demonstrating the 0.1-percent to 5-percent blends. Pacific Gas & Electric did not join the other three utilities in the petition." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regulation%5Fstatus/california-gas-utilities-say-research-supports-up-to-5-percent-hydrogen-blending/article%5Fb09ffe33-3b55-400f-ab19-db01c40e7f94.html?ref=calregulatory.com) - **California Oil Reserves May Exceed Texas Oil Reserves:** "California has perhaps up to 30 billion barrels of oil in reserve according to industry experts. These massive oil deposits could make California a world-class oil producer and energy independent. Unfortunately, misguided Net-zero Policies have hamstrung California’s energy production. Texas has about 20 billion or so barrels of oil in reserve with new discoveries made quite often. Texas is a strong fiscally responsible low-debt state, while California is in deep debt despite the highest taxes in the USA. California is also first nationwide in unemployment, with oil industry workers now among those without jobs.." [**TUCO'S CHILD**](https://tucoschild.substack.com/p/california-oil-reserves-may-exceed) - **Geothermal – Clean Energy for People Who Like to Drill:** "Southern California Edison, the huge public utility, signed a contract for 320 megawatts of geothermal power from Fervo Energy’s Cape Station project in Utah. Even California’s long-term capital is helping. Fervo’s $462 million Series E funding round last December included [returning investor](https://fervoenergy.com/fervo-energy-raises-462-million-series-e-to-accelerate-geothermal-development-and-meet-surging-energy-demand-with-clean-firm-power/?ref=calregulatory.com) California’s CalSTRS, the world’s largest educator‑only pension fund and America’s second‑largest public pension fund." [**WASHINGTON MONTHLY**](https://washingtonmonthly.com/2026/03/12/geothermal-clean-energy-for-people-who-like-to-drill/?ref=calregulatory.com) - **Justice Department Says Defense Production Act Orders Could Override State Barriers to Oil:** "The U.S. Department of Justice issued a [legal opinion](https://www.justice.gov/olc/media/1429671/dl?inline&ref=calregulatory.com) concluding that a presidential order on energy production issued under the Defense Production Act could preempt conflicting state laws under the Constitution’s Supremacy Clause. The U.S. Department of Energy requested the opinion in connection with Sable Offshore Corp.’s ongoing efforts to restart offshore oil production from the Santa Ynez Unit." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/justice-department-says-defense-production?ref=calregulatory.com) - **Trump Administration Invokes Emergency Powers to Restart Oil Operations Off California Coast:** "Energy Secretary **Chris Wright** on Friday took action to hit back at two of the Trump administration’s top antagonists: Oil supply disruptions brought on by the war in Iran and California Gov. **Gavin Newsom**. Wright [issued an order](https://www.politico.com/f/?id=0000019c-e98e-dd96-a9be-fd9e41c80000&ref=calregulatory.com) paving the way for a company operating off the California coast to restart an oil pipeline that state officials have kept offline since 2015\. The Energy Department framed it as a way to ease reliance on oil imports through the Strait of Hormuz, a key waterway for oil tanker traffic that the war has choked off." [**POLITICO**](https://www.politico.com/news/2026/03/13/trump-administration-invokes-emergency-powers-to-restart-oil-operations-off-california-coast-00828164?ref=calregulatory.com) - **SCE Could Return $63.2M to Ratepayers Following 2023 Overcollection:** "The decision would also require SCE to return about $71,000 in 'unrealized revenue' associated with four public-safety power shutoffs that occurred in 2023\. SCE determined that had the four shutoffs not been implemented, customers would have used 912 MWh during those times, and calculated that it would have earned about $71,000 from electricity sales. This was recorded in a balancing account and was later discovered when the accounts were reviewed. Under current regulations, SCE must return that amount to customers because utilities aren’t allowed to recover revenue lost when power is shut off during PSPS events." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regulation%5Fstatus/sce-could-return-63-2m-to-ratepayers-following-2023-overcollection/article%5F23ea6974-f0fa-44d9-ade8-41b2d9e33323.html?ref=calregulatory.com) - **Shouting CEQA Reform From the Rooftops:** "We could soon find out how Californians really feel about CEQA. Voters are on track to consider a CalChamber-backed ballot measure in November that aims to modernize the 55-year-old California Environmental Quality Act to speed up the construction of essential housing, clean energy, transportation, water infrastructure and other projects. The [measure](https://advocacy.calchamber.com/ceqa/?ref=cleanpowercalifornia.org), titled the Building an Affordable California Act, cleared a signature threshold last month to appear on ballots and is gaining momentum, including an endorsement last week from Assemblymember **Buffy Wicks**, the former Housing Committee Chair and [accomplished](https://calmatters.org/housing/2025/03/ceqa-infill-housing-wicks/?ref=cleanpowercalifornia.org) CEQA brawler."[ **THE CURRENT**](https://www.cleanpowercalifornia.org/shouting-ceqa-reform-from-the-rooftops/?ref=calregulatory.com) - **This Public Power Movement is Raising a Billion Dollar Question:** "California has more than 20 publicly-owned electric utilities. But we haven’t seen a successful municipalization since Sacramento took ownership of its poles and wires in the 1940s. Today’s utilities are more complex than they were back in the day. A modern municipalization would involve not just poles and wires, but also stranded costs, bond obligations, wildfire liabilities, and protections for the customers outside the city who remain with the investor-owned utility." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/03/09/this-public-power-movement-is-raising-a-billion-dollar-question/?ref=calregulatory.com) - **Washington, California, and Quebec Collaborate on Linking Carbon Markets:** "Washington, California and Québec could start operating a linked carbon emissions trading market as soon as 2027, depending on how fast linkage process steps and regulatory changes are completed in each jurisdiction..." [**UTILITY DIVE**](https://www.utilitydive.com/news/washington-california-quebec-collaborate-linking-carbon-markets-cca/813995/?ref=calregulatory.com) - **Why a Microgrid Didn't Pencil Out in this California Advanced Energy Community:** "Ultimately, the microgrid didn’t make financial sense, said **Therese Peffer**, associate director, California Institute for Energy & Environment. The microgrid cost came in too high because PG&E’s estimated costs were unexpected, the battery shed in a proposed tight space was expensive–including sound mitigation and air conditioning–and some costs were unknown." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/community-microgrids/article/55361041/why-a-microgrid-didnt-pencil-out-in-this-california-advanced-energy-community?ref=calregulatory.com) ### FRIDAY AGGREGATE: Chevron/Valero Challenge 59.2% Crude Oil Transportation Rate Increase URL: https://www.calregulatory.com/friday-aggregate-chevron-valero-challenge-59-2-crude-oil-transportation-rate-increase/ Last updated: 2026-03-13T21:14:48.000Z Friday's roundup looks at an application for rehearing filed by Chevron and Valero that challenges last month's CPUC authorization of a 59.2% [Crimson Pipeline](https://www.crimsonmidstream.com/shipper-information?ref=calregulatory.com) rate increase for crude oil transportation on the San Joaquin Valley-to-Bay Area pipeline system. Chevron and Valero argue the increase is unlawful under the statutory 10% interim cap for oil pipelines (and question whether emergency rate relief makes sense for a pipeline that has been idle since November 2025). Other items on today's radar include: - SCE's request to recover $7.9 million in incremental O&M costs from its Class C water utility and small gas utility on Santa Catalina Island; - Edison's request to launch a program for residential customers who are rebuilding/repairing homes in the aftermath of the January 2025 wildfires; and - SoCalGas's update to the imbalance cash-out rates under its "California Producer Service" tariff. --- ### CRUDE OIL TRANSPORTATION Chevron Products Company and Valero Marketing & Supply Company filed an [application for rehearing ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K269/602269229.PDF?ref=calregulatory.com)of [Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673435.PDF?ref=calregulatory.com), which the CPUC adopted last month. The applicants argue that the CPUC unlawfully granted Crimson Pipeline utilities a **59.2%** interim rate increase for crude oil transportation on the San Joaquin Valley-to-Bay Area pipeline system (*see CRI's coverage of Resolution O-0098 here.*) [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-60.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-03-2026-2.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/?ref=california-regulatory-intelligence-newsletter) The shippers contend that state law limits oil pipelines to a **10%** interim rate increase prior to CPUC approval, and that the resolution improperly relied on general Commission authority to bypass this statutory cap. This is Crimson's fourth attempt at securing interim relief above 10%; the three prior requests were all rejected, and the CPUC declared in a 2024 decision ([D.24-05-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K630/531630207.PDF?ref=calregulatory.com)) that it considered the matter settled. The application further argues that the emergency justification is unsupported because the pipeline moved its last volumes in November 2025, with nominations at zero through February 2026 as shippers shifted to alternative supply routes. From Chevron and Valero's point of view, a retroactive rate increase under these conditions would impose substantial costs on past shippers without restoring service. They request the CPUC vacate Resolution O-0098. **INSTANT ANALYSIS:** This filing challenges the CPUC's interpretation that its general authority allows it to override the Public Utilities Code 10% interim cap for oil pipelines. The authorized interim rate (**$3.7527/bbl**) actually exceeds the rate Crimson requested in its pending 2025 General Rate Case (**$3.6137/bbl**), raising the additional question of whether the CPUC can set an interim rate above what could ultimately be authorized on final disposition. The deeper reality is that the dispute may already be overtaken by events. With the pipeline idle since November 2025, the practical effect of the interim rate increase is a retroactive cost allocation to former shippers, a circumstance that tests whether the CPUC's emergency authority extends to preserving a crude transportation asset that may no longer serve an active market. --- ### SCE's WATER & GAS UTILITIES SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M602/K280/602280022.PDF?ref=calregulatory.com) seeking to recover approximately **$7.9 million** (including interest) in incremental O&M costs from its Class C water utility and small gas utility on Santa Catalina Island. The underlying **$6.2 million** in base costs (**$5.78 million** for water, **$0.43 million** for gas) were recorded across memorandum accounts covering COVID-19 response, storm events, pipeline assessments, decommissioned pipe removal, mandatory water conservation (Stage 1 rationing), and [Lead and Copper Rule](https://www.epa.gov/dwreginfo/lead-and-copper-rule?ref=calregulatory.com) compliance. Labor costs are limited to premium time only. - To address affordability concerns on Catalina, SCE proposes recovering water costs over five years and gas costs over two years, with rate design that shifts the entire revenue increase onto non-residential (largely tourism-driven) customers so residential rates remain flat. - SCE also proposes a new one-way balancing account to capture revenues from a water distribution planning study charge and a non-potable water rate, functioning as offsets analogous to Other Operating Revenue in an electric General Rate Case. - On the gas side, higher-than-forecast microturbine propane usage has already driven actual 2025 rates approximately 1.5% below prior-year levels, cushioning the impact of the relatively modest $0.43 million gas recovery. Protests/responses are due **April 13**. **INSTANT ANALYSIS**: The accounting is unlikely to generate major controversy (the Commission already approved similar catastrophic event-costs in a 2023 decision, [D.23-11-089](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M521/K337/521337885.PDF?ref=calregulatory.com)) but Cal Advocates will likely scrutinize the premium labor allocations between the shared-employee water and gas utilities. The main issue is whether the CPUC accepts a framework of loading recovery onto commercial customers and using new offset revenue mechanisms to shield residents from further rate increases on an island where water-affordability ratios already exceed statewide thresholds. --- ### DISASTER RECOVERY SCE filed Advice Letter 5764-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)), requesting CPUC approval to launch the SWITCH (Simplified Wildfire Incentives for Transforming Customer Homes) energy-efficiency program. SCE would fund the program through an approximately **$20 million** shift within its existing 2024–2027 Energy Efficiency portfolio (no new ratepayer funding is requested). The program targets the approximately 8,500 residential customers (7,000 in Eaton and 1,500 in Palisades) rebuilding or repairing homes damaged by the January 2025 wildfires. Eligible measures include: - Induction ranges; - Heat-pump water heaters; - Heat-pump AC, electric dryers; and - Smart thermostats. Specific incentive amounts are not detailed in the filing, though gross measure costs range from **$100** (smart thermostat) to **$2,417** (heat-pump water heater). SCE frames the program as complementing concurrent grid investments in the burn-scar areas, including distribution undergrounding, voltage upgrades, and increased system capacity. SCE seeks three program exceptions: - Relaxed baseline verification requirements where destroyed homes make prior equipment data unavailable; - Authority to apply "Normal Replacement" rather than New Construction measure treatment so that wildfire-impacted customers are not rendered categorically ineligible; and - Flexibility to exceed "Incremental Measure Cost" caps so rebates can competitively steer appliance choices toward electrification. Protests are due **March 26**. **INSTANT ANALYSIS:** SCE is treating wildfire reconstruction as an electrification intervention point: catching customers at the moment they must replace major equipment anyway, when incremental costs are lowest and the risk of locking in decades of gas infrastructure is highest. The program is modest in scale with no rate impact, but the combination of relaxed verification rules, Normal Replacement measurement treatment, and Incremental Measure Cost cap could establish a replicable template for disaster-linked electrification across California. --- ### SOCALGAS SCHEDULE G-CPS SoCalGas filed Advice Letter 6610-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Effective&ref=calregulatory.com)) to update the imbalance cash-out rates under Schedule G-CPS (California Producer Service) for February 2026\. This routine monthly compliance update revises tariff sheets reflecting the gas price-based settlement rates applied to California producers who end the month with supply imbalances on the SoCalGas system. The rates are calculated using the methodology approved by the CPUC in [Resolution G-3489](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M079/K275/79275125.PDF?ref=calregulatory.com) and related decisions, which apply asymmetric multipliers (150% of the 7-day average high and 50% of the 7-day average low) to natural gas price indices at the SoCal Border, as reported by [Natural Gas Intelligence](https://naturalgasintel.com/?ref=calregulatory.com). The filing updates both the January and February 2026 daily imbalance cash-out values. The February table shows a declining trend through the month, with the seven-day average index falling to about **$0.14179/therm** by the end of February and averaging **$0.19912/therm** for the month. | Flow Date | 150% of 7-Day Avg High ($/therm) | 50% of 7-Day Avg Low ($/therm) | 7-Day Avg of Avg ($/therm) | | --------- | -------------------------------- | ------------------------------ | -------------------------- | | 1 | 0.86357 | 0.16864 | 0.46193 | | 2 | 0.53143 | 0.14121 | 0.32550 | | 3 | 0.42000 | 0.10686 | 0.25650 | | 4 | 0.30793 | 0.09043 | 0.19550 | | 5 | 0.29293 | 0.08686 | 0.18671 | | 6 | 0.28693 | 0.08614 | 0.18350 | | 7 | 0.28511 | 0.08664 | 0.18307 | | 8 | 0.28543 | 0.08850 | 0.18479 | | 9 | 0.28575 | 0.09036 | 0.18650 | | 10 | 0.29004 | 0.09186 | 0.18914 | | 11 | 0.29689 | 0.09357 | 0.19300 | | 12 | 0.30118 | 0.09500 | 0.19600 | | 13 | 0.30504 | 0.09586 | 0.19793 | | 14 | 0.30043 | 0.09350 | 0.19436 | | 15 | 0.29582 | 0.09114 | 0.19079 | | 16 | 0.29121 | 0.08879 | 0.18721 | | 17 | 0.28693 | 0.08693 | 0.18479 | | 18 | 0.28929 | 0.08650 | 0.18536 | | 19 | 0.28393 | 0.08471 | 0.18171 | | 20 | 0.27964 | 0.08314 | 0.17850 | | 21 | 0.27964 | 0.08286 | 0.17836 | | 22 | 0.27964 | 0.08257 | 0.17821 | | 23 | 0.27964 | 0.08229 | 0.17807 | | 24 | 0.27664 | 0.08164 | 0.17621 | | 25 | 0.26164 | 0.07793 | 0.16779 | | 26 | 0.25093 | 0.07464 | 0.16071 | | 27 | 0.23700 | 0.06964 | 0.15143 | | 28 | 0.22307 | 0.06536 | 0.14179 | | Avg | N/A | N/A | 0.19912 | **INSTANT ANALYSIS:** The February data shows a rapid normalization in the imbalance pricing environment after the volatility seen late in January. The average index used for cash-out settlement fell to $0.199/therm for February, down from **$0.328/therm** in January. The daily settlement value dropped significantly in the first few flow dates (still elevated at **$0.462/therm** on February 1 as the 7-day averaging window carried the late-January spike). Then it collapsed to a stable **$0.18 band** by flow date 5 (approximately) before fading gradually to $0.142 by month-end. The main story: imbalance exposure became much less expensive during February, reducing the penalty risk for producers whose nominations deviate from actual flows. This softens the financial consequences of imperfect scheduling but does not change the underlying incentive to maintain balance. ### WEDNESDAY AGGREGATE: Demand Response Bridge Funding; CalCCA on PCIA Reform; New PG&E Data Center in Gilroy URL: https://www.calregulatory.com/wednesday-aggregate-16/ Last updated: 2026-03-13T15:20:44.000Z Today's aggregate looks at: - A ruling in the CPUC's Demand Response proceeding regarding "bridge year" funding for utilities' DR programs; - Ex parte communications in the ERRA/PCIA Reform docket between CalCCA and President **Alice Reynolds**' office; - PG&E, Stanpac, and Chevron's argument that the CPUC's Affiliate Transaction Rules do not apply to the sale of Stanpac gas transmission assets to PG&E; - PG&E's request for approval of agreements that provide transmission-level electric service for a data center project in Gilroy; - PG&E's ex parte communication on post-2018 wildfire mitigation spending being an emergency response exceeding GRC assumptions; and - SCE's annual status update on Transportation Electrification Grid Readiness projects. Parties also filed comments in: - The CPUC's [Biomethane Procurement Cost Allocation docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K216/500216057.PDF?ref=calregulatory.com) regarding how the environmental attributes/costs of biomethane should be treated; and - The Long-Term Gas Planning docket, in response to Commissioner **Karen Douglas**'s amended scoping memo addressing [Senate Bill 1221 decarbonization pilots](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/sb-1221-implementation?ref=calregulatory.com). (*See CRI's recent coverage of these rulemakings* [*here*](https://www.calregulatory.com/monday-aggregate-senate-bill-1221-implementation-reining-in-rng-costs-pg-e-arrangement-with-citizens-energy-corporation/)*.*) [Senate Bill 1221 Implementation; Reining in RNG CostsCommissioner Karen Douglas issued a third amended scoping memo in the CPUC’s Long-Term Gas Planning docket.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-59.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Mar-04-2026--62-.png)](https://www.calregulatory.com/monday-aggregate-senate-bill-1221-implementation-reining-in-rng-costs-pg-e-arrangement-with-citizens-energy-corporation/) *CRI is available to fully update your organization on these matters and other standalone projects –* [*contact us*](https://www.calregulatory.com/contact-us/) *if interested.* --- ### DEMAND RESPONSE A new [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K872/601872252.PDF?ref=calregulatory.com) in the CPUC's Demand Response docket seeks comments on an Energy Division [staff proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K795/601795650.PDF?ref=calregulatory.com) that would authorize interim “bridge year” funding for investor-owned utility DR programs. - The proposal recommends extending the utilities’ existing 2027 demand response portfolios for two additional years, covering 2028–2029, while the CPUC completes broader policy updates in the current rulemaking. - Energy Division staff argue that a bridge period is necessary because the current schedule would require PG&E, SCE, and SDG&E to file their next demand response applications before the rulemaking’s policy changes are finalized. The Commission employed the same bridge-year approach during the last DR rulemaking, authorizing interim funding in a 2014 decision ([D.14-01-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M086/K608/86608147.PDF?ref=calregulatory.com)). - Staff therefore recommend maintaining the utilities' approved 2027 program structures and budgets (excluding pilots, though the proposed budget table includes a separate pilots line item) during 2028–2029 while giving utilities additional time to incorporate new policy requirements, including the Societal Cost Test, into program design and cost-effectiveness reporting tools for the subsequent 2030–2034 application cycle. - The proposal recommends exempting the bridge-year portfolios from the Societal Cost Test requirement while funding the utilities' integration of the Societal Cost Test into their reporting tools ahead of the 2030–2034 cycle. Under the proposal, utilities would file the next full DR program applications by **January 1, 2029**. The proposal also outlines preliminary annual bridge-year budget levels that mirror existing program categories such as supply-side demand response, auction mechanisms, enabling technologies, marketing, and portfolio support. Estimated annual totals would be **$82.7 million** for PG&E, **$159.2 million** for SCE, and **$8.5 million** for SDG&E, plus additional funding to implement SCT reporting capabilities. Opening comments are due **April 15**, with replies due **May 6**. **INSTANT ANALYSIS**: This is a timing fix. The CPUC's Demand Response rulemaking will not finish in time for the utilities' next program filings, so staff proposes extending the existing 2027 portfolios through 2028–2029\. The result is a temporary hold on new program authorization while the Commission finishes rewriting DR policy and finalizes how the Societal Cost Test will apply to the next full program cycle starting in 2030\. Utilities will presumably be designing their 2030–2034 programs during the bridge period, but no new program structures can be approved until this rulemaking concludes. --- ### ERRA/PCIA REFORM In a March 5 ex parte meeting in [R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com), CalCCA [presented its position](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K896/601896098.PDF?ref=calregulatory.com) to President **Alice Reynolds**' office regarding Track 2 of the PCIA reform proceeding. Recall that this track focuses on how pre-2019 banked Renewable Energy Credits should be valued within the PCIA framework. CalCCA argued that customers who were originally on bundled IOU service and paid for these RECs through rates (but later departed to Community Choice Aggregators, termed "Later Departing Customers") currently receive no value when the investor-owned utilities later use those banked RECs for [Renewables Portfolio Standard](https://www.cpuc.ca.gov/rps/?ref=calregulatory.com) compliance. This is distinct from customers who were already unbundled at the time of REC generation, who received value through a PCIA credit at that time. According to CalCCA, this outcome violates the statutory "indifference" principle underlying the PCIA by creating a cost shift from current bundled customers to later-departing customers, because only bundled customers receive the compliance value of RECs that all then-bundled customers helped fund. To address this issue, CalCCA proposed that, when IOUs use pre-2019 banked RECs for compliance, the value of those credits should be reflected in the PCIA for the customers who originally paid for them. Its primary proposal would credit the PCIA at the current RPS Market Price Benchmark when the RECs are used, applied to the appropriate customer vintage year; an alternative approach would allocate the benefit by reducing the RPS procurement requirement for the load-serving entity serving those later-departing customers. CalCCA maintains that either approach restores customer indifference and prevents cost shifting. The utilities have advanced five primary counterarguments: - Pre-2019 banked RECs were already valued in the year of generation and the accounting is closed; - The PCIA "collective rights" framework forecloses any claim by later-departing customers to REC value "left behind"; - Valuation of pre-2019 banked RECs would impermissibly open up the pre-2019 PCIA methodology; - Pre-2019 banked RECs are categorically different from post-2018 RECs and cannot be valued at the current Market Price Benchmark; and - CPUC precedent precludes the valuation, which would also produce impermissible consequences. CalCCA characterized these arguments as "clouds" over what it views as a straightforward valuation issue, arguing that none of them refute the core fact that bundled customers only receive value when the RECs are actually used, and later-departing customers should receive equivalent value to ensure indifference. **INSTANT ANALYSIS:** This is a technical but consequential dispute over who captures the value of pre-2019 banked RECs. CalCCA argues that customers who paid for those RECs before departing utility service should receive value when the credits are later used for RPS compliance, likely through a PCIA credit tied to the RPS market price benchmark. If adopted, the proposal would require that compliance value flow to CCA and departing-load vintages (a correction, in CalCCA's view, of what it characterizes as an unlawful cost shift under current practice), though the utilities contest both the legal basis and the practical implications of such a change. The CPUC's eventual decision on this matter will shape the treatment of banked environmental attributes in PCIA accounting, with direct implications for CCA economics and future REC valuation. --- ### NATURAL GAS TRANSMISSION ASSETS PG&E, Standard Pacific Gas Line Incorporated (Stanpac), and Chevron Pipe Line Company filed an [opening brief ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K872/601872260.PDF?ref=calregulatory.com)in [A.25-12-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com), arguing that the CPUC’s Affiliate Transaction Rules do not apply to their proposed transaction involving the sale of Stanpac gas transmission assets to PG&E. The brief responds to a protest from Cal Advocates asserting that the transaction should be evaluated under the Affiliate Transaction Rules. PG&E, Stanpac, and Chevron contend the rules are not triggered because Stanpac is a regulated subsidiary whose revenues and expenses are already subject to CPUC ratemaking oversight, and therefore it is expressly excluded from the Affiliate Transaction Rules definition of an “affiliate.” They argue further that Chevron is not an affiliate of PG&E under the ownership or control thresholds used in the Affiliate Transaction Rules. - The transaction itself would transfer substantially all Stanpac pipeline and land assets to PG&E for approximately **$150.4 million**, with Stanpac then paying a dividend to its owners proportional to their ownership interests (PG&E 6/7, Chevron 1/7), resulting in an effective **$21.5 million** economic buyout of Chevron's one-seventh interest in the assets. - The transaction also establishes a long-term transportation arrangement under which Stanpac remains contractually obligated to provide gas service to Chevron's Richmond refinery but subcontracts actual performance to PG&E through an Inter-Utility Service Agreement, effectively making Stanpac a contractual pass-through entity operating on PG&E's system. Under the proposed structure, Stanpac would remain in existence during a 20-year service term before PG&E ultimately acquires Chevron’s remaining Stanpac shares for **$1.00** and seeks Commission approval to dissolve the entity. The parties maintain that the CPUC’s existing statutory review under the Public Utilities Code already provides the appropriate framework for evaluating the transaction and protecting ratepayers without applying the Affiliate Transaction Rules regime. **INSTANT ANALYSIS**: This filing is a procedural move by PG&E and its partners to narrow the scope of this docket by keeping the transaction out of the CPUC’s Affiliate Transaction Rules framework. If the Commission agrees, the proceeding stays focused on the key statutory questions rather than expanding into a broader affiliate-conduct inquiry. The dispute reflects a familiar regulatory refrain: Cal Advocates attempting to widen scrutiny over a complex utility transaction, and the utilities pushing to confine the case to traditional public-interest and ratemaking review. The outcome will not determine whether the transaction proceeds, but it could affect how heavily the CPUC interrogates potential cross-subsidization and corporate-structure issues tied to PG&E’s consolidation of Stanpac pipeline assets serving Chevron’s Richmond refinery. --- ### DATA CENTERS PG&E submitted [Advice Letter 7853-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7853-E.pdf?ref=calregulatory.com) requesting CPUC approval of several agreements to provide transmission-level electric service for a new data center project in Gilroy with a projected peak demand of 49.5 MW operating continuously. To serve the load, PG&E proposes constructing a new 115-kV "Garlic Switching Station" connected via a dual circuit transmission line loop configuration to the Morgan Hill and Llagas substations, with the facilities expected to enter service by March 2027\. The project includes multiple agreements covering interconnection facilities, special facilities, design review, and an engineering-procurement-construction arrangement under which the customer will build the switching station and transfer it to PG&E once completed and inspected. PG&E also requests several exceptions to standard Electric Rules 2, 15, and 16 governing line extensions and special facilities. Instead of the usual estimated-cost framework, the agreements require the customer to pay PG&E's actual project costs with progress billing, while certain project elements are treated as refundable depending on future revenue generated by the load over a 15-year period. The customer is not entitled to refunds on Special Facilities and will pay ongoing cost-of-ownership charges for those components. PG&E argues this structure protects existing ratepayers by ensuring the data-center developer bears the upfront infrastructure costs while allowing refunds only if the project ultimately produces sufficient electric revenues. Protests are due **March 26**. **INSTANT ANALYSIS:** This filing shows another data center load pushing into transmission territory in Silicon Valley’s southern corridor. A 49.5 MW facility now requires its own 115-kV switching station and dual transmission feeds. The key point is cost structure. PG&E is shifting construction risk to the customer through actual-cost billing and customer-funded infrastructure. That model is becoming the default template for large data-center interconnections in California. --- ### WILDFIRE & GAS SAFETY PG&E [reported a March 2 ex parte meeting](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K687/601687369.PDF?ref=calregulatory.com) with advisors to Commissioner **John Reynolds** and President **Alice Reynolds** regarding its request to recover wildfire mitigation costs recorded in memorandum accounts in [A.23-06-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M511/K547/511547762.PDF?ref=calregulatory.com). PG&E argued that 2020–2022 wildfire mitigation work was reasonable, necessary for public safety, and consistent with its approved Wildfire Mitigation Plan, citing audits supporting the costs’ incrementality. PG&E also opposed intervenor proposals for permanent capital disallowances and asked the CPUC to allow recovery of its 2023–2030 capital revenue requirement through a compliance advice letter rather than a new application, arguing the streamlined process would save time and about **$52 million** in ratepayer interest. **INSTANT ANALYSIS:** This ex parte shows PG&E reinforcing the overriding narrative of this proceeding: wildfire mitigation spending after the 2017–2018 fires was an emergency response that exceeded General Rate Case assumptions and should be fully recoverable. PG&E is also laying groundwork against TURN and Cal Advocates’ proposed capital disallowances, which would set a precedent for excluding portions of wildfire mitigation investment from rate base. PG&E is also advocating for recovery of the 2023–2030 revenue requirement through a compliance advice letter rather than a new application. If the CPUC accepts that approach, the remaining cost-recovery phase becomes faster and more administrative, limiting additional litigation risk around the wildfire mitigation spending. --- ### TRANSPORTATION ELECTRIFICATION SCE submitted Advice Letter 5758-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters/pending?ref=calregulatory.com)), providing its first annual status update on Transportation Electrification Grid Readiness (TEGR) projects required by the Commission’s decision in SCE’s 2025 General Rate Case. The filing reports progress on distribution and subtransmission upgrades intended to prepare the grid for transportation electrification and other load growth, including substation capacity expansions, new circuits, and reconductoring projects across SCE’s service territory. SCE explains that some TEGR projects have changed scope, been deferred, or migrated into its standard distribution and transmission planning process as updated load forecasts and engineering assessments emerged. The report also provides project-level information such as status, expected in-service dates, capital expenditures, and anticipated hosting capacity increases for infrastructure upgrades supporting future electrification demand. SCE did not include project-specific energization request details or customer benefit types, stating that this information is "not readily accessible." **INSTANT ANALYSIS:** This filing shows how transportation electrification is migrating from policy aspiration into routine grid planning. Many projects originally labeled as TEGR in SCE’s General Rate Case are now being absorbed into the utility’s normal distribution and subtransmission planning process as load forecasts evolve and specific interconnection needs emerge. ### March 19, 2026 CPUC Voting Meeting Preview: Transmission-Level Planning Problems Take Center Stage URL: https://www.calregulatory.com/march-19-2026-cpuc-voting-preview-transmission-level-planning-problems-take-center-stage/ Last updated: 2026-03-11T16:21:36.000Z Below is the lineup of [items the CPUC is scheduled to consider](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M602/K180/602180761.pdf?ref=calregulatory.com) on **March 19**. The dominant story is the buildout of physical and regulatory infrastructure for a mass electrification future. Three recurring threads are: - **How the influx of data centers is becoming a transmission-level planning problem**. California's San Jose cluster alone features STACK's 90 MW, Menlo Equities' 49 MW, LS Power's two transmission CPCNs (one at $1.6 billion, one at $813 million), plus a load forecast doubling from 2,100 to 4,200 MW. These developments show Silicon Valley load growth outpacing the existing grid so dramatically that the CPUC is approving billions in new transmission on compressed timelines. SCE's Alberhill project in Riverside extends the same logic to Southern California's heat-vulnerable load pockets. The situation is no longer incremental; the Commission is authorizing the kind of capital deployment that reshapes utility balance sheets for a generation. - **Attempts at accountability are intensifying**. A pending ICA remediation item is the clearest example (turning hosting capacity maps from informational tools into compliance-grade tools) but similar themes show up in the Climate Credit PD, SDG&E's ERRA compliance review, a denial of SDG&E's POLR memorandum account, and the closure of PG&E's RAMP. Capital deployment's mass acceleration in the electrification age will reveal much about costs, oversight, and regulatory problem-solving. - **The machines of electrification keep getting money, while legacy infrastructure recedes**. A tripling of the DG Statistics platform, ORCHARD's EV charging layer, a Flex Alert media extension, an SGIP methane-quality standard holdover...none of these are big-ticket items, but they demonstrate where all major movement is headed. Meanwhile, moves at Shell and Crimson Pipeline tell an equally clear narrative, albeit from the standpoint of departure. Last, two Consent Agenda items (a SoCalGas GCIM reward and SCE's debt authorization) offer a microcosm of utility finances. One utility gets rewarded for efficient natural gas procurement, another gets funding to finance capital expenditures and address wildfire-related liabilities. --- ### DATA CENTERS - [Draft Resolution E-5447](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K895/598895478.PDF?ref=calregulatory.com) approves PG&E's [Advice Letter 7653-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7653-E.pdf?ref=calregulatory.com), and authorizes a non-standard Engineering, Procurement, and Construction agreement with [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com) for construction of the 115 kV Ringwood Switching Station in San Jose. The Ringwood facility is a key component of infrastructure needed to energize STACK’s planned 90-megawatt data center load. Under the agreement, STACK will design, procure, and construct the switching station and then transfer ownership to PG&E upon completion. - Separately, [Draft Resolution E-5433](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K319/599319897.PDF?ref=calregulatory.com) approves, with modifications, PG&E’s agreement to energize a new 49-MW data center and computing lab in Sunnyvale for [Menlo Equities](https://www.menloequities.com/?ref=calregulatory.com). The data center requires the construction of new transmission facilities, including a 115-kV line extension, and substation upgrades. The draft resolution finds the project reasonable but imposes additional ratepayer protections due to the scale and uncertainty of a transmission-level large load. These protections include limiting refunds of the customer's upfront energization costs to **75%** of PG&E's annual net revenues from the project, plus an income-tax component adjustment. --- ### TRANSMISSION INFRASTRUCTURE - A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056564.PDF?ref=calregulatory.com) grants [LS Power Grid California](https://www.lspowergrid.com/utilities/ls-power-grid-california/?ref=calregulatory.com) a certificate to construct the [Power Santa Clara Valley Project](https://www.lspowergrid.com/wp-content/uploads/Power-Santa-Clara-Valley-2-Pager.pdf?ref=calregulatory.com), a **$1.6 billion** transmission upgrade initially approved to address reliability issues in the San José area's 115-kV system. The project was subsequently modified in November 2024 to respond to load forecast increases from 2,100 MW to potentially 4,200 MW through a new HVDC link between major substations. The PD finds the project necessary despite significant environmental impacts, adopts an environmentally superior configuration with mitigation measures, and authorizes cost recovery through CAISO transmission rates subject to FERC oversight, emphasizing that rising load forecasts and grid stability needs outweigh unavoidable cultural resource impacts. - Another item on the March 19 Regular Agenda addresses a separate LS Power [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M531/K704/531704388.PDF?ref=calregulatory.com). A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K351/599351814.PDF?ref=calregulatory.com) grants LS Power Grid California a Certificate of Public Convenience and Necessity to construct the [Power the South Bay Project](https://www.lspowergrid.com/wp-content/uploads/Power-the-South-Bay-2-Pager.pdf?ref=calregulatory.com), a roughly 12-mile 230-kV transmission line connecting PG&E's Newark substation to Silicon Valley Power's Northern Receiving Station to address reliability risks and rising demand in the San José area. Identified by the CAISO in its 2021–2022 Transmission Plan, the project will largely be built underground to relieve system overloads and support future load growth. Construction is authorized beginning March 2026 with a CAISO-required in-service date of June 1, 2028\. The maximum cost cap is **$813.24 million** ($677.7 million base plus 20% contingency), recovered through CAISO transmission rates subject to FERC oversight. - Additionally, a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038893.PDF?ref=calregulatory.com) grants SCE a CPCN to construct the [Alberhill System Project](https://www.sce.com/sites/default/files/inline-files/Alberhill%5FSystem%5FProject.pdf?ref=calregulatory.com) in western Riverside County. The PD concludes that new transmission and substation infrastructure is needed to address growing electricity demand, reliability risks, and resilience concerns in the Valley South System. The PD finds that this load pocket (which serves hundreds of thousands of residents and lacks tie-lines to neighboring systems) faces increasing exposure to outages and capacity constraints during extreme heat and contingency events, and that the project’s benefits outweigh its environmental impacts. The PD sets a cost cap of **$482 million** (2023 dollars) for the three-year construction project. --- ### CLIMATE CREDIT A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101732.PDF?ref=calregulatory.com) in [R.25-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com) (the Climate Credit rulemaking) orders PG&E, SCE, and SDG&E to pause distribution of the 2026 residential electric [Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) while it considers moving the credit to higher-billed summer months later this year. The PD concludes that allowing the spring 2026 credit to proceed as scheduled would violate the Public Utilities Code, which explicitly requires distribution in high-billed months (and spring is historically a low-bill period for electric customers). --- ### INTEGRATION CAPACITY ANALYSIS [Draft Resolution E-5440](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?ref=calregulatory.com) approves, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their [Integration Capacity Analysis](https://irecusa.org/blog/regulatory-engagement/key-lessons-from-the-california-integrated-capacity-analysis/?ref=calregulatory.com) tools. These tools estimate how much distributed energy can be added to the grid without upgrades. Utilities must improve data transparency, reduce redactions, update maps more consistently, and report the causes of discrepancies. The draft resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. --- ### FLEX ALERTS A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/599037490.PDF?ref=calregulatory.com) in [R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com) extends the statewide Flex Alert paid media campaign through calendar year 2026, authorizing a one-year budget of **$15 million** funded by customers of the three large investor-owned utilities. The reduced budget reflects the end of emergency programs like Power Saver Rewards while acknowledging that Flex Alerts still deliver measurable load relief at relatively low implementation complexity compared to new program design. --- ### SDG&E 2023 ERRA COMPLIANCE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) approves (with modifications) SDG&E's 2023 Energy Resource Recovery Account compliance application, finding that the utility’s power procurement, contract administration, dispatch decisions, and related accounting were largely prudent and consistent with CPUC-approved plans. The PD also determines that SDG&E recorded a net undercollection of about **$214.6 million** across its procurement-related balancing accounts (excluding confidential subaccounts) and allows recovery of those costs through established mechanisms. --- ### PROVIDER OF LAST RESORT [Draft Resolution E-5411](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K879/598879783.PDF?ref=calregulatory.com) denies SDG&E's request for review of Energy Division’s disposition denying Advice Letter 4475-E, which sought to preemptively establish a memorandum account to track incremental administrative and procurement costs in the event of a mass involuntary return of customers to Provider of Last Resort service. If the item is authorized, actual cost tracking would remain available to SDG&E, albeit situationally and under CPUC control. --- ### GAS COST INCENTIVE MECHANISM A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K024/599024344.PDF?ref=calregulatory.com) approves SoCalGas’s request for an **$8.37 million** shareholder reward under its Gas Cost Incentive Mechanism for Year 31 (April 2024–March 2025), after finding the utility procured natural gas supplies significantly below its benchmark cost. SoCalGas’s actual gas procurement costs were about **$42.1 million** under the benchmark, producing **$33.8 million** in savings for core ratepayers and the remainder as a shareholder incentive under the GCIM’s established sharing formula, which rewards utilities for acquiring gas at or below market prices. --- ### UTILITY FINANCES A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/99037460.PDF?ref=calregulatory.com) authorizes SCE to issue up to **$9.85 billion** in new debt and **$1.155 billion** in preferred equity, a **$525 million** reduction that SCE itself proposed after updating forecasts to reflect the CPUC's 2025 General Rate Case decision ([D.25-09-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M580/K788/580788967.PDF?ref=calregulatory.com)). The funds would finance capital expenditures, refinance maturing obligations, and address wildfire-related liabilities through 2028. --- ### RISK ASSESSMENT & MITIGATION PHASE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K902/596902581.PDF?ref=calregulatory.com) closes PG&E's 2024 Risk Assessment and Mitigation Phase proceeding, which serves as the front-end risk analysis for PG&E’s 2027 Test Year General Rate Case. The PD finds that PG&E’s RAMP filing, which uses a new cost-benefit framework to monetize safety and reliability risks, complies with Commission requirements despite multiple identified deficiencies. --- ### DISTRIBUTED GENERATION [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com) increases funding for the California Distributed Generation Statistics platform to **$2.6 million** per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion. If authorized, this move would nearly triple current funding and position the platform as a long-term backbone for forecasting, planning, and enforcement. --- ### ELECTRIC VEHICLE LOAD MANAGEMENT [Draft Resolution E-5452](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K873/598873013.PDF?ref=calregulatory.com) approves (with modifications) SCE's request to update its [Low Carbon Fuel Standard](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification/charging-infrastructure-deployment-and-incentives/low-carbon-fuel-standard?ref=calregulatory.com) Holdback Implementation Plan to add a new vehicle-grid integration program known as Orchestrated Charging and Advanced Resiliency for Distribution (ORCHARD). ORCHARD would integrate a software layer into SCE’s [Distributed Energy Resource Management System](https://www.cgi.com/us/en-us/article/derms-utilities?ref=calregulatory.com) to directly manage residential electric vehicle charging in order to reduce localized distribution peaks caused by Time-of-Use charging patterns, defer transformer upgrades, and lower system costs. --- ### SELF-GENERATION INCENTIVE PROGRAM A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056565.PDF?ref=calregulatory.com) denies ENGIE North America’s [petition to modify](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K757/542757352.PDF?ref=calregulatory.com) a 2021 decision in the SGIP rulemaking ([D.21-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M387/K064/387064243.PDF?ref=calregulatory.com)). The petition sought an exemption for wastewater treatment plants from the requirement that on-site biogas used in internal combustion engine projects contain at least **96% methane**. The PD finds the petition procedurally defective. If adopted, it would leave the existing methane quality standard in place while keeping the broader SGIP rulemaking open. --- ### PETROLEUM PIPELINES A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K805/597805000.PDF?ref=calregulatory.com) approves Shell California Pipeline Company LLC's withdrawal of the Carson-to-LAX and Carson-to-Van Nuys petroleum pipelines from common carrier service. The pipelines have never served non-affiliate customers, no protests were filed, and the PD finds no public purpose in maintaining common-carrier status. In short, the PD retires two legacy Shell pipelines from CPUC jurisdiction after decades of nominal common-carrier status never used by third parties. For operators, the PD illustrates a viable pathway for converting unused common-carrier designations to private pipelines where the public-service rationale has disappeared. --- ### CRUDE OIL TRANSPORTATION A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K284/601284606.PDF?ref=calregulatory.com) approves Crimson California Pipeline L.P.'s request to withdraw the southern segment of the Seal Beach Pipeline from public utility service. The 5.87-mile crude oil pipeline segment, running between Seal Beach and Signal Hill, had only one customer ([DCOR LLC](https://dcorllc.com/?ref=calregulatory.com)), which independently terminated its use of the pipeline after deciding to end operations at Platform Esther and shift to a different oil platform, and withdrew its protest to the application. Crimson argued that continued operation would require expensive repairs, relocations, and maintenance costs that far exceed revenues (in particular, insufficient crude oil volumes to purge saltwater intrusion were causing pipeline corrosion requiring frequent repairs). The PD finds those financial arguments reasonable and determines the pipeline is no longer necessary for public utility service. Crimson will place the pipeline into out-of-service deferment status rather than abandon it, purging hydrocarbons, filling the line with nitrogen, and isolating it while retaining ownership. ### MONDAY AGGREGATE: Senate Bill 1221 Implementation; Reining in RNG Costs; PG&E Arrangement with Citizens Energy Corporation URL: https://www.calregulatory.com/monday-aggregate-senate-bill-1221-implementation-reining-in-rng-costs-pg-e-arrangement-with-citizens-energy-corporation/ Last updated: 2026-03-09T20:23:41.000Z Today's aggregate provides updates on: - Continued implementation of Senate Bill 1221 and priority zone decarbonization projects; - An attempt by the CPUC to rein in biomethane costs; - PG&E's long-term investment arrangement with Citizens Energy Corporation; - Potential guiding principles for the Avoided Cost Calculator; - SCE ERRA compliance matters; and - Ex parte communications involving the Sempra IOU's petition for modification of a 2024 General Rate Case decision. Parties also filed opening comments on Track 1 proposals in the CPUC's Resource Adequacy rulemaking. If your organization would like an update reviewing all parties' comments on the RA matter, please [contact us](https://www.calregulatory.com/contact-us/) for a standalone summary and analysis. CRI now offers standalone project pricing. --- ### SENATE BILL 1221 DECARBONIZATION PILOTS Commissioner **Karen Douglas** issued a [third amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158013.PDF?ref=calregulatory.com) in the CPUC's Long-Term Gas Planning docket to refine questions related to the pilot program established under Senate Bill 1221, [which directs the CPUC to establish a program under which gas utilities propose pilot projects aimed at cost-effective decarbonization in designated priority zones](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/sb-1221-implementation?ref=calregulatory.com). The ruling revises a previously issued scoping memo by clarifying how gas utilities must demonstrate compliance with statutory requirements concerning community coordination and customer participation. Specifically, the memo restates one existing scoping issue and adds a related sub-issue addressing what information utilities must include in their pilot applications to show collaboration with local governments and community organizations, as well as how they will document property-owner consent and provide notice to affected customers and tenants, including those served through master-metered systems. Parties are invited to comment by **March 10**, with reply comments due **March 17**. **INSTANT ANALYSIS:** The ruling clarifies what gas utilities must include in their pilot applications to demonstrate local government coordination, community engagement, property-owner consent, and customer notification for participation in decarbonization zone pilots. The CPUC is emphasizing documentation of community participation before approving decarbonization zone pilots. Utilities preparing proposals will need clearer records of outreach and consent, which may lengthen application preparation but does not alter the policy direction of the proceeding. --- ### BIOMETHANE Commissioner **John Reynolds** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846485.PDF?ref=calregulatory.com) that modifies the CPUC's Renewable Gas Standard program created under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com) to modify biomethane procurement requirements for California's gas utilities. The PD concludes that the procurement framework adopted in a 2022 decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)) would impose excessive above-market costs on ratepayers given the early-stage biomethane market and limited feedstock supply. - To address this, the PD adopts a Cost Containment Mechanism that caps average program rate impacts at **1%** of each utility's bundled core customer revenue requirement with a maximum **3%** year-over-year increase. The Cost Containment Mechanism is the controlling constraint; the CPUC will not approve contracts that would cause rates to exceed it. - The PD also reduces the overall biomethane procurement target from 72.8 billion cubic feet annually to **36.4 billion cubic feet** and extends the compliance timeline from 2030 to 2035\. The prior short-term/medium-term structure is eliminated in favor of a single 2035 deadline. The Diverted Organic Waste procurement goal of 17.6 Bcf remains unchanged, tied to California's [Senate Bill 1383](https://www.wm.com/us/en/sb1383?ref=calregulatory.com) methane-reduction policy. - The PD opens all feedstocks to bid into utility solicitations while maintaining the dedicated Diverted Organic Waste target and directs utilities to revise their Renewable Gas Procurement Plans via Tier 2 Advice Letters. The 4% livestock biomethane procurement limit is retained. - The PD removes the previous 2040 delivery cutoff so contracts can extend beyond that date, retains the [M-RETS](https://ww2.arb.ca.gov/sites/default/files/2020-10/101520presentation%5Fm-rets.pdf?ref=calregulatory.com) tracking system, and establishes an 80/10/10 Renewable Thermal Certificate unbundling framework: 80% of biomethane by volume stays bundled with Renewable Thermal Certificate retired by the utility; 10% allows the developer to retain the RTC; 10% allows the utility to market it. Unbundled volumes purchased at market rate do not count against the Cost Containment Mechanism. Utilities are also directed to advice letters addressing landfill eligibility and interconnection cost reductions, respectively**.** The earliest the CPUC will consider this item is **April 9**. Comments are due **March 26**. **INSTANT ANALYSIS:** The CPUC is walking back the scale of the Renewable Gas Standard after early procurement revealed high costs and limited biomethane supply. The PD cuts the overall target in half while preserving the full Diverted Organic Waste target, pushes the deadline to 2035, and imposes a strict Cost Containment Mechanism that halts procurement if program costs exceed a 1% average rate impact measured against each utility's bundled core customer revenue requirement. If the PD is adopted, RNG procurement will continue, but under strict affordability constraints. The program shifts from an aggressive decarbonization mandate to a controlled, ratepayer-limited market experiment. The 80/10/10 Renewable Thermal Certificate unbundling framework is a novel structure worth watching; if it demonstrates cost savings, expect expansion in future proceedings. --- ### TRANSMISSION PROJECTS A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K795/601795585.PDF?ref=calregulatory.com) in [A.24-03-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M527/K221/527221490.PDF?ref=calregulatory.com), if adopted, would allow PG&E to enter into a long-term investment arrangement with [Citizens Energy Corporation](https://citizensenergy.com/?ref=calregulatory.com) under which Citizens could lease partial transmission entitlements in future PG&E transmission projects. The proposal stems from a "Development, Coordination, and Option Agreement" executed in 2024 (and amended in 2025), allowing PG&E to offer Citizens up to five investment tranches totaling as much as $1 billion in transmission projects. For each tranche, Citizens could acquire up to **49.9%** of the transmission entitlement rights through a 30-year lease, paying PG&E a lump-sum “prepaid rent” based on the project’s capital cost share. PG&E would still develop, construct, own, operate, and maintain the transmission assets, while Citizens would receive a share of transmission revenues through the CAISO’s High-Voltage Transmission Access Charge system. - The PD does not approve the individual leases but authorizes PG&E to seek approval for each tranche through Tier 3 Advice Letters. PG&E had sought direct approval of the first tranche in this proceeding, but the PD requires all five Option Periods to go through the Tier 3 process. - Each filing must show the transaction complies with the Development, Coordination, and Option Agreement and would not leave ratepayers worse off than PG&E financing the projects itself. The Commission applied a heightened "public interest" standard to the overall transaction as novel and unprecedented, though individual Tier 3 reviews will use the lower "no worse off" test. - Citizens proposes dedicating 50% to 90% of after-tax profits (escalating across tranches) to direct bill-payment assistance for PG&E customers, potentially totaling more than $450 million over the program's life. The Commission found the ratepayer-assistance concept provides public benefits but noted that Citizens has not provided sufficient detail about which organizations will deliver the assistance or which communities will be served. - TURN estimated Citizens' internal rate of return would exceed **9%** (about 400 basis points above PG&E's own debt cost) and calculated the leases would cost ratepayers approximately **$740 million** more than securitized debt financing. The PD defers these cost arguments to the tranche-by-tranche review. - To address oversight gaps, the PD requires standardized reporting in each Tier 3 filing covering project details, cost allocations, rate impacts, and ratepayer-assistance program design. PG&E must also file a Tier 1 Advice Letter each time FERC approves a new formula rate, updating its representative rate model to track whether the "ratepayer neutral" claims hold over time. The earliest the CPUC will consider this item is **April 9**. Comments are due March **16**. **INSTANT ANALYSIS:** The CPUC does not fully approve PG&E's **$1 billion** Citizens Energy transmission financing program but allows the framework to proceed through a closely supervised, tranche-by-tranche Tier 3 Advice Letter process (with no tranche pre-approved, including the first one). The heightened "public interest" standard and extensive reporting requirements reflect concern about undefined projects, potential rate impacts, and ratepayer-assistance accountability. --- ### DISTRIBUTED ENERGY RESOURCES Commissioner **Darcie Houck** issued an [amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K758/601758363.PDF?ref=calregulatory.com) in the DER Cost-Effectiveness, Data Access, and Equipment Performance Standards proceeding. The ruling adds a new Track Three to examine guiding principles for the [Avoided Cost Calculator](https://www.cpuc.ca.gov/dercosteffectiveness?ref=calregulatory.com). The rulemaking originally focused on improving the consistency of DER cost-effectiveness evaluations, enhancing data access for DER programs, and establishing equipment performance standards. Phase One of the proceeding already includes two tracks addressing cost-effectiveness methodology and data access rules. Pursuant to a 2025 decision ([D.25-12-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K806/591806164.PDF?ref=calregulatory.com)), which extended the statutory deadline for this docket, additional time and focus are needed to address overarching principles governing the Avoided Cost Calculator. Track Three will consider whether the CPUC should adopt guiding principles for the Avoided Cost Calculator, including how those principles should align with other Commission proceedings (e.g., [Integrated Resource Planning](https://www.cpuc.ca.gov/irp/?ref=calregulatory.com)) and how equity considerations should factor into DER cost-effectiveness evaluations. The CPUC will also examine whether concepts such as accuracy, transparency, and consistency should formally guide the Avoided Cost Calculator framework and how those principles should be defined and applied. The new track is categorized as quasi-legislative, meaning ex parte communications are permitted without restriction or reporting requirements. A proposed decision is scheduled for August 2026. **INSTANT ANALYSIS:** The CPUC is elevating the Avoided Cost Calculator debate from model inputs to policy principles. By opening a separate track to define how the ACC should be guided and aligned with other proceedings, the Commission is inviting parties to shape the underlying logic of DER valuation. The quasi-legislative categorization signals that this will be a policy conversation, not a contested factual one, and the unrestricted ex parte rules give stakeholders wide latitude to engage directly with the assigned commissioner and staff. --- ### SCE ERRA COMPLIANCE A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K846/601846486.PDF?ref=calregulatory.com), tentatively scheduled for consideration on **April 9**, approves SCE's 2023 Energy Resource Recovery Account compliance application, finding that SCE’s procurement activities, contract administration, and recorded fuel and purchased power costs complied with its CPUC-approved procurement plan and applicable rules during the 2023 record year. The PD determines that SCE prudently managed its utility-owned generation resources, administered energy contracts appropriately, and recorded costs in ERRA and related balancing and memorandum accounts accurately. As a result of account balances across several regulatory accounts, the decision directs SCE to reduce its revenue requirement by **$63.195 million** through a rate decrease and to return **$70,811** in unrealized revenues associated with four 2023 Public Safety Power Shutoff events. The PD also addresses two contested issues. - First, Cal Advocates argued that several contracting incidents reflected a pattern of imprudent contract administration and sought three specific remedies: a formal finding of imprudent contracting practices, mandatory disclosure of material contract errors in future ERRA proceedings, and mandatory explanation of corrective measures. - Cal Advocates cited disputes involving Willdan, Sterling Analytics, Brookfield Resource Adequacy contracts, and a Victorville letter-of-credit error. The PD rejects the heightened scrutiny request, finding that the cited incidents were isolated issues that SCE discovered and resolved prudently (in the Brookfield case, SCE's settlement actually produced a direct net benefit to ratepayers above the originally negotiated terms). - However, the PD includes a notable warning: "Two or more errors may give credence to Cal Advocates' assertion of a pattern of imprudent conduct," and encourages parties to exchange the type of information Cal Advocates requested through existing discovery and testimony mechanisms in future proceedings. - Second, the PD reviews SCE's Affiliate Transfer Fee Memorandum Account and finds that the account contains a **$219,000** overcollection, which must be returned to customers. The PD also finds reasonable SCE's mid-2023 shift from a flat 25% affiliate transfer fee to a tiered approach (15–25% based on employee job title). **INSTANT ANALYSIS:** The key takeaway is what did not happen. The PD declines to escalate oversight of SCE's procurement despite pressure from Cal Advocates. For utilities and counterparties, this preserves the current ERRA framework as a retrospective accounting review, not a venue for expanding procurement enforcement. But the outcome is more nuanced than a clean win for SCE. The PD finds the substance of Cal Advocates' information requests reasonable, it just declined to mandate them, instead directing parties to use existing discovery tools. Cal Advocates planted a flag: if SCE produces another contracting incident in a future record year, the "pattern" argument is already framed and waiting. The door was left open, not slammed shut. --- ### SEMPRA UTILITIES' GENERAL RATE CASE SoCalGas/SDG&E provided [notice of an ex parte meeting on February 27](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158231.PDF?ref=calregulatory.com) with advisors to President **Alice Reynolds** and Commissioner **Karen Douglas** regarding the utilities’ Petition for Modification of [D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com) in their 2024 General Rate Case proceeding. (*See CRI's previous coverage* [*here*](https://www.calregulatory.com/deep-dive-the-sempra-ious-5-billion-post-test-year-ratemaking-gambit/) *and* [*here*](https://www.calregulatory.com/monday-aggregate-capital-recovery-attrition-design-decarbonization-cost-allocation-gas-system-continuity-w-o-new-assets/?ref=california-regulatory-intelligence-newsletter)*.*) [The Sempra IOUs’ $5 Billion Post-Test-Year Ratemaking GambitAt issue: The Sempra Utilities claim an adopted mechanism leaves approximately $5 billion in capital-related revenue requirements unfunded![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-58.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/funding1-1.png)](https://www.calregulatory.com/deep-dive-the-sempra-ious-5-billion-post-test-year-ratemaking-gambit/) **At issue:** The Sempra Utilities claim the adopted attrition mechanism leaves approximately **$5 billion** in recurring capital projects inadequately funded during the 2025–2027 post-test-year period. - During the meeting, the Sempra IOUs explained that the decision’s approved attrition mechanism (which applies a flat **3%** annual escalation to the 2024 test-year revenue requirement) does not allow the utilities to recover the full depreciation or rate of return associated with their capital investments during the post-test-year period. - The companies argued that this approach leads to significant under-recovery of capital costs as capital expenditures grow over time. To address this issue, the utilities are proposing a replacement of the current escalation method with a capital-additions attrition mechanism based on a seven-year average of historical and forecast capital spending, which they said is consistent with a Track 1 settlement between the utilities and Cal Advocates. - The companies also noted that parties such as TURN/Southern California Generation Coalition and the Federal Executive Agencies had independently recommended a capital-additions mechanism based on a seven-year average in their respective Track 1 testimony. **INSTANT ANALYSIS**: SoCalGas and SDG&E are pressing the CPUC to revise the attrition formula adopted in the 2024 GRC decision. They argue the current 3% escalation on the test-year revenue requirement does not track actual capital spending and leads to under-recovery of depreciation and return during 2025–2027. The utilities want a capital-additions attrition method based on a seven-year capital average. If accepted, this approach would raise revenue recovery during the attrition period and better align rates with the timing of capital entering service. The presentation included illustrative tables showing that, for a project with a mid-year in-service date, the 3% mechanism produces a cumulative shortfall of **$12.7 million** against what a capital-additions approach would yield, and that over 70% of the companies' capital is recurring work, amplifying the gap across the full portfolio. --- ### GAS SYSTEM RELIABILITY PG&E submitted [Advice Letter 5186-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5186-G.pdf?ref=calregulatory.com) to notify Energy Division that, on March 4, the company’s natural gas backbone transmission system fell below the minimum capacity standard required under prior Commission decisions governing gas system reliability. The applicable standard requires utilities to maintain backbone transmission capacity sufficient to meet the average day demand in a “1-in-10 cold and dry year.” On that date, PG&E calculated total available capacity at 2,372 MMcf/day, which is **121 MMcf/day** below the required threshold of 2,493 MMcf/day. The shortfall is attributed to planned maintenance outages at Delevan Station and the Topock Compressor Station, scheduled from March 4 through March 6. **INSTANT ANALYSIS:** The shortfall is modest and temporary. It does not indicate reliability problems or curtailments. The key point: post-2022 gas planning rules require utilities to formally report any day backbone capacity drops below the benchmark, even during routine maintenance. ### WEDNESDAY AGGREGATE: Rule 21 Interconnection Review Opens; CPUC Expands PG&E 2027 GRC Scope URL: https://www.calregulatory.com/wednesday-aggregate-15/ Last updated: 2026-03-04T23:17:24.000Z Today's roundup includes the following items. - **Interconnection**: A scoping memo in the Rule 21 Update proceeding indicates that the OIR's initial phase will focus on whether the CPUC should: - Modify technical screening tools used to evaluate grid impacts; - Revise interconnection timelines and compliance benchmarks established in 2020; and - Reconsider the **$800** flat interconnection application fee currently applied to non-[Net Energy Metering](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) and non-[Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) resources. - **PG&E 2027 General Rate Case:** An amended scoping memo expands this proceeding to address [Assembly Bill 2666 ](https://calmatters.digitaldemocracy.org/bills/ca%5F202320240ab2666?ref=calregulatory.com)and [Assembly Bill 2847](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202320240AB2847&ref=calregulatory.com), which require the CPUC to examine utilities’ actual-versus-forecasted rates of return, and to evaluate the revenue-requirement impacts of proposed capital expenditures in future applications. - **Risk Assessment and Mitigation**: A [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158225.PDF?ref=calregulatory.com) in the Sempra IOUs' Risk Assessment Mitigation Phase docket directs SoCalGas and SDG&E to provide additional information regarding their 2025 RAMP filings, which will inform the utilities’ upcoming Test Year 2028 General Rate Case application. The ruling demands greater transparency from the IOUs. - **SCE 2022 ERRA Compliance:** A new Edison advice letter implements the CPUC’s January decision in its 2022 Energy Resource Recovery Account compliance proceeding. - **PG&E ERRA Trigger**: PG&E filed an advice letter to establish its 2026 ERRA trigger amount. Based on 2025 generation-related revenues, PG&E sets the 4% ERRA trigger amount at **$166.5 million** and the 5% threshold at **$208 million**. If its net ERRA balance reaches the trigger level and approaches the threshold, PG&E must file an application proposing rate changes to amortize the balance. - **PG&E Hinkley Compressor Station**: An ALJ ruling in PG&E's application for a [Certificate of Public Convenience and Necessity](https://en.wikipedia.org/wiki/Certificate%5Fof%5Fpublic%5Fconvenience%5Fand%5Fnecessity?ref=calregulatory.com) to construct electrical upgrades at the S-238 Hinkley Compressor Station directs PG&E to provide additional information regarding its recent motion to withdraw the application and pursue the project under an emergency exemption. - **Load Control:** SCE filed a report describing the results of its Load Control Management System pilot, a two-year program that tested whether customer-owned load-control technology could allow new electric loads to be energized in grid-constrained areas before distribution upgrades are completed. - **Public Safety Power Shutoffs:** PG&E, SCE, and SDG&E each submitted their 2025 Public Safety Power Shutoff Post-Season Reports in the CPUC’s de-energization rulemaking ([R.18-12-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M251/K987/251987258.PDF?ref=calregulatory.com)). The filings are compliance updates, but they help finalize the official record of 2025 PSPS operations. --- ### **INTERCONNECTION** The CPUC issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158095.PDF?ref=calregulatory.com) in the rulemaking whose focus is to update [Rule 21](https://www.cpuc.ca.gov/Rule21/?ref=calregulatory.com) interconnection rules for Distributed Energy Resources. The proceeding marks the Commission’s next step in adapting Rule 21 to a grid with growing volumes of storage, electric-vehicle charging, and hybrid DER resources. Phase 1 will focus on whether the Commission should: - Modify Screens Q and R (technical screening tools used to evaluate grid impacts); - Revise interconnection timelines and compliance benchmarks established in a 2020 decision ([D.20-09-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M347/K953/347953769.PDF?ref=calregulatory.com)); and - Reconsider the **$800** flat interconnection application fee currently applied to non-[Net Energy Metering](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) and non-[Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) resources. The ruling also outlines a broader set of issues that may be addressed in later phases, including updates to Rule 21 technical standards, communications and interoperability requirements for DERs, alignment with the [Wholesale Distribution Access Tariff](https://www.lawinsider.com/dictionary/wholesale-distribution-access-tariff?ref=calregulatory.com), cost-sharing mechanisms for grid upgrades, and potential changes related to emerging technologies such as vehicle-to-grid systems and plug-in solar. Opening comments on the Phase 1 questions are due **March 11**, with replies due **March 18**. **INSTANT ANALYSIS:** This ruling will first focus on screening failures, utility processing timelines, and the flat $800 application fee for non-NEM resources. These areas represent the main friction points in the DER pipeline, where projects stall after failing technical screens or waiting for utility review. DER developers may push for revised screens or alternative review paths to avoid lengthy cluster studies, while utilities will focus on reliability and ensuring upgrade costs fall on applicants rather than ratepayers. The ruling's interest in D.20-09-035's interconnection timelines suggests a continuing concern with processing delays. The fee issue could also prove significant: moving from a flat $800 charge to cost-based fees would raise application costs for many projects while better reflecting utility workload. --- ### PG&E GENERAL RATE CASE Commission **President John Reynolds** issued a [second amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158439.PDF?ref=calregulatory.com) in PG&E's 2027 General Rate Case, expanding the proceeding to address new statutory requirements enacted in 2024\. The ruling incorporates implementation questions related to [Assembly Bill 2666 ](https://calmatters.digitaldemocracy.org/bills/ca%5F202320240ab2666?ref=calregulatory.com)and [Assembly Bill 2847](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202320240AB2847&ref=calregulatory.com), which require the CPUC to examine utilities’ actual-versus-forecasted rates of return and to evaluate the revenue-requirement impacts of proposed capital expenditures in future applications. - Under AB 2666, the Commission must establish guidelines for utilities to report actual annual rates of return and track deviations from GRC forecasts, including identifying cost categories where forecasts diverged from recorded costs. - AB 2847 requires the Commission to determine whether applications seeking authorization or recovery of capital spending must include estimates of annual revenue-requirement impacts and the [Net Present Value](https://corporatefinanceinstitute.com/resources/valuation/net-present-value-npv/?ref=calregulatory.com) of those impacts over the life of assets placed in rate base. The ruling adds these statutory implementation issues to the PG&E GRC scope and directs PG&E (and other parties) to provide input on how the CPUC should calculate and track actual rates of return, what methodologies should be used to compare forecasted and recorded costs, and what capital-expenditure impact estimates should be required in the application. The ruling also asks PG&E to report its actual annual rates of return for 2023–2026 and explain the methodology used. Responses are due **March 17**. **INSTANT ANALYSIS:** This ruling introduces two new statutory requirements into PG&E’s 2027 GRC that increase scrutiny of both utility earnings and capital spending forecasts. AB 2666 requires the CPUC to examine utilities’ actual-versus-forecasted rates of return and identify cost categories where forecasts diverged from recorded costs, creating a new evidentiary path for parties to challenge forecast accuracy in future rate cases. AB 2847 pushes utilities to show the revenue-requirement and NPV impacts of proposed capital projects, giving intervenors clearer tools to contest large investments before approval. In the near term, PG&E must provide data on its 2023–2026 realized returns, which could widen the record around earnings performance and cost forecasting in the GRC. --- ### SEMPRA UTILITY RAMP SUBMISSIONS A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158225.PDF?ref=calregulatory.com) in the Sempra IOUs' Risk Assessment Mitigation Phase docket directs SoCalGas and SDG&E to provide additional information regarding their 2025 RAMP filings, which will inform the utilities’ upcoming Test Year 2028 General Rate Case application. The ruling follows a review by the CPUC’s Safety and Policy Division, which found that the utilities’ RAMP submissions generally comply with the CPUC’s Risk-Based Decision-Making framework but contain several deficiencies that must be corrected before the GRC is evaluated. Specifically, the ruling directs the utilities to improve transparency and comparability in their risk analyses, including clearer presentation of risk-scaling methods, cross-cycle comparisons of risk results, and documentation of how risk tranches correspond to mitigation programs and cost-benefit ratios. The ruling also requires standardized cost-benefit calculations, explicit justification for mitigation programs with cost-benefit ratios below 1.0, and more granular reporting of underground gas storage risks for SoCalGas. The utilities must incorporate these corrections into their Test Year 2028 GRC filings, provide replicable Excel workpapers supporting their analyses, and submit a roadmap linking each RAMP risk to the relevant GRC testimony by **June 15**. **INSTANT ANALYSIS:** This ruling is demanding greater transparency from SoCalGas/SDG&E regarding how they calculate risk, select mitigation programs, and justify spending. The ruling orders replicable models and Excel workpapers, which gives intervenors a clearer path to challenge risk assumptions and cost-benefit calculations. The ruling also places attention on mitigations with cost-benefit ratios below 1.0 and large shifts in risk values across RAMP cycles. Both issues are likely to become major points of dispute once the 2028 GRC applications are filed. --- ### ERRA COMPLIANCE SCE filed Advice Letter 5756-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters/pending?ref=calregulatory.com)) to implement the CPUC’s decision in its 2022 Energy Resource Recovery Account compliance proceeding ([*D.26-01-003*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K913/594913852.pdf?ref=calregulatory.com)*; see CRI's coverage here.*) [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-54.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--11--4.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) The filing carries out D.26-01-003's findings that SCE prudently managed its procurement activities during the 2022 record year, including administration of utility-owned generation, procurement contracts, least-cost dispatch, and greenhouse-gas compliance. D.26-01-003 also verified the accuracy of SCE’s ERRA-related balancing and memorandum account entries, while approving recovery of **$50.873 million in** undercollected costs, plus franchise-fee and uncollectibles adjustments, for a total revenue requirement increase of about **$51.5 million** to be reflected in future rates. These costs stem from several CPUC-authorized programs and accounts, including residential rate implementation, Integrated Resource Planning costs, a summer reliability demand response program, a climate adaptation vulnerability assessment, and the [Percentage of Income Payment Plan](https://www.sce.com/save-money/savings-programs/ways-to-save-at-home/percentage-of-income-plan?ref=calregulatory.com). Last, the advice letter implements several small disallowances and accounting corrections as ordered by the decision. - SCE must return **$14,547** in unrealized revenues associated with two 2022 Public Safety Power Shutoff events, and remove **$56,500** in CAISO sanctions previously recorded in procurement balancing accounts, shifting those costs to shareholders. - In addition, SCE will eliminate its [Wheeler North Reef Expansion Project](https://marinemitigation.msi.ucsb.edu/sites/default/files/documents/artificial%5Freef/project%5Fdescription%5Fwheeler%5Fnorth%5Freef%5Fphase%5F3%5Fexpansion%5F062317.pdf?ref=calregulatory.com) memorandum account, since the project is no longer incurring costs, and will stop including the permanently offline [Tehachapi Storage Project](https://en.wikipedia.org/wiki/Tehachapi%5FEnergy%5FStorage%5FProject?ref=calregulatory.com) in future ERRA review proceedings. Protests are due **March 23**. **INSTANT ANALYSIS:** The dollar amounts involved with this filing are modest, but it illustrates how a wide range of policy programs (from IRP compliance work to demand-response pilots and affordability programs) ultimately flow through ERRA-adjacent mechanisms and land in rates years after the costs were incurred. --- ### ERRA TRIGGER PG&E filed [Advice Letter 7851-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7851-E.pdf?ref=calregulatory.com) to establish its 2026 ERRA trigger amount, a routine annual calculation required under multiple CPUC decisions governing electric procurement balancing accounts. The ERRA trigger mechanism is designed to prevent large over- or under-collections in utility power procurement accounts. If the net balance of procurement costs and revenues exceeds defined limits relative to prior-year generation revenues, the utility must file an expedited application to adjust rates and amortize the imbalance. For 2026, PG&E calculates total 2025 generation-related revenues of about **$4.16 billion**, derived from ERRA and several related balancing accounts, including: - The Portfolio Allocation Balancing Account; - Modified Transitional Cost Balancing Account; - New System Generation Balancing Account; and - Green Tariff Shared Renewables Balancing Account. Based on these revenues, PG&E sets the 4% ERRA trigger amount at **$166.5 million** and the 5% threshold at **$208 million**. If its net ERRA balance (calculated net of bundled customers’ share of PABA balances) reaches the trigger level and approaches the threshold, PG&E must file an application within 60 days proposing rate changes to amortize the balance. The filing also explains that balances already being amortized through previously approved ratemaking mechanisms are excluded when evaluating whether the trigger is reached, ensuring that only unamortized procurement imbalances are considered. PG&E requests CPUC approval of the calculated trigger and threshold amounts, which would remain in effect until the next annual calculation is adopted. Protests are due **March 23**. **INSTANT ANALYSIS:** The size of the trigger reveals the scale of PG&E’s bundled procurement exposure. A $166.5 million trigger means procurement costs can deviate by that amount before the utility must seek a rate adjustment. That tolerance band gives PG&E substantial room to absorb normal market volatility without returning to the CPUC mid-year. The more meaningful point is the netting of ERRA against PABA balances adopted in recent decisions. By offsetting bundled procurement balances with PCIA-related allocations, the trigger test now filters out cost-allocation noise between bundled and departing-load customers. In practice, that lowers the likelihood of ERRA trigger applications and reduces the chance of sudden procurement-driven rate adjustments. The chief takeaway is that ERRA volatility will show up in rates more slowly than before, because the trigger test now smooths fluctuations that previously could have pushed the account toward the threshold. --- ### **PG&E HINKLEY COMPRESSOR STATION** A [new ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158300.PDF?ref=calregulatory.com) in PG&E's application for a [Certificate of Public Convenience and Necessity](https://en.wikipedia.org/wiki/Certificate%5Fof%5Fpublic%5Fconvenience%5Fand%5Fnecessity?ref=calregulatory.com) to construct electrical upgrades at the S-238 Hinkley Compressor Station directs PG&E to provide additional information regarding its recent [motion to withdraw the application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K051/597051566.PDF?ref=calregulatory.com) and pursue the project under an emergency exemption. The ruling responds to concerns raised by intervenors, including TURN and Cal Advocates, who questioned whether they should proceed with scheduled testimony given PG&E’s request to withdraw the case. [PG&E Looks to Bypass CPCN Review for Hinkley ProjectTopics covered: PG&E’s S-238 Hinkley Compressor Station Electrical Upgrades Project; PG&E’s Billing Modernization Initiative![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-55.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Jan-28-2026--10--3.png)](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/?ref=california-regulatory-intelligence-newsletter) PG&E must submit a compliance filing by **March 11** detailing the electrical equipment failures and component obsolescence issues cited as the basis for initiating the project in January 2026, and explaining how those failures relate to the originally proposed project. The ruling also grants parties additional time to prepare testimony while the Commission evaluates the withdrawal request and PG&E’s new claims. Intervenor testimony is now due **March 25**, PG&E rebuttal testimony **April 17**, and an evidentiary hearing (if needed) is scheduled for **May 14**. The ALJ further asks PG&E to confirm whether construction activity already underway is complying with the mitigation measures identified in the project’s environmental review. **INSTANT ANALYSIS:** PG&E’s attempt to withdraw the Hinkley Compressor Station CPCN application and proceed under an emergency exemption has not been accepted at face value. The ALJ is requiring a March 11 compliance filing detailing the specific equipment failures and obsolescence issues that allegedly forced PG&E to begin the project in January. The ruling preserves the procedural track by extending testimony deadlines rather than suspending the case. PG&E must now demonstrate that the situation meets the threshold for a [General Order 177 ](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com)emergency exemption; if not, the proceeding can continue under the original CPCN review schedule. --- ### **LOAD CONTROL** SCE filed a [report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158430.PDF?ref=calregulatory.com) describing the results of its Load Control Management System (LCMS) pilot, a two-year program conducted from January 2024 through January 2026 to test whether customer-owned load control technology could allow new electric loads to be energized in grid-constrained areas before distribution upgrades are completed. The pilot allowed participating customers (primarily projects such as electric-vehicle charging infrastructure) to operate under approved power-import limits using automated control systems that restricted site demand until grid capacity expansions were finished. SCE evaluated both autonomous local control systems and the concept of communication-based systems that could eventually interact with utility grid-management platforms such as [DERMS](https://www.nlr.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com) and [ADMS](https://www.hitachienergy.com/us/en/products-and-solutions/scada/network-management/network-manager-adms?ref=calregulatory.com). - According to the report, nine projects ultimately participated in the pilot, allowing those customers to energize their facilities an average of about 20 months earlier than if they had waited for grid upgrades, with time savings ranging from five months to more than three years. SCE reports that the participating power-control systems performed reliably and never exceeded approved import limits. - The pilot also tested the process for reviewing and approving customer equipment, including vendor-specific testing and the emerging [UL 3141](https://www.ampcontrol.io/post/ul-3141-power-control-systems-and-the-future-of-ev-charging-stations?ref=calregulatory.com) certification standard for power-control systems. While the program relied on delayed [AMI](https://www.ibm.com/think/topics/advanced-metering-infrastructure?ref=calregulatory.com) meter data rather than real-time telemetry, SCE concluded that the concept worked safely and provided significant value for projects facing energization delays. - Based on the results, SCE recommends continuing the use of LCMS-type “Flexible Service Connections” as a bridge solution for load growth in constrained areas, expanding adoption of UL-certified control equipment, developing better engineering and tracking tools, and eventually moving toward dynamic, communications-based load controls integrated with future grid management systems. The report concludes that the pilot demonstrated a workable pathway for accelerating new load interconnections while maintaining distribution system reliability and supporting state electrification goals. **INSTANT ANALYSIS:** SCE’s LCMS pilot shows a realistic path for energizing new loads in constrained areas before distribution upgrades are complete. Participating projects were energized about 20 months earlier on average, demonstrating that controlled import limits can bridge the gap between load growth and grid expansion. The concept shifts interconnection from a binary model to a managed-load approach, where customers operate below full capacity until upgrades are finished. If adopted more widely, this could accelerate EV charging and other electrification projects without immediate infrastructure buildout. The pilot also exposed operational gaps. Monitoring relied on next-day AMI data rather than real-time telemetry, suggesting that larger deployments will require utility-integrated controls through DERMS/ADMS. Overall, the program points toward Flexible Service Connections becoming a standard tool for managing California’s load growth. --- ### PUBLIC SAFETY POWER SHUTOFFS PG&E, SCE, and SDG&E each submitted their 2025 Public Safety Power Shutoff Post-Season Reports in the CPUC’s de-energization rulemaking ([R.18-12-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M251/K987/251987258.PDF?ref=calregulatory.com)). The filings compile supplemental data and corrections to previously submitted 10-day post-event reports and cover multiple 2025 PSPS events across the state. PG&E reports PSPS activity during January and June 2025 events and updates previously reported metrics, including corrected impacted-customer counts and revisions to the number of circuits and transmission facilities within event scope. - PG&E [documents](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158395.PDF?ref=calregulatory.com) four PSPS events during the year (January 13–15, January 20–21, January 22–24, and June 19–22, 2025) and provides updated operational data required under the CPUC’s PSPS reporting framework. The filing primarily corrects and supplements previously submitted post-event reports. PG&E revised impacted-customer counts for the January 20–21 and January 22–24 events after determining that five customers who received temporary generation had been mistakenly counted as de-energized; the corrected totals reduced the impacted counts slightly. - PG&E also revised the scope of the June 19–22 PSPS event, increasing the reported number of distribution circuits included in the event from 47 to **67**, while simultaneously reducing the count of affected transmission-level facilities from 22 to **nine** after post-season validation. - PG&E further updated its mitigation metrics across the 2025 events. In several cases, the company revised downward the number of customers considered “mitigated,” particularly where backup generation was installed after outages had already begun and therefore did not fully prevent de-energization impacts. - PG&E also includes updated notification-failure explanations and revised mitigation waterfall charts for each PSPS event, reflecting PG&E’s internal root-cause reviews of communication lapses and operational decisions. According to PG&E, some notification gaps occurred when weather conditions escalated more rapidly than forecast models anticipated, resulting in compressed notification timelines during certain events. The utilities also provided additional operational details on how PSPS decisions were made and how impacts were mitigated. - For example, SDG&E [reports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158292.PDF?ref=calregulatory.com) that a January 7–16, 2025 PSPS event ultimately involved de-energization affecting over **23,000 customer accounts** (about 15,000 unique customers) due to extreme wildfire conditions tied to historically dry weather. - SDG&E describes mitigation strategies such as circuit sectionalization that avoided outages for more than **10,000 customers**, deployment of temporary generation at critical community sites, and installation of permanent backup generation at hundreds of premises that had previously experienced PSPS events. - Similarly, SCE’s report [provides ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158545.PDF?ref=calregulatory.com)circuit-level data on 2025 PSPS events, including wind thresholds, fire potential index triggers, and the number of residential, commercial, and medical baseline customers de-energized during specific outages. The filing also details notification performance and identifies instances where some public safety partners or critical facilities did not receive advance PSPS alerts because of messaging errors or rapidly changing weather conditions. **INSTANT ANALYSIS:** These filings are compliance updates, but they help finalize the official record of 2025 PSPS operations. PG&E’s revisions (especially the June event scope change from 47 to 67 circuits) illustrate how utilities refine event data after internal validation, which in turn shapes the dataset the CPUC will use to evaluate PSPS performance and oversight. The reports also highlight utilities’ effort to demonstrate that mitigation tools are reducing outage impacts. Measures such as circuit sectionalization, backup generation, and targeted de-energization are presented as evidence that PSPS events are becoming more precise rather than systemwide. At the same time, the filings acknowledge persistent notification issues, including missed alerts or compressed timelines when weather conditions escalate faster than forecasts. ### March 1, 2026 Rate Roundup: California IOU Natural Gas Rate Increases URL: https://www.calregulatory.com/march-1-2026-rate-roundup-california-iou-natural-gas-rate-increases/ Last updated: 2026-03-04T16:45:57.000Z Below is a consolidated roundup of the March 1 natural gas rate increases that CRI reported on last week. *If you're finding our reports useful, please consider becoming a* [***paid subscriber***](https://www.calregulatory.com/pricing/)*, or* [***inquiring***](https://www.calregulatory.com/contact-us/) *about tailored work for your organization. Our enterprise engagement levels now include *video briefings*, *quantitative analysis/modeling*, and *legislative advisory* work.* --- PG&E, SoCalGas and SDG&E have all filed advice letters to implement **March 1, 2026** natural gas rate changes. Protests to all three filings are due **March 16**. ## Pacific Gas and Electric PG&E filed [Advice Letter 5184-G,](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5184-G.pdf?ref=calregulatory.com) which consolidates adjustments tied to PG&E's 2023 Wildfire Mitigation and Catastrophic Event (WMCE) application, in which PG&E sought recovery of costs incurred primarily in 2022\. That authorization occurred last month in [D.26-02-004.](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K674/597674515.PDF?ref=calregulatory.com) - The authorized amount included **$14.6 million** in gas distribution and **$5.4 million** in gas transmission revenue requirements (including interest and RF&U). - Under the proposal, noncore transportation rates would increase by about **$3.6 million** annually, while concurrent changes to core transportation rates would add roughly **$16.4 million**, producing an overall gas revenue increase of about **$20 million** on an annualized basis. In sum, the filing results in a modest, across-the-board increase, with the entire increase flowing from a single cost recovery driver (last month's WMCE decision). ### Who should care? **Noncore industrial and electric generation customers**. If you're taking gas at distribution, transmission, or backbone level under rate schedules G-NT or G-EG, your transportation rate is moving, effective March 1\. The increases are small but they're real, and if you're running high volumes, the per-therm math adds up. Covered entities should confirm their billing system is properly applying the GHG compliance cost credit to net the increase down. Illustrative rates are available [here](https://www.calregulatory.com/march-1-2026-pg-e-noncore-natural-gas-rate-increase/). --- ## Southern California Gas Company SoCalGas filed Advice Letter 6605-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) to recover **$35.5 million** in costs recorded in its Distribution Integrity Management Program Balancing Account (DIMPBA) for 2019–2023, as authorized by a CPUC decision last month ([D.26-02-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K021/597021734.PDF?ref=calregulatory.com)). - The $35.5 million represents a partial authorization of SoCalGas's [original motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K987/576987593.PDF?ref=calregulatory.com), which had requested interim recovery of 85% of **$59.1 million** in under-collected costs, with the final determination of reasonable spending still pending in the underlying application ([A.25-08-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com)). - The filing also incorporates related rate impacts from SDG&E’s approved non-officer compensation costs under [Resolution E-5405](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K488/595488983.PDF?ref=calregulatory.com) due to system-wide averaging ratemaking between the utilities. - The interim recovery will be collected over a 12-month period using the **Equal Percent of Authorized Margin** (EPAM) allocation method, with any over-collection to be refunded with interest if the CPUC later approves a lower amount. The changes produce modest adjustments across customer classes (primarily increases for core and noncore transportation customers) and update multiple tariff schedules accordingly, with an estimated overall revenue and rate effect of about **0.7%**. The EPAM allocation method and system-wide averaging spread impacts across customer classes and between SoCalGas and SDG&E, softening bill effects for any single group but embedding the costs broadly in transportation rates. Because the recovery is subject to refund if a lower amount is approved later, the advice letter functions as bridge financing for the utility rather than a final determination, though it may create inertia around the interim level. ### Who Should Care? - **Large noncore gas customers, electric generators, and marketers** moving gas on the SoCalGas system should pay attention to this filing because the interim recovery flows directly through transportation rates, raising delivered fuel costs beginning in March. - **Load-serving entities and procurement teams** should also track the filing since system-wide averaging means SDG&E customers are affected as well, and future true-ups could alter cost forecasts. - **Industrial users, liquefied natural gas and biomethane project developers,** and counterparties negotiating gas supply or tolling arrangements, will want to incorporate the higher transportation baseline into contracts and hedging assumptions. - **Intervenors in the DIMP proceeding** should note that, once interim dollars are flowing, reversing them becomes harder even if portions of the spending are later disallowed. Illustrative rates are available [here](https://www.calregulatory.com/march-1-2026-socalgas-rate-increase/). (Related impacts on the company's Sempra peer, SDG&E, are noted below). --- ## San Diego Gas & Electric SDG&E's parallel filing, AL 3498-G (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)), also implements the interim recovery of **$35.5 million** in SoCalGas DIMPBA costs from 2019–2023, albeit on SDG&E's side. The rate changes produce minimal customer bill effects, increasing the typical bundled residential bill per month (by about **0.05%**), while raising SDG&E’s overall gas revenue requirement by roughly **$783,000** across customer classes. SDG&E's adjustments also modify related rate components for electric generation, natural-gas vehicle service, and transmission-level service to maintain alignment with SoCalGas's transportation rates. Ultimately, the filing is a revealing pass-through adjustment that illustrates how upstream SoCalGas cost-recovery decisions propagate across the Sempra gas system, including SDG&E transportation rates. ### Who Should Care? - **Large gas users and transportation customers**. Core commercial, industrial, electric generation, and noncore transportation customers will see small rate changes, tied to SoCalGas system costs flowing through SDG&E tariffs. But even minor per-therm shifts matter at scale for facilities burning millions of therms annually. - **Pipeline operators, storage stakeholders, and safety-cost watchers.** The interim recovery of pipeline integrity spending suggests that safety and compliance costs will continue migrating into rates ahead of final reasonableness findings. Anyone tracking the affordability implications of integrity programs should view this as another incremental step in that trend. - **Energy traders, procurement teams, and load-serving entities.** System-wide transportation alignment confirms that SoCalGas revenue requirement changes remain the anchor for Southern California gas economics. Entities exposed to basis risk, fuel costs, or dispatch economics should incorporate the updated transportation components into forward cost assumptions. Illustrative rates are available [**here**](https://www.calregulatory.com/march-1-2026-sdg-e-natural-gas-rate-increase/)**.** --- ### SDG&E April 1 Filing: Wildfire Track 2 Adds $48 Million/Year; Delivery Rates Up 1.3%, Residential Bills Slightly Down URL: https://www.calregulatory.com/sdg-e-april-1-filing-wildfire-track-2-adds-48-million-year-delivery-rates-up-1-3-residential-bills-slightly-down/ Last updated: 2026-03-03T22:55:09.000Z A new SDG&E Advice Letter (4791-E, available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) implements rates adopted in the company's 2024 General Rate Case Phase 2 decision ([D.25-09-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M601/K153/601153093.PDF?ref=calregulatory.com)) and in the Track 2 wildfire mitigation cost-recovery decision ([D.26-01-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K291/596291467.PDF?ref=calregulatory.com)). These changes will take effect **April 1**. System average electric delivery rates (excluding the [California Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com)) will rise by about **0.3¢/kWh**, or **1.3%**, and total bundled average rates will increase by **0.7%**, primarily due to recovery of 2019–2022 Wildfire Mitigation Plan costs. [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-53.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--11--3.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) SDG&E will amortize **$181.3 million** in electric wildfire undercollections over 45 months, adding approximately **$48.3 million** annually to distribution revenue requirements. Despite the overall rate increase, typical bundled residential bills are projected to decline modestly (**−0.6%** for non-CARE; **−1.5%** for CARE), largely because SDG&E is expanding the weekday Super-Off-Peak period (10 a.m.–2 p.m. year-round), which shifts more usage into lower-priced hours. | TOU Period | Weekdays | Weekends and Holidays | | | | -------------- | ---------------------------------------------------- | ---------------------------------------------------- | --------------- | --------------- | | Summer | Winter | Summer | Winter | | | On-Peak | 4 PM - 9 PM | 4 PM - 9 PM | 4 PM - 9 PM | 4 PM - 9 PM | | Off-Peak | All other hours | All other hours | All other hours | All other hours | | Super Off-Peak | Midnight - 6 AM ; 10 AM − 2 PM 10 AM − 2 PM 10AM-2PM | Midnight - 6 AM ; 10 AM − 2 PM 10 AM − 2 PM 10AM-2PM | Midnight - 2 PM | Midnight - 2 PM | The filing also: - Creates a new Medium Commercial class (20–200 kW, with exceptions for certain schedules); - Restructures commercial monthly service fees through phased annual increases differentiated by class (**15%** for Medium Commercial, **10%** for Large C&I, **7.5%** for Large C&I–Substation, and **5%** for both Small Commercial and Agricultural, capped at marginal cost levels); - Updates revenue allocations across customer classes; - Adjusts marginal distribution costs; and - Maintains existing marginal generation cost differentials based on SDG&E's 2019 marginal cost study. SDG&E is also implementing a three-year glidepath to bring the EV-TOU-5 Super-Off-Peak distribution rate to marginal cost, rising from $0.02601/kWh in Year 1 (April 2026) to **$0.04812/kWh** in Year 3 (January 2028). In addition, SDG&E: - Revises Medical Baseline benefits toward a standardized 20% line-item discount via a glidepath reducing the tiered-schedule discount from 21.64% in 2026 to **9.50%** by 2029; - Increases the commercial CARE (Expanded Low Income) discount from 20% to **35%**; and - Updates various public purpose program and balancing account components consistent with prior CPUC decisions. The following table provides illustrative class-average rates, **inclusive** of the California Climate Credit. SDG&E Advice Letter 4757-E · All rates in ¢/kWh | Customer Class | Current Rates (1/1/2026) | Proposed Rates (4/1/2026) | Total Rate Change | | | | | | | ----------------- | ------------------------ | ------------------------- | ----------------- | --------- | ------ | ------ | ------ | ------- | | Delivery | Commodity | Total | Delivery | Commodity | Total | ¢/kWh | % | | | Residential | 25.650 | 17.532 | 43.182 | 26.302 | 17.549 | 43.851 | +0.669 | +1.55% | | Small Commercial | 23.885 | 15.391 | 39.276 | 24.665 | 15.665 | 40.330 | +1.054 | +2.68% | | Medium Commercial | — | — | — | 20.358 | 18.251 | 38.609 | — | — | | Large Commercial | 18.903 | 19.278 | 38.181 | 18.904 | 19.193 | 38.097 | −0.084 | −0.22% | | Agriculture | 14.350 | 13.041 | 27.391 | 14.288 | 12.009 | 26.297 | −1.094 | −3.99% | | Lighting | 22.940 | 11.994 | 34.934 | 14.545 | 11.981 | 26.526 | −8.408 | −24.07% | | System Total | 21.647 | 17.676 | 39.323 | 21.948 | 17.657 | 39.605 | +0.282 | +0.72% | The table below provides illustrative class-average rates, *excluding* the Climate Credit. SDG&E Advice Letter 4757-E · All rates in cents/kWh | Customer Class | Current Rates (1/1/2026) | Proposed Rates (4/1/2026) | Total Rate Change | | | | | | | -------------- | ------------------------ | ------------------------- | ----------------- | --------- | ------ | ------ | ------ | ------ | | Delivery | Commodity | Total | Delivery | Commodity | Total | c/kWh | % | | | Residential | 28.167 | 17.532 | 45.699 | 28.819 | 17.549 | 46.368 | +0.669 | +1.46% | | System Total | 22.502 | 17.676 | 40.178 | 22.803 | 17.657 | 40.460 | +0.282 | +0.70% | Protests are due **March 23**. ### INSTANT ANALYSIS This is a compliance filing, but it moves real money. SDG&E adds about $48 million per year of Track 2 wildfire recovery into distribution rates through 2029, producing a system average delivery increase of about 1.3%. The near-term rate effect is modest, yet wildfire amortization continues embedding itself in base distribution revenue. The more consequential shift is in rate design. SDG&E creates a new Medium Commercial class (20–200 kW), phases in higher commercial monthly service fees at varying rates by class, and updates customer class revenue allocations. Over time, that shifts more cost recovery toward fixed charges for mid-sized commercial customers. On the residential side, the year-round expansion of the 10 a.m.–2 p.m. Super Off-Peak window strengthens midday load-shifting incentives. Typical residential bills will decline slightly even as average rates rise, showing how TOU design now drives outcomes as much as revenue requirement. The EV-TOU-5 glidepath sends a similar signal on the EV side; SDG&E is steadily repricing its most aggressive promotional rate toward cost. In short, the main themes of this filing are: moderate upward rate pressure, continued wildfire cost-recovery absorption into base rates, and steady recalibration of bill design. ### MONDAY AGGREGATE: Load Growth Caps, PG&E ERRA Compliance; Crimson's 67% Crude Pipeline Rate Hike URL: https://www.calregulatory.com/wednesday-aggregate-14/ Last updated: 2026-03-03T01:13:38.000Z February 2026 ended with a bang; many items surfaced late last week and spilled over into Monday. We're getting you caught up on them now. - **DISTRIBUTED ENERGY RESOURCES/LOAD GROWTH:** The major electric IOUs submitted filings to address a longstanding tension identified in the [High DER proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com): the CEC's IEPR forecasts are system-level and coincident, while distribution planning is circuit-level and based on non-coincident peaks. Applying system caps directly to circuit forecasts can either distort known load data or suppress near-term distribution upgrade needs. Consequently, all three utilities propose formal adoption of a “Non-Coincident IEPR Cap” methodology that reconciles IEPR system forecasts with bottom-up circuit planning. - **PG&E'S ERRA COMPLIANCE**: PG&E's new ERRA compliance filing requests that issues pertaining to the extended operations of Diablo Canyon be excluded from the ERRA venue, arguing those costs are reviewed under a separate statutory framework. - **HYDRO ASSETS:** PG&E filed an application seeking approval under the Public Utilities Code to sell its [4.8-MW Hamilton Branch Hydroelectric Project](https://watershedscience.org/news/2022/12/9/pgampe-seeks-to-sell-hamilton-branch-hydro-facilities?ref=calregulatory.com), located near Lake Almanor in Plumas and Lassen Counties, to Hamilton Branch Hydro, LLC. This is a straightforward portfolio exit of a mothballed hydro unit. - **ARTIFICIAL OIL ISLANDS:** SCE, THUMS Long Beach Company, and the City of Long Beach recently submitted [a Joint Mediation Statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158496.PDF?ref=calregulatory.com) reporting continued progress toward a potential sale of the THUMS Added Facilities from SCE to THUMS. Read our "instant analysis" to understand why this proceeding is not trivial. - **CRUDE OIL TRANSPORTATION:** Crimson California Pipeline L.P. filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158735.PDF?ref=calregulatory.com) with the CPUC seeking authorization to increase rates on its Southern California crude oil pipeline system by **66.97%**, retroactive to **April 1, 2026**. This is a declining-asset ratemaking case. Also, please see our standalone summaries from earlier today covering the [gas utilities' major infrastructure investments](https://www.calregulatory.com/pg-e-and-socalgas-sdg-e-spending-billions-to-perform-gas-system-overhauls/), PG&E's **March 1** [electric rates filing](https://www.calregulatory.com/pg-e-march-1-filing-b-20-transmission-rates-edge-up-while-average-delivery-rates-decline-bundled-2-3-da-cca-1-3-excluding-ghg-returns/), and [the first real test](https://www.calregulatory.com/cpucs-d-22-09-026-exception-pathway-gets-its-first-test-socalgas-rng-projects-may-fall-short/) of the CPUC's narrow exception pathway after it eliminated gas line extension allowances in a 2022 decision (D.22-09-026). --- ### DERS/LOAD GROWTH In recently-filed advice letters, SDG&E (AL 4809-E, available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) and PG&E/SCE ([AL 7850-E/5747-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7850-E.pdf?ref=calregulatory.com)) respond to a 2024 decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)), which requires the utilities to formalize improved methods for setting caps on load growth derived from the California Energy Commission’s [Integrated Energy Policy Report. ](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) The filings address a longstanding tension identified in the [High DER proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com): IEPR forecasts are system-level and coincident, while distribution planning is circuit-level and based on non-coincident peaks. Applying system caps directly to circuit forecasts can either distort known load data or suppress near-term distribution upgrade needs. All three utilities propose formal adoption of a “Non-Coincident IEPR Cap” methodology that reconciles IEPR system forecasts with bottom-up circuit planning. The approach integrates: - IEPR baseline (R/I/C) growth; - IEPR load modifiers such as light-duty and medium/heavy-duty EV and fuel substitution; - Known loads; and - Commission-adopted pending load categories under [Resolutions E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K318/592318785.PDF?ref=calregulatory.com) and [E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K455/592455565.PDF?ref=calregulatory.com). Known loads are modeled at their specific circuit locations and may exceed the IEPR cap. Higher-confidence pending loads may also exceed the cap depending on category and scenario. Specifically, Category A and B1 loads can exceed IEPR under the Base Scenario, and Category B2 loads can exceed IEPR only in designated hot spot areas), while lower-confidence pending loads are limited to IEPR-consistent growth and, if necessary, rolled forward to later years. Both the joint PG&E/SCE filing and SDG&E describe the cap as implementable on either an energy or peak basis depending on the forecast element, with circuit-level growth compared annually to the corresponding IEPR value and with capped pending loads allocated until the IEPR limit is reached. If non-capped load alone exceeds IEPR, capped loads are deferred. If total load remains below IEPR, no cap applies and remaining IEPR headroom is filled with econometric growth. SDG&E presents a functionally similar framework, emphasizing avoidance of double counting and explicit treatment of non-coincident peak effects. Protests are due **March 19**. **INSTANT ANALYSIS:** The IOUs are formalizing a method that lets high-confidence electrification loads exceed IEPR caps at the circuit level while limiting lower-confidence projects. That shifts away from the "borrow forward" approach described by PG&E/SCE and gives distribution planners more room to reflect real interconnection demand. For CRI readers, this affects upgrade timing, queue movement, and rate base growth. If approved as filed, utilities gain clearer authority to plan ahead for EV and fuel-switching load rather than pushing it into later years to match IEPR. --- ### ERRA COMPLIANCE PG&E filed its [2025 ERRA compliance application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158608.PDF?ref=calregulatory.com). It seeks a Commission finding that, for the January 1–December 31, 2025 record period, it complied with its CPUC-approved Bundled Procurement Plan and applicable decisions across: - Generation operations; - Fuel procurement; - Contract administration; - Hedging; - GHG compliance instrument procurement; and - Resource Adequacy sales. PG&E asks the CPUC to confirm that it reasonably managed utility-owned generation, achieved least-cost dispatch, and made accurate entries to ERRA, PABA, and related balancing accounts. The filing also includes required Public Safety Power Shutoff revenue showings and Central Procurement Entity cost reporting. Notably, PG&E is presenting entries to the Modified Transition Cost Balancing Account, Bioenergy Market Adjustment Tariff Non-Bypassable Charge Account, Tree Mortality Non-Bypassable Charge Balancing Account, and New System Generation Balancing Account for compliance review for the first time, based on a stipulation from its 2024 ERRA case ([A.25-02-013](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K607/557607577.PDF?ref=calregulatory.com)). This will expand the scope of what is subject to annual compliance review going forward. PG&E also requests deferral of review for three Utility-Owned Generation outages still in progress at the end of the record period: - Bucks Creek Unit 2; - Cresta Powerhouse Unit 2; and - Elkorn Battery Energy Storage System. Additionally, PG&E requests that Diablo Canyon extended operations be excluded, arguing those costs are reviewed under a separate statutory framework. PG&E frames this as a legal preemption argument under the Public Utilities Code, which provides that there shall be "no further review" of Diablo Canyon extended operations costs if actuals remain below 115% of forecasted costs. PG&E contends the legislature foreclosed ERRA review of extended operations entirely, and that duplicating review in this proceeding risks inconsistent results. No new rate recovery is requested. **INSTANT ANALYSIS:** This is a ledger-protection filing. A disallowance would flow through ERRA and PABA true-ups and ultimately affect bundled rates and PCIA vintages. Areas to watch: least-cost dispatch metrics, whether the Commission accepts PG&E's statutory preemption effort to keep Diablo Canyon extended operations in a separate review track, and whether the expanded balancing account scope invites new intervenor scrutiny. --- ### HYDROELECTRIC ASSETS PG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158397.PDF?ref=calregulatory.com) seeking approval under the Public Utilities Code to sell its [4.8-MW Hamilton Branch Hydroelectric Project](https://watershedscience.org/news/2022/12/9/pgampe-seeks-to-sell-hamilton-branch-hydro-facilities?ref=calregulatory.com), located near Lake Almanor in Plumas and Lassen Counties, to Hamilton Branch Hydro, LLC. The project, originally built in 1921 and acquired by PG&E in 1946, has been in decline since 2016, when one of its two units was mothballed; the second unit followed in 2018, due to the significant capital investment required to restore operations. The transaction includes the powerhouse, dams, water conveyance facilities, non-consumptive water rights, and approximately 6,800 acres of land subject to an existing conservation easement. PG&E conducted a public Request for Offers process beginning in April 2021, selected a winning bidder later that year, but paused negotiations in 2022 while pursuing its [Pacific Generation LLC application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M497/K359/497359207.PDF?ref=calregulatory.com) to transfer all non-nuclear generation assets to a subsidiary. After that application was denied (in a 2024 decision, [D.24-05-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K375/531375060.PDF?ref=calregulatory.com)) PG&E resumed negotiations in 2024 and executed a Purchase and Sale Agreement on January 1, 2026. - PG&E proposes to transfer the project “as-is” and make certain interconnection-related improvements prior to closing. The net book value of the project is approximately **$1.16 million**, and PG&E will make a $19.26 million transfer payment to the buyer, resulting in an estimated pre-tax loss of about $22.29 million. - PG&E asserts that selling the project will save customers between roughly **$38.6 million** and **$61.8 million** compared to refurbishing or decommissioning the facility, due to avoided future capital and operating costs. - PG&E proposes to record the loss in its Portfolio Allocation Balancing Account and recover it consistent with prior CPUC gain-on-sale precedent, with recovery flowing through Power Charge Indifference Adjustment-related mechanisms. - PG&E also requests a categorical CEQA exemption, consistent with prior hydro divestitures, and outlines compliance with tribal notice policies and procedural requirements. PG&E proposes an aggressive procedural schedule. **INSTANT ANALYSIS:** This is a straightforward portfolio exit of a 4.8 MW mothballed hydro unit. PG&E argues the sale avoids $38–$62 million in future refurbishment or decommissioning costs, framing the transaction as a customer savings move. The failed Pacific Generation reorganization is the background context; this asset would have transferred to that subsidiary had the CPUC approved PG&E's application, and PG&E is now unwinding these assets individually. The financial tension sits in the estimated **$22.29 million** pre-tax loss and the proposed PABA/PCIA treatment. Intervenors may question whether ratepayers should absorb the full depreciable asset loss under existing gain-on-sale rules. PG&E invokes the percentage allocation rule of a 2006 decision ([D.06-05-041](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/57114.PDF?ref=calregulatory.com)): 100% of depreciable asset losses go to customers, with a 67/33 customer/shareholder split on non-depreciable assets. Given that approximately 6,800 acres of land represents a significant non-depreciable component of the transaction, the breakdown between depreciable and non-depreciable portions of the $22.29 million loss is likely to draw scrutiny from Cal Advocates. CEQA is positioned as categorically exempt based on continued hydro use. Unless the buyer’s rehab scope expands, approval risk appears low. --- ### ARTIFICIAL OIL ISLANDS/ADDED FACILITIES SCE, THUMS Long Beach Company, and the City of Long Beach recently submitted [a Joint Mediation Statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158496.PDF?ref=calregulatory.com) reporting continued progress toward a potential sale of the THUMS Added Facilities from SCE to THUMS. Following a July 17, 2025 full-day mediation and subsequent negotiations, the parties conducted site visits at the [Pico Substation](https://ia.cpuc.ca.gov/environment/info/pico.htm?ref=calregulatory.com) to plan separation of the THUMS facilities from SCE’s remaining assets and engaged in ongoing calls, email exchanges, and in-person discussions to resolve outstanding issues. And since a January 29 Mediation Status Conference, SCE and THUMS have agreed on a sales price and all three parties are close to finalizing a term sheet, which they expect to complete within 60 days. They will provide a status update at a **March 4** Mediation Status Conference and propose filing a further Joint Mediation Statement by **March 27**, noting that confidentiality limits additional detail at this stage. Previous CRI coverage of this proceeding can be found at the [link below](https://www.calregulatory.com/friday-aggregate-update-on-190-million-thums-oil-islands-cable-replacement-slow-sce-movement-in-microgrid-incentive-program/?ref=california-regulatory-intelligence-newsletter), which provides background on this application. In short, Edison seeks to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the [THUMS artificial oil islands](https://www.calregulatory.com/r/f8f7b1c7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) must be replaced under a new, customer-financed Added Facilities Agreement (with THUMS or any successor customer providing all upfront capital and assuming all removal-cost risk). [Update on $190 Million THUMS Oil Islands Cable ReplacementTopics covered: SCE’s role in the Microgrid Incentive Program, an agreement serving the THUMS artificial oil islands, and PG&E’s RAMP![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-52.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-29-2026--17-.png)](https://www.calregulatory.com/friday-aggregate-update-on-190-million-thums-oil-islands-cable-replacement-slow-sce-movement-in-microgrid-incentive-program/?ref=california-regulatory-intelligence-newsletter) **INSTANT ANALYSIS:** This proceeding is not trivial. If SCE and THUMS finalize a sale of the Added Facilities, the Commission will effectively bless a negotiated unwind of utility-owned infrastructure serving a single, highly specialized customer. That keeps cost responsibility contained and avoids litigating broader [Rule 2](https://studylib.net/doc/18609773/tariff-rule-2.h---southern-california-edison?ref=calregulatory.com) added-facilities doctrine. - For SCE, the upside is balance sheet simplification and reduced long-term operational exposure tied to oil-field infrastructure. - For THUMS and the City of Long Beach, ownership clarity provides control and planning certainty. The key issue for observers is whether the CPUC treats this as a one-off transaction or articulates principles that could be cited in future large-load or co-located infrastructure separations. Most readers will not see immediate rate impacts. The longer-term relevance lies in how the CPUC handles negotiated asset boundary shifts between IOUs and major customers. --- ### CRUDE OIL TRANSPORTATION Crimson California Pipeline L.P. filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158735.PDF?ref=calregulatory.com) with the CPUC seeking authorization to increase rates on its Southern California crude oil pipeline system by **66.97%**, retroactive to **April 1, 2026**. - Crimson argues that, under current rates, it would earn a negative 24.00% overall return on rate base and a negative 48.01% return on equity in the 2026 test year, leaving it unable to cover operating expenses and placing the system at risk of shutdown. - Crimson's supporting declaration (from CEO/CFO **Robert Waldron**) explains that projected 2026 operating expenses increase to approximately **$41.9 million** (excluding depreciation), driven largely by higher integrity, insurance, and shared-cost allocations, with the single largest adjustment being a **$6.0 million** reallocation of unavoidable shared costs following the idling of affiliated [San Pablo Bay](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M593/K603/593603831.pdf?ref=calregulatory.com) and KLM pipelines. (Though the remaining eight test period adjustments collectively add about **$5 million** more across wage reallocations, integrity spending, insurance repricing, and other categories). - Crimson calculates an average original cost rate base of approximately **$52.6 million** and proposes a 4.90% composite depreciation rate to ensure full recovery by 2036, consistent with the CPUC's previously recognized remaining economic life. - Crimson further models an imputed capital structure assuming 40% debt at a 12.0% cost, citing the term loan of its parent company [CorEnergy ](https://www.corenergy.reit/?ref=calregulatory.com)(placed June 2024, maturing **April 2029**) as the best proxy for market debt costs. Crimson itself carries no third-party debt; all debt on its books is intercompany with its parent CorEnergy, which has 100% voting control. The 60/40 debt-equity structure and 12% cost of debt are therefore analytical constructs, not reflections of actual entity-level financing. With the full 66.97% increase, Crimson projects a 13.80% overall return on rate base and a 15% return on equity, which it contends falls within the “zone of reasonableness” under [*Hope Natural Gas*](https://supreme.justia.com/cases/federal/us/320/591/?ref=calregulatory.com) and is necessary to maintain financial integrity and continued operations. **INSTANT ANALYSIS:** Crimson frames this matter as existential. At current rates it projects a negative 24% return on rate base and negative 48% ROE. With the full 66.97% increase, returns move to approximately 13.8% and 15% respectively. Its message is simple: no increase, no viable system. The conflict here will center on three issues: - Cost reallocations after affiliated pipelines were idled, pushing shared overhead onto Southern California crude pipeline shippers (the $6 million SPB/KLM reallocation alone accounts for about half the total test period adjustment, and shippers will challenge whether those costs are properly assignable to this system); - The imputed 12% cost of debt and 60/40 capital structure. Given that Crimson carries zero third-party debt, shippers will argue the CPUC should not impute a 12% borrowing cost for debt that does not exist at the entity level, and the CPUC itself may scrutinize whether the CorEnergy Term Loan is an appropriate proxy; and - A 7.5% annual volume decline forecast, which Robert Waldron justifies by citing California's approximate 8% five-year average production decline and an approximate 7.6% year-over-year throughput drop from 2024 to 2025. This is a declining-asset ratemaking case. The CPUC must decide how aggressively to allow cost recovery for oil infrastructure nearing end-of-life, and who bears the contraction risk as throughput shrinks. ### CPUC’s D.22-09-026 Exception Pathway Gets Its First Test: SoCalGas RNG Projects May Fall Short URL: https://www.calregulatory.com/cpucs-d-22-09-026-exception-pathway-gets-its-first-test-socalgas-rng-projects-may-fall-short/ Last updated: 2026-03-02T22:14:12.000Z Last week, parties filed opening briefs in [A.25-07-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M571/K244/571244390.PDF?ref=calregulatory.com). Recall that, in this application, SoCalGas seeks approval to provide approximately **$4.2 million** in gas line extension allowances for eight non-residential Renewable Natural Gas refueling station projects serving heavy-duty transportation fleets. Additionally, SoCalGas seeks authority to update its non-residential allowance multiplier, revise Tariff Rules 20 and 21, and establish a new balancing account to recover an estimated **$14.9 million** revenue requirement over time. This is the first application filed under an exception pathway created by a 2022 decision ([D.22-09-026](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K987/496987290.PDF?ref=calregulatory.com)) since the CPUC eliminated gas line extension allowances in that same decision. PG&E withdrew both its 2024 and 2025 line extension allowance applications, with PG&E itself acknowledging that there has never been a successful application by any party to use the pathway as a template. ### SoCalGas's Opening Brief SoCalGas [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158167.PDF?ref=calregulatory.com) that each project satisfies the three minimum criteria established in D.22-09-026: - Demonstrable lifecycle GHG reductions; - Consistency with California’s climate goals (including [Senate Bill 32](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=201520160SB32&ref=calregulatory.com) and [CARB’s Scoping Plan](https://ww2.arb.ca.gov/our-work/programs/ab-32-climate-change-scoping-plan?ref=calregulatory.com)); and - A lack of feasible non-gas alternatives. SoCalGas contends that RNG displacement of diesel in refuse, freight, bus, and logistics fleets yields measurable emissions benefits while battery-electric or hydrogen options remain commercially or operationally infeasible for these specific applications. ### Cal Advocates' Opening Brief Cal Advocates [recommends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158062.PDF?ref=calregulatory.com) denial of the application, asserting that SoCalGas failed to meet its burden of proof under D.22-09-026 by relying primarily on unverified customer attestations regarding RNG volumes, emissions reductions, and lack of feasible alternatives, without independently substantiating the factual basis for those claims. Cal Advocates argues that the company’s lifecycle methodology merely plugs customer-provided usage estimates into a formula, that procurement of low-carbon RNG is uncertain, and that the proposed projects therefore do not demonstrate the required GHG reductions or alignment with state climate policy. Cal Advocates also challenges SoCalGas's request to create a new Gas Line Extension Allowance Balancing Account, arguing that the existing Gas Line Extension Balancing Account – established pursuant to the Sempra IOUs' 2024 General Rate Case decision, [D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com) – could be modified to serve the same purpose, and that the CPUC has previously denied new balancing accounts where existing mechanisms are available (citing [D.12-12-029](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K674/40674698.PDF?ref=calregulatory.com)). ### Sierra Club's Opening Brief Sierra Club [likewise urges rejection](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158407.PDF?ref=calregulatory.com), framing the projects as methane-burning vehicle refueling stations inconsistent with California’s long-term electrification trajectory and the CPUC’s prior elimination of categorical line extension allowance subsidies for such infrastructure. - Sierra Club argues that SoCalGas's Application amounts to a collateral attack on D.22-09-026, contending that SoCalGas is effectively seeking the same categorical exemption for Compressed Natural Gas/RNG refueling stations that the CPUC already rejected, presenting boilerplate justifications with little project-specific differentiation rather than the "specific, unique" circumstances contemplated by the decision. - Sierra Club emphasizes stranded asset risk (noting that the gas lines connecting to these stations would not be fully depreciated until 2096) conflict with zero-emission vehicle mandates, and Environmental and Social Justice concerns. It notes that six of the eight projects are in Disadvantaged Communities. Last, Sierra Club cites the Commission's finding in D.24-12-074 that methane-burning vehicle refueling stations in Disadvantaged Communities are inconsistent with the [CPUC's ESJ Action Plan](https://www.cpuc.ca.gov/news-and-updates/newsroom/environmental-and-social-justice-action-plan?ref=calregulatory.com), and introduced unrebutted testimony that Compressed Natural Gas vehicles can produce five to 50 times more ultrafine particulate matter than diesel vehicles certified to the same emissions standard. ### **INSTANT ANALYSIS** This is the first real test of D.22-09-026’s narrow exception pathway after the CPUC eliminated gas line extension allowances. SoCalGas seeks approval for eight RNG heavy-duty fueling projects totaling about $4.2 million in allowances, arguing they meet the three criteria: GHG reductions, climate consistency, and no feasible alternatives. Evidentiary sufficiency will be the central issue in this case. Cal Advocates argues that SoCalGas relied on unverified customer estimates for RNG volumes and emissions reductions. The "no feasible alternatives" criterion may present the weakest evidentiary record: - Customer applicants for Projects D1 and D2 (both waste collection fleet operations) provided essentially bare checkbox responses with no supporting data on range, vehicle types explored, or relative costs; and - Neither Projects C (heavy-duty commercial logistics) nor D explored renewable diesel as an alternative despite customers themselves acknowledging they would retain diesel equipment absent gas infrastructure. Cal Advocates identifies specific categories of missing evidence (route range data, EV models evaluated, refueling time comparisons, and cost analyses) that would constitute reasonable supporting documentation. If the CPUC finds the record thin, it can deny the application without revisiting broader electrification policy. Sierra Club is arguing the stranded asset and ZEV mandate angle, but the collateral attack argument may carry independent procedural weight (if the CPUC views SoCalGas's generalized justifications as functionally recreating the categorical exemption it already rejected, that alone could support denial). The balancing account dispute also offers the Commission a procedural off-ramp: it could deny the new Gas Line Extension Balancing Account even if inclined to approve some projects, forcing SoCalGas to use the existing GLEBA. Approval risks diluting the 2022 elimination decision. Denial reinforces that the exception pathway is real and demanding. ### PG&E and SoCalGas/SDG&E Spending Billions to Perform Gas-System Overhauls URL: https://www.calregulatory.com/pg-e-and-socalgas-sdg-e-spending-billions-to-perform-gas-system-overhauls/ Last updated: 2026-03-04T23:11:14.000Z PG&E and SoCalGas submitted their major, planned natural gas infrastructure investments under the CPUC's [General Order 177](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com) long-term gas planning framework. The filings highlight a statewide wave of large-scale reliability, safety, and compliance projects focused on modernizing aging compressor stations, rebuilding critical transmission and terminal facilities, and replacing or retrofitting high-pressure pipelines through the 2026–2035 period. ### PG&E Update PG&E’s [submission](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158401.PDF?ref=calregulatory.com) emphasizes backbone system reliability work such as compressor replacements at Los Medanos, Topock, Hinkley, and McDonald Island; a major terminal rebuild at Brentwood; a greenfield station replacement at Shingletown; and integrity upgrades to key pipelines. These projects address obsolescence, maintain storage and peak-day supply capability, comply with federal emissions rules, and prevent catastrophic failures that could disrupt gas deliveries. Notably, PG&E's cover letter discloses that the S-238 Hinkley Electrical Upgrades Project commenced emergency construction on January 20, 2026, pursuant to GO 177's unplanned emergency exemption. Component failures and obsolescence issues emerging in Summer 2025 elevated concerns that the Hinkley Compressor Station may not remain functional through the CPCN application period. (*PG&E filed a motion to withdraw A.25-04-004 on February 4; see CRI's coverage* [*here*](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/?ref=california-regulatory-intelligence-newsletter)). A utility invoking the emergency exemption and pulling its own CPCN application is a significant procedural indicator about the deteriorating condition of backbone infrastructure. [PG&E Looks to Bypass CPCN Review for Hinkley ProjectTopics covered: PG&E’s S-238 Hinkley Compressor Station Electrical Upgrades Project; PG&E’s Billing Modernization Initiative![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-51.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Jan-28-2026--10--2.png)](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/?ref=california-regulatory-intelligence-newsletter) PG&E lists estimated capital expenditures for several major backbone projects: - Los Medanos Compressor Replacement (about **$75.6 million**); - Brentwood Station Rebuild (about **$212 million**); - [Topock Compressor Station](https://www.doi.gov/sites/doi.gov/files/migrated/toppock%5Ffact%5Fsheet.pdf?ref=calregulatory.com) Rebuild (about **$288 million**); and - Pipeline integrity upgrade (L-021B segment, about **$50.4 million**). These costs are preliminary and subject to change as engineering progresses. PG&E also notes that many projects are early-stage, with some costs still "to be determined," particularly where detailed engineering has not yet begun. Three projects (Hinkley, McDonald Island, and Shingletown) have no cost estimates at this time. ### The Sempra IOUs' Update The [SoCalGas/SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158498.PDF?ref=calregulatory.com) report identifies 10 total projects meeting GO 177 thresholds, including a billion-dollar compressor modernization at Honor Rancho and near-billion-dollar modernizations at Moreno and Ventura, major pipeline replacements tied to the Pipeline Safety Enhancement Plan, transmission retrofits, and integrity remediation work driven by both federal safety mandates and actual inspection findings. Two projects from the Sempra IOUs' 2025 report were removed from the current filing: - Playa Del Rey Upgrade RECLAIM Lean Burn (placed in service Q4 2025); and - Line 3000 Hydrotest (broken into sub-threshold projects). Overall, the Sempra IOUs' investments are framed primarily as safety compliance, emissions reduction, and system resilience measures necessary to sustain reliable gas service for residential, industrial, and electric-generation demand. They also conform with increasing air-quality and pipeline safety requirements, and their in-service dates stretch into the early 2030s and beyond. The Sempra Utilities' report shows even larger figures than PG&E does, including several mega-projects: - Moreno Compressor Modernization (SDG&E, about **$911 million**); - [Honor Rancho Compressor Modernization](https://www.socalgas.com/sustainability/pipeline-and-storage-safety/storage-facility-safety/honor-rancho-modernization?ref=calregulatory.com) (about **$1.058 billion**); - [Ventura Compressor Modernization](https://www.socalgas.com/sustainability/pipeline-and-storage-safety/ventura-modernization?ref=calregulatory.com) (about **$578 million**); - Line 85N Elk Hills–Lake Station Replacement (about **$185 million**); - Supply Line 38-539 Replacement (about **$73 million**); - Line 85N Lake Station–Grapevine Replacement (about **$261 million**); - SL 44-306/44-307 Retrofits (approximately **$67–68 million** each); - Line 85-Section 5 Replacement (approximately 50 miles of PSEP Phase 1B pipeline, **cost TBD**); and - Line 235 West Assessment: Newberry Springs to Victorville. The latter project is driven by PHMSA and the Transmission Integrity Management Program. An October 2024 inline inspection identified 16 immediate repair conditions that were already repaired, plus 18 two-year conditions scheduled for Q2 2026\. The full remediation scope and cost have yet to be determined. ### INSTANT ANALYSIS These filings confirm that California’s gas utilities are advancing a long-duration capital cycle to rebuild the foundations of their gas systems, even as official policy narratives emphasize electrification and load decline. The scale (individual projects in the hundreds of millions to over $1 billion) indicates utilities are planning for continued operational dependence on the gas network for peak reliability, storage management, and electric-sector support well into the 2030s. The Hinkley emergency construction episode underscores that this dependence is not theoretical; backbone infrastructure is already degrading faster than planned replacement timelines can accommodate. - From a regulatory strategy perspective, GO 177 reporting is functioning as a pipeline of future rate base, not merely a transparency exercise. Many projects are framed as safety, emissions compliance, or obsolescence replacements rather than expansions, a positioning that aligns with CPUC tolerance for reliability spending even under decarbonization mandates. This suggests the Commission is likely to face increasing tension between gas transition policy and the need to authorize large capital recovery to avoid reliability risks. - For market participants, the practical implication is that gas system costs are not plateauing; they are resetting upward. As throughput declines over time, fixed costs from these investments will be spread across a shrinking customer base, intensifying affordability pressure and raising the probability of future cost-allocation battles (e.g., exit fees, non-bypassable charges, or electrification cross-subsidies). Many projects are also located in ESJ communities, increasing the political sensitivity of cost-recovery decisions. Most importantly, the filings suggest that California is entering a phase where the gas system becomes a strategic reliability backstop rather than a growth platform. That transition typically produces regulatory shock points: stranded asset debates, accelerated depreciation proposals, and potential pressure for state intervention if customer bills spike. Stakeholders should treat these reports as early indicators of future proceedings where the central question will shift from “whether to invest” to “who pays for a shrinking but indispensable system." ### PG&E March 1 Filing: B-20 Transmission Rates Edge Up While Average Delivery Rates Decline (Bundled −2.3%, DA/CCA −1.3%, Excluding GHG Returns) URL: https://www.calregulatory.com/pg-e-march-1-filing-b-20-transmission-rates-edge-up-while-average-delivery-rates-decline-bundled-2-3-da-cca-1-3-excluding-ghg-returns/ Last updated: 2026-03-02T19:17:06.000Z PG&E submitted [Advice Letter 7846-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7846-E.pdf?ref=calregulatory.com) to implement electric rate and tariff changes effective March 1, incorporating multiple revenue requirement adjustments and rate-design directives previously approved by the CPUC and FERC. The filing produces modest average rate decreases (about **2.%** for bundled customers and **1.3%** for Direct Access and Community Choice Aggregation customers for PG&E-provided services) while updating numerous cost components, including transmission balancing account charges, wildfire mitigation cost recovery, securitization bond charges/credits, and other balancing-account true-ups. In parallel, the advice letter finalizes major changes to residential rate design mandated by prior CPUC decisions, most notably the rollout of an income-graduated fixed Base Services Charge (approximately **$6**/month for [CARE](https://webtraining.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com) customers, about **$12** for [FERA](https://www.pge.com/en/account/billing-and-assistance/financial-assistance/family-electric-rate-assistance-program-fera.html?ref=calregulatory.com) or income-qualified households, and **$24.15** for all others). This charge is intended to improve affordability and support electrification policy goals. The filing also adjusts certain minimum bill levels for inflation, closes obsolete balancing accounts, updates wildfire hardening bond recovery charges, and implements tariff revisions reflecting these changes. Protests are due **March 19**. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/03/table-march-1.png) ### INSTANT ANALYSIS This filing is a classic “rates down, bills restructured” package: small volumetric decreases that will be partly offset (especially for many residential customers) by the new fixed charge architecture. The Base Services Charge shifts cost recovery away from usage and toward fixed revenue stability, which reduces conservation price signals and makes load growth (including electrification) less financially risky for the utility. For CCAs and Direct Access providers, the modest delivery-rate reductions slightly improve the optics of non-utility supply but do not materially change competitive positioning; the bigger implication is that the fixed charge dampens the bill savings customers perceive from switching suppliers. In sum, the advice letter shows wildfire financing, securitization, and infrastructure cost recovery continuing to flow through rates in incremental layers, reinforcing that California’s affordability problem is being managed through rate design engineering rather than cost containment. ### FRIDAY AGGREGATE: Woolsey Fire Update; IOUs' Energization Costs; SCE's IT/Enterprise Resource Funding URL: https://www.calregulatory.com/friday-aggregate-woolsey-fire-update-ious-energization-costs-sces-it-enterprise-resource-funding/ Last updated: 2026-02-27T21:08:24.000Z Today's report includes the following items. - **WOOLSEY FIRE:** A prehearing conference convened in the proceeding where SCE seeks a financing order under the Public Utilities Code to securitize **$1.951** billion in Woolsey Fire-related costs recorded in its Wildfire Expense Memorandum Account. Relatedly, a **Commissioner Matt Baker** scoping memo sets an intervenor testimony deadline of **March 4**. - **ENERGIZATION**: PG&E, SCE, and SDG&E jointly filed a motion in [R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com) seeking authorization to establish memorandum accounts to track costs associated with funding an Energy Division contract to analyze energization data. - **ENTERPRISE RESOURCE PLANNING:** In February 20 reply briefs, parties offered conflicting views on SCE's [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M559/K223/559223108.PDF?ref=calregulatory.com) to recover costs for its NextGen Enterprise Resource Planning program. SCE argues the program is necessary because its existing ERP system faces imminent obsolescence, posing operational and cybersecurity risks. - **NATURAL GAS RESEARCH**: PG&E filed an application for rehearing of CPUC Resolution G-3618, arguing that the CPUC unlawfully denied recovery of approximately **$7.2 million** in Gas Research, Development, and Demonstration program costs incurred in 2023-2024. - **NATURAL GAS STORAGE:** A SoCalGas advice letter lowers the storage injection fuel retention, which slightly improves the economics of injecting gas into storage ahead of the new storage year. --- ### WOOLSEY FIRE A February 19 [prehearing conference convened](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K101/600101062.PDF?ref=calregulatory.com) in the proceeding where [SCE seeks CPUC approval for a financing order under the Public Utilities Code to securitize **$1.951** billion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com) in Woolsey Fire-related costs recorded in its Wildfire Expense Memorandum Account (WEMA), which were found just and reasonable in the December 2025 settlement decision ([D.25-12-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K453/592453458.PDF?ref=calregulatory.com)). SCE's position is that securitization through recovery bonds will lower financing costs passed to ratepayers compared to the alternative established in the settlement: a five-year amortization financed with long-term debt. At the prehearing conference, Cal Advocates highlighted two areas of particular focus: - The appropriate duration and tenor of the recovery bonds (noting that in the Thomas Fire case, SCE initially proposed 35-year bonds before the parties agreed to a weighted average of up to 20 years); and - The cumulative ratepayer impact of these bonds layered on top of Edison's three prior [Assembly Bill 1054](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=201920200AB1054&ref=calregulatory.com) financing orders and the Thomas Fire bonds. SCE and Cal Advocates agreed these issues are fairly subsumed within the broader Thomas Fire scoping framework. Cal Advocates does not currently anticipate factual disputes but indicated it is preparing data requests and will focus its testimony on bond duration and bill impacts, including analysis of tenors ranging from 15 to 30 years. A notable exchange occurred around the interpretation of the Woolsey settlement decision. Edison maintained the settlement offered only two paths: securitization or five-year amortization, and suggested this binary framing influenced its decision to settle. **ALJ DeAngelis** pushed back, suggesting the CPUC is not necessarily limited in this proceeding to evaluating only those two options, particularly regarding alternative amortization periods. Cal Advocates aligned with the ALJ's broader reading. The issue was left unresolved but noted for the record. **Commissioner Matt Baker**'s prepared remarks struck a balanced tone, acknowledging securitization as a valuable tool to ease rate shock while cautioning that the details (particularly bond duration and ultimate ratepayer impact) require careful scrutiny. --- Commissioner Baker's subsequent [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158717.PDF?ref=calregulatory.com) formally adopted nine scoped issues centered on: - Whether the proposed bonds are just, reasonable, and consistent with the public interest; - Whether they reduce rates relative to traditional financing; - The appropriate customer allocation for fixed recovery charges; and - Reporting requirements. Intervenor direct testimony is due **March 4**, rebuttal testimony **March 6**, with a status conference that same day to determine whether evidentiary hearings (set for March 9) are actually needed or whether parties will stipulate testimony into the record. Opening briefs are due **March 16**, reply briefs **March 23**, and all parties agreed to a shortened Section 311 comment period. **INSTANT ANALYSIS:** The battle here isn't whether SCE securitizes $1.951 billion in Woolsey costs (D.25-12-023 already blessed recovery), it's how long ratepayers carry the bonds. - Cal Advocates is modeling tenors from 15 to 30 years and cited cumulative stacking with Edison's three existing AB 1054 orders plus the Thomas Fire bonds, which is new analytical territory that could set precedent for every future Section 850 filing across all three IOUs. - Meanwhile, ALJ DeAngelis pushed back hard on Edison's claim that the Woolsey settlement locked the Commission into a binary choice of securitization or five-year amortization, suggesting the CPUC retains authority to evaluate alternative amortization periods. Edison's counsel warned that such a reading could retroactively undermine the settlement framework itself. The March 4 Cal Advocates testimony will define the entire range of dispute, and the present-value comparison between securitization savings and shorter-tenor alternatives becomes the decisive exhibit. --- ### ENERGIZATION PG&E, SCE, and SDG&E jointly [filed a motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158480.PDF?ref=calregulatory.com) in [R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com) seeking authorization to establish memorandum accounts to track their costs associated with funding a CPUC Energy Division contract to analyze energization data. The motion implements language in a 2024 decision ([D.24-09-020](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K806/540806654.PDF?ref=calregulatory.com)), which requires the large electric utilities to collectively fund **$1 million** per year for five years to improve the CPUC’s ability to collect, analyze, track, and publicly report energization data and progress toward adopted energization and upstream capacity upgrade targets. Each utility’s share would be allocated based on its percentage of California-jurisdictional electric revenues as of the decision’s issuance, with PG&E and SCE each responsible for about **47%** and SDG&E about **6%**. The utilities explain that the CPUC directed them to establish these accounts so the Energy Division’s contracting costs can be recorded but not recovered from ratepayers unless later approved in a ratesetting proceeding. They also note uncertainty regarding whether the $5 million contract funding is distinct from or part of a separate “Commission-managed evaluation budget” to be sought through the state budget process, requesting clarification on that point. If approved, each utility would file advice letters to formally create the memorandum accounts, enabling the CPUC to bill them for the contract costs once the Executive Director executes the agreement. **INSTANT ANALYSIS:** This filing is a procedural compliance step. The IOUs are seeking to track (not yet recover) their shares of a $5 million CPUC-directed contract to strengthen Energy Division oversight of energization timelines, with any ratepayer recovery deferred to a later proceeding. The overarching story, though, is that the Commission is building a permanent data-monitoring function around interconnection performance. That points to tougher scrutiny of utility timelines going forward and potential downstream pressure if targets are missed. --- ### ENTERPRISE RESOURCE PLANNING In February 20 reply briefs, parties offered conflicting views on SCE's [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M559/K223/559223108.PDF?ref=calregulatory.com) to recover costs for its NextGen Enterprise Resource Planning (ERP) program. - SCE [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083290.PDF?ref=calregulatory.com) the program is necessary because its existing ERP system faces imminent obsolescence, posing operational and cybersecurity risks, and contends that its cost forecasts, implementation plan, risk management approach, and projected long-term benefits are reasonable and supported by extensive evidence. SCE seeks approval of approximately **$1.08 billion** in capital expenditures, **$238 million** in O&M costs, and a two-way balancing account to manage cost uncertainty while returning savings to customers. - SCE argues that parties' failure to respond to its rebuttal testimony in their reply briefs should be treated as a concession on those issues, and contends that delaying the business transformation scope would increase costs by 30% and reduce customer savings by 20%. - Cal Advocates [maintains](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K064/600064192.PDF?ref=calregulatory.com) that SCE has not met its burden of proof for many disputed costs, recommends approving substantially reduced funding, and opposes the requested two-way balancing account on legal and policy grounds, arguing it would shift risk to ratepayers during an affordability crisis. - Cal Advocates also argues that **$212.754 million** already authorized in SCE's 2025 General Rate Case should be applied to fund NextGen ERP implementation and that SCE has not demonstrated why costs from completed or obsolete IT projects cannot be reallocated, and raises procedural concerns about SCE's late-filed 2024 recorded data compromising Cal Advocates' ability to conduct a thorough review. - Small Business Utility Advocates (SBUA) [likewise urges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K260/600260844.PDF?ref=calregulatory.com) denial or major modification of the application, emphasizing the high risk of cost overruns, delays, overstated benefits, and near-term rate impacts, and proposing that only limited "obsolescence" work proceed (if at all) under stricter cost controls tied to demonstrated benefits. - SBUA proposes that SCE's rate of return on capital be contingent on achieving a positive benefit-cost ratio, a mechanism SCE characterizes as unprecedented and akin to retroactive ratemaking, citing multiple court decisions and CPUC precedents rejecting similar benefit-contingent penalties. SBUA also aligns with TURN's stance in this proceeding that excess cost recovery should require a separate application and that any cost overrun review must consider whether SCE delivered forecasted benefits**.** **INSTANT ANALYSIS**: This proceeding is about who bears digital transformation risk. SCE is framing the ERP replacement as unavoidable infrastructure due to system obsolescence, while intervenors argue the broader transformation is discretionary and should not be financed by ratepayers. - The first question that needs answering is whether the Commission will approve the approximately $482 million transformation scope at all (both SBUA and TURN argue it should be denied outright, with SBUA proposing SCE defer to its next GRC). - If the Commission denies the transformation scope, the balancing account debate becomes moot for nearly half the requested funding. If some or all of the program advances, the conflict shifts to the requested two-way balancing account. Approval would shift cost-overrun risk to customers and set a precedent that large utility IT modernization qualifies as recoverable infrastructure. Denial would keep that risk with shareholders. In short, this case is a testing ground for whether enterprise software inevitably becomes rate-base infrastructure in California. --- ### NATURAL GAS RESEARCH PG&E filed an [application for rehearing ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M601/K158/601158474.PDF?ref=calregulatory.com)of CPUC [Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K045/595045490.pdf?ref=calregulatory.com), arguing that the Commission unlawfully denied recovery of approximately **$7.2 million** in Gas Research, Development, and Demonstration program costs incurred in 2023 ($3.53 million) and 2024 ($3.67 million). [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-50.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--11--2.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) - PG&E contends the Commission misinterpreted the 2023 General Rate Case decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)) by applying a new requirement for pre-approval of RD&D spending retroactively, even though the decision directed PG&E to submit its first pre-approval plan by June 1, 2024 (implying applicability beginning with 2025 spending). PG&E pointed out this timing concern in its October 2023 comments on the proposed decision. - PG&E argues it was impossible to comply with pre-approval requirements for expenditures already incurred or underway, making denial of cost recovery arbitrary, inconsistent with treatment of similar requirements imposed on SoCalGas, and an abuse of discretion. - PG&E also raises an equal protection claim under both the California and U.S. Constitutions as an independent ground for reversal, arguing the Commission treated functionally indistinguishable utilities differently without justification. PG&E requests that the CPUC grant rehearing, allow recovery of the disputed costs in a balancing account, or alternatively modify the underlying decision to clarify that the pre-approval framework applies prospectively starting in 2025 rather than retroactively to 2023–2024 spending. Notably, PG&E invites the Commission to construe the rehearing application as a petition for modification of D.23-11-069, offering the Commission a procedural off-ramp to correct course without conceding legal error. **INSTANT ANALYSIS:** This rehearing request tests whether the CPUC can enforce new pre-approval rules on spending that occurred before those rules could realistically be followed. If the CPUC holds the line, utilities face higher risk that late GRC directives can retroactively jeopardize recovery for RD&D and pilot programs. If the Commission relents, it preserves the norm that new oversight mechanisms apply prospectively, not mid-stream. The petition-for-modification alternative makes the second outcome more likely by giving the Commission a face-saving path to resolution. The context is: small dollars, real precedent. The outcome will indicate how aggressively the CPUC plans to control utility discretion over gas-system innovation spending during the transition period. --- ### NATURAL GAS STORAGE SoCalGas filed Advice Letter 6607-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) to revise its gas storage tariffs by reducing the In-Kind Energy Charge applied to customer gas injections from 8.93% to **6.88%**, effective **April 1**. The filing updates Schedule Nos. G-BSS (Basic Storage Service), G-LTS (Long-Term Storage Service), and G-TBS (Transaction-Based Storage Service) in accordance with: - A 2009 decision ([D.09-11-006](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/110307.PDF?ref=calregulatory.com)), which established that the injection fuel rate be recalculated annually using a three-year rolling average of actual fuel use; and - A 2016 decision ([D.16-06-039](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M164/K355/164355965.pdf?ref=calregulatory.com)), which authorized SoCalGas to sell equivalent gas compressor fuel volumes to cover electricity costs for electric compressors at its storage fields. The proposed decrease reflects updated operational data and cost adjustments, including electricity costs associated with electric compressors installed under the Aliso Canyon Turbine Replacement project, with projections based on 2023–2025 performance data and forward market prices. Attachment B — In-Kind Energy Charge Calculation 2023–2025 Operations Data (Non-Aliso Gas-Fired Compression) | 3-Year Fuel Usage | 1,762,869 Mcf | | ---------------------- | -------------- | | 3-Year Injection Total | 93,989,452 Mcf | | Gas Compression Rate | 1.84% | 2026–27 Storage Year Forecast | | Fuel (Mcf) | Injections (Mcf) | | ------------------------ | ---------- | ---------------- | | Gas Compression | 187,449 | 10,000,000 | | ACTR Electric Equivalent | 1,378,998 | 11,200,000 | | 2026 Totals | 1,566,000 | 21,200,000 | In-Kind Energy Charge Effective April 1, 2026 8.93% → 6.88% Fuel Requirement Composition ■ Gas Compression (12%) ■ ACTR Electric (88%) **INSTANT ANALYSIS:** This filing lowers the storage injection fuel retention to 6.88%, slightly improving the economics of injecting gas into SoCalGas storage ahead of the new storage year. The change reflects updated fuel-use data and projected electricity costs for electric compressors, not a policy shift. Notably, the electric-equivalent fuel component now represents roughly 88% of the forward-looking fuel requirement in the calculation, meaning power prices are already playing a larger role in shaping gas storage charges than the underlying gas compression itself. ### WEEKEND NEWS CODEX: California Offshore Drilling; 6 GW of Non-Fossil Fuel Capacity; Diablo Canyon Milestone URL: https://www.calregulatory.com/weekend-news-codex-9/ Last updated: 2026-02-27T18:04:28.000Z - **Banned in California – the Electric Car:** "Building an EV requires metal forging, battery manufacturing, painting, and chip fabrication — all processes that drove Tesla to build in Nevada and Texas." [**BANNED IN CALIFORNIA**](https://www.bannedincalifornia.org/?ref=calregulatory.com#car-section) - **BOEM Eyes California Offshore Drilling:** "BOEM highlighted that a Notice of Intent will be published in the Federal Register today and pointed out that this will open a 30 day public scoping period, 'during which BOEM invites input from tribal, state, and local governments, stakeholders, and the public.'" [**RIGZONE**](https://www.rigzone.com/news/boem%5Feyes%5Fcalifornia%5Foffshore%5Fdrilling-27-feb-2026-183089-article/?rss=true&ref=calregulatory.com) - **California Orders Utilities to Add 6 GW of Non-Fossil Fuel Capacity by 2032:** "The order mandates that 2 GW be brought online by 2030, then the same in 2031 and 2032\. Each LSE’s procurement obligation has been determined by its share of the managed peak on the electric system as of this year, with [load forecasts taken into account](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K854/600854771.pdf?ref=calregulatory.com), the CPUC said." [ **UTILITY DIVE**](https://www.utilitydive.com/news/cpuc-california-lses-procure-6-gw-2032/813357/?ref=calregulatory.com) - **California Turns to Imports as its Refineries Close:** "California has had as many as [42 refineries 40 years ago](https://www.msn.com/en-us/money/markets/phillips-66-shuts-down-in-california-with-no-clear-plan-for-who-pays-2b-cleanup-bill/ar-AA1STDti?ref=calregulatory.com), and since 2000, its [operational refineries dropped from 23 to 12 at the end of 2025](https://oilprice.com/Energy/Energy-General/Californias-Oil-Rush-Slips-Into-Its-Final-Act.html?ref=calregulatory.com). Phillips 66 shuttered its Los Angeles refinery in October, and [Valero will shutter its Northern California refinery this spring](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/californias-refinery-situation-looks-like-it-will-get-worse/?ref=calregulatory.com), bringing the number of refineries in the state to 11." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/california-turns-to-imports-as-its-refineries-close/?ref=calregulatory.com) - **California Wants Millions of Heat Pumps – High Power Bills Might Get in the Way:** "**Quentin Gee**, a manager at the California Energy Commission, said the advantage of heat pumps comes down to thermodynamics. Unlike a gas furnace, which burns fuel to create heat, a heat pump compresses and expands a refrigerant, like a refrigerator in reverse. That moves heat from outside into a home — allowing it to deliver several units of heat for every unit of electricity it uses. Even in PG&E territory, where electricity rates may be some of the highest in the U.S., Gee said that efficiency can allow heat pumps to compete with — and in some cases beat — gas on operating costs, depending on local rates and home characteristics. In lower-cost municipal utility regions such as Sacramento’s SMUD, he said heat pumps can be a clear financial win." [**CAL MATTERS**](https://calmatters.org/environment/2026/02/heat-pumps-ca-electricity/?ref=calregulatory.com) - **Can Energy and Water Interests Find a Common Agenda?** "Examples of the water/energy nexus abound. It would only take [3,500 gigawatt-hours to power](https://www.desware.net/energy-requirements-desalination-processes.aspx?ref=calregulatory.com) seawater desalination plants with the capacity to produce *one million* acre feet of fresh water. That’s barely one percent of the state’s total [annual electricity consumption](https://www.energy.ca.gov/data-reports/energy-almanac/california-electricity-data/2024-total-system-electric-generation?ref=calregulatory.com). These innovations, combined with practical policy revisions and project choices, could enable California’s water consumers to negotiate a grand bargain and common agenda, one that could unite disparate interests from the Central Valley and Imperial Valley to the great coastal cities." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/can-energy-and-water-interests-find-a-common-agenda/?ref=calregulatory.com) - **Case Study – the Lights are On at PG&E to Build Smarter, Stronger, Sustainable Grid:** "...PG&E, supported by IFS Copperleaf, began an integrated grid planning initiative in 2024\. IGP provided a strategic decision-making layer that enables PG&E to answer critical questions such as 'What work should we do? When should we do it? And how can we execute it most efficiently?'" [**RENEWABLE ENERGY WORLD**](https://www.renewableenergyworld.com/power-grid/grid-modernization/case-study-the-lights-are-on-at-pge-to-build-a-smarter-stronger-sustainable-grid/?ref=calregulatory.com) - **CEC Report Warns California's Reliance on Imported Energy Creates Supply Risks:** "The California Energy Commission in December 2025 [released](https://www.energy.ca.gov/publications/2025/california-energy-security-plan?ref=calregulatory.com) an updated California Energy Security Plan, evaluating risks across the state’s electricity, natural gas, and transportation fuel systems. The report, [presented](https://www.energy.ca.gov/filebrowser/download/9382?fid=9382&ref=calregulatory.com) by staff at the CEC’s February 11 meeting, outlines vulnerabilities in California’s energy supply and establishes planning frameworks for preventing and responding to disruptions. The analysis highlights the state’s reliance on energy imports as a central risk factor. California imports approximately 30% of its electricity, about 90% of its natural gas, and roughly 75% of its petroleum supply, according to the report. Much of that energy reaches the state through interstate pipelines, high-voltage transmission lines, and marine shipping routes." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/cec-report-warns-californias-reliance?ref=calregulatory.com) - **Diablo Canyon Clears Last California Permit Hurdle to Keep Running:** "Central Coast Water authorities approved waste discharge permits for Diablo Canyon nuclear plant Thursday, making it nearly certain it will remain running through 2030, and potentially through 2045\. The Pacific Gas & Electric-owned plant was originally supposed to shut down in 2025, but lawmakers extended that deadline by five years in 2022, fearing power shortages if a plant that provides about 9 percent the state’s electricity were to shut off." [**LA TIMES**](https://www.latimes.com/environment/story/2026-02-26/la-enviro-diablo-canyon-clears-last-state-permitting-hurdle-to-keep-running?ref=calregulatory.com) - **Diablo Canyon Nuclear Power Plant Takes Big Step Toward Extending Life Until 2030:** "Now that PG&E secured a coastal development permit from the California Coastal Commission and a wastewater permit and Clean Water Act certification from the water quality board — there’s only one step left to keep the power plant running until 2030\. The U.S. Nuclear Regulatory Commission must decide whether to issue a 20-year operating license to PG&E for the power plant. PG&E representative Tom Jones said he expects the commission to make a decision about the license during the second quarter of the year." [**SACRAMENTO BEE**](https://www.sacbee.com/news/california/article314852996.html?ref=calregulatory.com) - **High Costs and Few Benefits From California's Proposed Sustainable Aviation Fuel Tax Credit:** "Decarbonizing aviation will be [challenging](https://energyathaas.wordpress.com/2025/10/06/what-if-we-required-airplanes-to-use-more-biofuels/?ref=calregulatory.com). Current batteries are too heavy and hydrogen takes up too much space, which leaves liquid fuels as the dominant energy source for the next few decades. However, promoting SAF only makes sense if it creates a clear path to future cost reductions and carefully manages the unintended consequences." [**ENERGY AT HAAS**](https://energyathaas.wordpress.com/2026/02/23/high-costs-and-few-benefits-from-californias-proposed-sustainable-aviation-fuel-tax-credit/?ref=calregulatory.com) - **Largest Solar Farm in US Coming to Central Valley in California:** "Project owners bill this as a huge boon to California, helping it reach its aggressive clean energy requirements. Golden State Clean Energy, a partner in the project, estimated that once it is completed, California could meet one sixth of its energy needs in 2035 from solar panels in the Central Valley." [**CLEAN TECHNICA**](https://cleantechnica.com/2026/02/26/largest-solar-farm-in-us-coming-to-central-valley-in-california/?ref=calregulatory.com) - **New Bills Target a Range of Energy Issues, with a Focus on Affordability:** "[SB 1161](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB1161&ref=calregulatory.com) would require the California Air Resources Board to prepare an economic impact assessment that assesses whether and to what extent a proposal to adopt, amend, or repeal a regulation will affect low- and middle-income California households and disadvantaged communities." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/new-bills-target-a-range-of-energy?ref=calregulatory.com) - **Not a Moment Too Soon, California Moves to Embrace Nuclear Energy:** "A bipartisan group of lawmakers—led by Democratic Assemblymembers **Lisa Calderon**, **John Harabedian**, and **Alex Lee**, along with Republican Senator **Brian Jones**—introduced [legislation](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202520260AB2647&ref=calregulatory.com) to exempt nuclear reactors approved by the Nuclear Regulatory Commission since 2005 from California’s decades-old moratorium on new nuclear builds. This exemption would include reactors using the AP1000 design, like those powering [Vogtle Units 3 and 4](https://www.georgiapower.com/about/energy/plants/plant-vogtle/units-3-4/vogtle-facts.html?ref=calregulatory.com) in Georgia." [**ORANGE COUNTY REGISTER**](https://www.ocregister.com/2026/02/26/not-a-moment-too-soon-california-moves-to-embrace-nuclear-energy/?ref=calregulatory.com) - **Proposed Changes to Grid Technology Could Spur More Solar in California:** "CPUC [filed a resolution](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?utm%5Fsource=ActiveCampaign&utm%5Fmedium=email&utm%5Fcontent=Press%20Release%3A%20Pending%20Resolution%20from%20California%20Regulators%20Risks%20Millions%20in%20Utility%20Ratepayer%20Investments&utm%5Fcampaign=Press%20Release%20re%3A%20CPUC%20Draft%20ICA%20Resolution%202-26-2026%20%28CA%20reporter%20version%29%20%28Copy%29) for ICA improvements on Feb. 11 that lays out requirements for the investor-owned utilities enrolled in the program. It would require these utilities to report ICA data more frequently and actually follow ICA mandates." [**SOLAR POWER WORLD**](https://www.solarpowerworldonline.com/2026/02/proposed-changes-to-grid-technology-could-spur-more-solar-in-california/?ref=calregulatory.com) - **Trump Administration Reopens Door to Offshore Oil Leasing in California:** "Opposition from Sacramento is fierce and litigation is a near certainty. Still, the signal to markets is that federal energy policy is tilting toward supply. Whether California’s coastline actually sees new rigs is another story entirely." [**OILPRICE.COM**](https://oilprice.com/Latest-Energy-News/World-News/Trump-Administration-Reopens-Door-to-Offshore-Oil-Leasing-in-California.html?ref=calregulatory.com) - **US Military Airlifts Small Reactor as Trump Pushes to Quickly Deploy Nuclear Power:** "The reactor transported to Utah will be able to generate up to 5 megawatts of electricity, enough to power 5,000 homes, said **Isaiah Taylor**, CEO of Valar Atomics, the California startup that produced the reactor. The company hopes to start selling power on a test basis next year and become fully commercial in 2028." [**NPR**](https://www.npr.org/2026/02/21/nx-s1-5721761/us-military-airlifts-small-reactor?utm%5Fsource=substack&utm%5Fmedium=email) - **What California's Planned Power Outages are Costing Schools – Darkness, Disruption, and Debt:** "After the power shutoffs, the Val Verde Unified School District redirected $500,000 from the school facilities budget to buy battery storage units that could help Orange Vista High keep the lights on during future outages. But **Garrick Owen**, the district’s assistant superintendent, said the money would be better spent fixing the grid itself. 'If I had a magic wand, would I spend all the money to harden our schools against power outages, or would I spend it to harden the actual infrastructure of the power lines to not have the power outages?' he said." [**CAL MATTERS**](https://calmatters.org/environment/climate-change/2026/02/school-power-outages-edison-california/?ref=calregulatory.com) - **What Will California Gas Prices Do in 2026?** "When it comes to how much gasoline is going to cost in California this year, there are two not-so-encouraging conclusions we can reach. First, while the price increases may not be as extreme as some have predicted, they will come on top of what are already the highest prices in the continental United States. These high costs for gasoline harm businesses trying to stay competitive, and they wreak havoc on working families that have long commutes." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/what-will-california-gas-prices-do-in-2026/?ref=calregulatory.com) - **Why Farmers in California Are Backing a Giant Solar Farm:** "**Grace Wu**, an environmental scientist at the University of California, Santa Barbara, says 'this is a fantastic place for solar' because the fallowed farmland isn't high-value habitat for wildlife." [**NPR**](https://www.npr.org/2026/02/26/nx-s1-5726411/farmers-california-san-joaquin-valley-solar-farm-westlands-water-district-golden-state-clean-energy?ref=calregulatory.com) ### February 26, 2026 CPUC Voting Meeting Results: President Alice Reynolds' Final Meeting URL: https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-results-president-alice-reynolds-final-meeting/ Last updated: 2026-02-28T03:04:47.000Z Today's CPUC voting meeting marked the final time **Commissioner Alice Reynolds** was present for her role as CPUC president. President Reynolds is moving on to work with the CAISO, and fellow commissioner **John Reynolds** (no relation) [will succeed her as head of the public utilities agency](https://www.calregulatory.com/newsom-installs-john-reynolds-as-cpuc-president-framing-affordability-and-wildfire-spending-oversight-as-top-priorities/). [Gavin Newsom Installs John Reynolds as New CPUC PresidentAlice Reynolds will step down later this month and join the California Independent System Operator’s Governing Board.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-49.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Feb-12-2026--7-.png)](https://www.calregulatory.com/newsom-installs-john-reynolds-as-cpuc-president-framing-affordability-and-wildfire-spending-oversight-as-top-priorities/) In her farewell remarks, President Reynolds commented that, under her stewardship, California has pursued a reliability-first decarbonization strategy. She cited the addition of more than 6,800 MW of new clean capacity in 2025 and the rapid build-out of battery storage to approximately 17,000 MW, presenting both as evidence that the state can maintain grid stability while accelerating the energy transition model, which other jurisdictions are beginning to replicate. Reynolds also affirmed a universal-service doctrine in which utilities are not permitted to segment customers by profitability, underscoring that grid infrastructure and clean energy delivery must extend to all households and businesses regardless of income. At the same time, she acknowledged that rising energy affordability pressures now frame virtually every CPUC decision, with cost containment and bill relief shaping approaches to General Rate Cases, program design, and financial-assistance mechanisms for customers struggling to pay utility bills. The meeting's regular agenda had two major items of note. - **Integrated Resource Planning:** A unanimous [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K854/600854771.pdf?ref=calregulatory.com) orders California load-serving entities to undertake a new tranche of electric resource procurement for reliability during 2029–2032 while also transmitting recommended resource portfolios to the CAISO for the 2026–2027 transmission planning cycle. An [accompanying attachment](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K861/600861712.pdf?ref=calregulatory.com) allocates the procurement obligations across individual LSEs based on their share of forecasted 2026 load, specifying annual capacity targets for 2030–2032 and the portion that must be long-duration storage or clean firm resources. - **Natural Gas Price Spike OII**: A decision in [Investigation 23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) concludes that the extraordinary spike in California natural gas prices during winter 2022–2023 resulted primarily from severe market conditions rather than misconduct by regulated utilities. This decision is a comprehensive exoneration of regulated gas utilities and storage providers for the price shock. The decision carried 4-0 (**Commissioner Matt Baker** was recused due to his past work with Cal Advocates). Additionally, the following items carried on the consent agenda. - **EPIC:** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K411/600411676.pdf?ref=calregulatory.com) adopts a comprehensive set of strategic objectives to guide the Electric Program Investment Charge Program’s 2026–2030 investment cycle, continuing the state’s ratepayer-funded energy innovation efforts while refining governance and accountability. - **V2X Microgrid Pilot**: [Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K860/600860735.pdf?ref=calregulatory.com) approves, with modifications, PG&E’s request to adjust its [Vehicle-to-Everything (V2X) Microgrid Pilot #3](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com), which is designed to test how bidirectional electric vehicles can support community microgrids during outages. - **Mid-Term Reliability**: [Resolution E-5446](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K097/600097056.pdf?ref=calregulatory.com) approves two SDG&E mid-term reliability contracts with Golden Fields Solar VI, LLC for standalone battery storage projects totaling 92 MW of nameplate capacity, consisting of a 44 MW four-hour system and a 48 MW eight-hour system expected to begin deliveries on **June 1, 2027**. - **SGIP**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K055/600055458.pdf?ref=calregulatory.com) denies [Bloom Energy Corp.](https://www.bloomenergy.com/?ref=calregulatory.com)’s 2024 petition for modification of a 2011 decision (D.11-09-015), which governs aspects of the Self-Generation Incentive Program. The CPUC also [delayed](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K872/600872671.PDF?ref=calregulatory.com) consideration of [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com) until March 19\. As currently worded, that draft resolution increases funding for the California Distributed Generation Statistics platform to **$2.6 million** per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion. Greater detail is provided below. **Note:* There is no paywall for this particular CPUC meeting summary, but if you have been finding our reports useful, please consider becoming a* [*paid subscriber*](https://www.calregulatory.com/pricing/) *or* [*inquiring*](https://www.calregulatory.com/contact-us/) *about personalized intelligence for your firm.* --- ### INTEGRATED RESOURCE PLANNING A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K854/600854771.pdf?ref=calregulatory.com) orders California load-serving entities to undertake a new tranche of electric resource procurement for reliability during 2029–2032 while also transmitting recommended resource portfolios to the CAISO for the 2026–2027 transmission planning cycle. "This decision is a true behemoth," said **Commissioner John Reynolds**, who noted the agency received over 800 pages of comments in the lead-up to its adoption. The decision finds that rising load forecasts (driven by data centers, electrification, and reduced behind-the-meter resources) combined with uncertainty around project timelines and expiring federal incentives create a need for additional capacity beyond prior Mid-Term Reliability orders. Accordingly, the decision requires: - An incremental 2,000 MW of Net Qualifying Capacity online by no later than **June 1, 2030**; - An additional 2,000 MW NQC by **June 1, 2031**; and - A further additional 2,000 MW NQC by **June 1, 2032** (6,000 MW cumulative), with at least one-quarter of each LSE's total obligation due by no later than June 1, 2032 coming from long-duration energy storage resources (able to discharge for at least eight hours) and/or clean firm resources with capacity factors of at least 80% that are not use-limited. Eligible resources must be new, zero-emitting or renewable, and generally subject to the same compliance framework as earlier procurement mandates. The decision also provides the CAISO with a reliability- and policy-driven base-case portfolio aligned with California's greenhouse-gas trajectory (targeting about 25 million metric tons of electric-sector emissions by 2035) along with a sensitivity portfolio testing a worst-case slowdown in all wind development, including onshore and offshore. These portfolios will inform transmission expansion needs under the Transmission Planning Process, where approved projects can receive cost recovery through transmission charges. The CPUC's reliability modeling indicates that even with existing contracts and prior procurement, additional capacity is needed to meet the planning standard of one expected loss-of-load day in 10 years, particularly if long-lead-time resources are delayed. An [accompanying attachment](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K861/600861712.pdf?ref=calregulatory.com) allocates the procurement obligations across individual LSEs based on their share of forecasted 2026 load, specifying annual capacity targets for 2030–2032 and the portion that must be long-duration storage or clean firm resources. For example, the largest bundled utilities (SCE at 2,088 MW and PG&E at 1,077 MW) receive the biggest obligations, while numerous community choice aggregators and electric service providers receive smaller, proportional requirements. In total, the allocation sums to 5,998 MW of new capacity statewide by 2032, including about 1,505 MW that must come from long-duration storage or clean firm technologies. __R.25-06-019 — Attachment A: Procurement Obligations by Load Serving Entity__ | Load Serving Entity | Type | 2026 Load(GWh) | Share of2026 Load | 2030(MW NQC) | 2031(MW NQC) | 2032(MW NQC) | Total(MW NQC) | LDES /Clean Firm | | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---- | -------------- | ----------------- | ------------ | ------------ | ------------ | ------------- | ---------------- | | PG&E Service Territory | | | | | | | | | | Pacific Gas & Electric (bundled) | IOU | 5,144 | 18.0% | 359 | 359 | 359 | 1,077 | 269 | | PG&E Direct Access (aggregated)\* | ESP | 11,393 | 4.1% | 82 | 82 | 82 | 246 | 62 | | Clean Power San Francisco | CCA | 3,394 | 1.8% | 36 | 36 | 36 | 108 | 27 | | East Bay Community Energy | CCA | 9,432 | 4.6% | 93 | 93 | 93 | 279 | 70 | | King City Community Power\*\* | CCA | 36 | 0.0% | 0 | 0 | 1 | 1 | 0 | | Marin Clean Energy | CCA | 5,966 | 3.0% | 60 | 60 | 60 | 180 | 45 | | Central Coast Community Energy | CCA | 5,791 | 2.8% | 57 | 57 | 57 | 171 | 43 | | Peninsula Clean Energy Authority | CCA | 3,831 | 1.9% | 38 | 38 | 38 | 114 | 29 | | Pioneer Community Energy | CCA | 1,793 | 0.9% | 18 | 18 | 18 | 54 | 14 | | Redwood Coast Energy Authority | CCA | 634 | 0.3% | 5 | 5 | 5 | 15 | 4 | | San Jose Clean Energy | CCA | 4,543 | 2.1% | 43 | 43 | 43 | 129 | 32 | | Silicon Valley Clean Energy | CCA | 4,132 | 2.2% | 45 | 45 | 45 | 135 | 34 | | Sonoma Clean Power Authority | CCA | 2,236 | 1.1% | 22 | 22 | 22 | 66 | 17 | | Valley Clean Energy Alliance | CCA | 724 | 0.4% | 7 | 7 | 7 | 21 | 5 | | SCE Service Territory | | | | | | | | | | Southern California Edison (bundled) | IOU | 51,858 | 34.8% | 696 | 696 | 696 | 2,088 | 522 | | SCE Direct Access (aggregated)\* | ESP | 12,003 | 4.3% | 86 | 86 | 86 | 258 | 65 | | Apple Valley Choice Energy | CCA | 250 | 0.1% | 2 | 2 | 2 | 6 | 2 | | City of Pomona | CCA | 431 | 0.2% | 4 | 4 | 4 | 12 | 3 | | Clean Power Alliance of Southern California | CCA | 11,166 | 5.9% | 118 | 118 | 118 | 354 | 89 | | Desert Community Energy | CCA | 369 | 0.2% | 4 | 4 | 4 | 12 | 3 | | Lancaster Clean Energy | CCA | 618 | 0.3% | 6 | 6 | 6 | 18 | 5 | | Orange County Power Authority | CCA | 2,275 | 1.3% | 25 | 25 | 25 | 75 | 19 | | Energy for Palmdale's Independent Choice | CCA | 497 | 0.2% | 5 | 5 | 5 | 15 | 4 | | Pico Rivera Innovative Municipal Energy | CCA | 218 | 0.1% | 2 | 2 | 2 | 6 | 2 | | Rancho Mirage Energy Authority | CCA | 286 | 0.1% | 3 | 3 | 3 | 9 | 2 | | San Jacinto Power | CCA | 172 | 0.1% | 2 | 2 | 2 | 6 | 2 | | Santa Barbara Clean Energy | CCA | 347 | 0.2% | 3 | 3 | 3 | 9 | 2 | | SDG&E Service Territory | | | | | | | | | | San Diego Gas & Electric (bundled) | IOU | 2,658 | 2.2% | 43 | 43 | 43 | 129 | 32 | | SDG&E Direct Access (aggregated)\* | ESP | 3,942 | 1.4% | 29 | 29 | 29 | 87 | 22 | | Clean Energy Alliance | CCA | 2,492 | 1.2% | 25 | 25 | 25 | 75 | 19 | | San Diego Community Power | CCA | 8,340 | 4.1% | 81 | 81 | 81 | 243 | 61 | | Total | | 176,972 | 100% | 1,999 | 1,999 | 2,000 | 5,998 | 1,505 | | \*Individual ESP obligations remain confidential; aggregated figures shown.\*\*King City's per-year obligation rounds to 0 MW; assigned 1 MW total in 2032, which may be met in any compliance year through 2032.LDES / Clean Firm = Long-duration energy storage (≥8 hr discharge) and/or clean firm resources (≥80% capacity factor, not use-limited), due by June 1, 2032.Source: R.25-06-019, Proposed Decision (Rev. 1), Attachment A. | | | | | | | | | Commissioner John Reynolds added: > We must always be sensitive to the ways our models do and do not reflect reality and adapt accordingly. Firm, weather-independent power and storage that can deliver eight or more hours of capacity are exactly the kinds of resources that keep the lights on during a heat wave or extended cloudy weather. Regarding the transmission side of the decision, Reynolds said that least-cost transmission planning only works if "we know where the power is coming from," and this decision gives the grid operator the necessary info in that regard. Regarding ratepayers, Reynolds said: > Planning ahead is always cheaper than scrambling for emergency resources when the grid is stressed. This procurement ordered now is how we avoid that scramble. Customers deserve a reliable, clean grid, and they deserve to get it at the lowest feasible cost, and today's decision works towards that exact goal. **INSTANT ANALYSIS**: This decision is a forward reliability order disguised as routine IRP housekeeping. By mandating 6,000 MW of new clean capacity across 2030–2032 (with a hard carve-out for long-duration storage and clean firm), the CPUC is pre-positioning the system for potential post-Diablo Canyon conditions, data-center load growth, and the likely shortfall of long-lead resources already slipping to the right. - The allocation table confirms the burden will fall primarily on the big IOUs and the largest Community Choice Aggregators, meaning procurement activity (and developer leverage) will concentrate in those counterparties over the next 24–36 months. - Equally important, transmitting portfolios to the CAISO for the 2026–2027 TPP ties procurement directly to transmission expansion, increasing the probability that new lines (and associated cost recovery) follow these resource assumptions. That linkage raises downstream rate exposure risk, because transmission approvals triggered by these portfolios will flow through the TAC regardless of whether load growth materializes as forecast. The decision therefore functions as both a capacity mandate and a transmission cost pipeline. In short, the decision is an early reliability shock absorber for 2029–2032 that shifts procurement risk onto LSEs now to avoid emergency actions later. Stakeholders who should care most are IOU procurement teams, large CCAs, storage developers, transmission planners, and large customers exposed to future [Transmission Access Charge](https://clean-coalition.org/policy/transmission-access-charges/?ref=calregulatory.com) and Resource Adequacy cost escalation. The practical effect is to pull forward contracting timelines and intensify competition for deliverable clean firm and long-duration storage projects statewide. --- ### NATURAL GAS PRICE INVESTIGATION A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K860/600860739.pdf?ref=calregulatory.com) in [Investigation 23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) concludes that the extraordinary spike in California natural gas prices during winter 2022–2023 resulted primarily from severe market conditions rather than misconduct by regulated utilities. "The '22-'23 gas price spike was a serious and painful event for California ratepayers," said **Commissioner John Reynolds**, "and a stark reminder of how our energy system remains dependent on commodity prices." The Commission finds that prolonged below-normal temperatures and high precipitation levels drove unusually high demand at the same time that supply was constrained by: - Interstate pipeline outages and maintenance; - Reduced gas flows from the Permian Basin, Canada, and the Rocky Mountain region; and - Unusually low storage inventories across the western United States. Price volatility was further amplified by the convergence of [Winter Storm Elliot](https://en.wikipedia.org/wiki/December%5F2022%5FNorth%5FAmerican%5Fblizzard?ref=calregulatory.com) with the monthly "bidweek" purchasing window, when the January 2023 index price locked in at levels reflecting the December spot surge. After reviewing extensive evidence, the decision determines that California gas utilities, their procurement departments, and independent storage providers did not intentionally or improperly cause the spike, and that customer bill increases largely reflected prevailing commodity market prices. FERC separately referred one unnamed market participant for investigation but completed its analysis in November 2024 without additional referrals; the identity of the investigated entity remains undisclosed. The decision formally defines a "gas price spike event" as a 150% increase in the monthly core procurement price relative to the 10-year average for that month during the winter season (November through March), creating the trigger for the following mitigation measures: - A temporary cap on utilities' Core Procurement Charge during defined spike events; - Amortization of under-collections within nine months; - Enhanced customer notifications within one business day of identifying a spike event; - Pre-winter early warning notifications no later than October 15 if forward prices indicate a spike; - Greater transparency around procurement incentives, including a shift from advice letter to formal application process for shareholder awards under PG&E's [Core Procurement Incentive Mechanism and SoCalGas's Gas Cost Incentive Mechanism](https://www.calregulatory.com/cpuc-proposes-administrative-changes-to-utility-gas-procurement-incentive-mechanisms/); - Increased storage reporting, including mandatory public monthly reporting by ISPs and base volume disclosure on PG&E's [Pipe Ranger](https://www.pge.com/pipeline/en.html?ref=calregulatory.com) and SoCalGas's [Envoy ](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome)platforms; and - Planning requirements to incorporate similar constraints into future procurement and hedging strategies. The decision considers and declines to adopt several additional measures, including a disconnection moratorium, a ban on credit reporting of delinquencies, a residential fixed charge, fuel cost sharing, climate credit changes, and LNG export mitigation tools. --- In comments from the dais, Commissioner John Reynolds pointed out that SoCalGas customers absorbed the worst of the price spike because Southern California's gas system was running on a single remaining artery (the El Paso pipeline had been out since the August 2021 rupture) while Aliso Canyon was throttled to reduced capacity. Two critical infrastructure buffers degraded simultaneously. PG&E's territory, by contrast, had geographic diversification and independent storage access that kept its market more liquid. Reynolds also noted a CAISO report, which showed **$3.9 billion** in additional wholesale electricity costs in December 2022 and January 2023 alone, driven by the same gas price spike. Gas generators are noncore customers outside CPUC procurement jurisdiction, but these costs flow straight through to ratepayers via the generation charge. Meaning the gas spike was also an electricity spike. On the decision itself, Reynolds backed the new consumer protection package: a temporary winter-only cap on the core procurement charge, nine-month cost amortization, and mandatory customer notification within one business day of a spike identification. He specifically rebutted the argument that rate caps erode price signals, noting that core gas customers currently have zero real-time rate visibility (bills arrive after the fact). The mandatory notification framework, he argued, actually creates a more functional price signal than the status quo silence. Last, Reynolds noted that, although previous storage limits on Aliso Canyon were not arbitrary, they were a response to the facility's 2015 leak, "a better stocked Aliso Canyon – operated safely – is a meaningful buffer against the kind of dual market shock that we saw in the winter of '22 and '23." Reynolds also added that his remarks should not be construed to mean that Aliso Canyon should operate indefinitely or without scrutiny. "The right answer going forward," he said, "will require weighing affordability, reliability, safety and California's long-term decarbonization goals together." **INSTANT ANALYSIS**: This decision is a comprehensive exoneration of regulated gas utilities and storage providers for the Winter 2022–2023 price shock. The decision firmly attributes the spike to upstream market fundamentals (weather-driven demand, pipeline outages, reduced imports, and depleted storage) rather than procurement misconduct or market manipulation. The Commission's policy focus therefore shifts from enforcement to resilience: it establishes a formal "gas price spike event" trigger, authorizes temporary caps on the Core Procurement Charge with amortization, and mandates advance customer notifications and transparency reforms. For stakeholders, the real significance is prospective: the decision creates a regulatory trigger framework for future volatility, strengthens oversight of procurement incentive mechanisms by requiring formal applications rather than advice letters for shareholder awards, and elevates storage transparency (including public ISP inventory reporting). All of these actions will shape winter reliability planning, hedging strategies, and rate design debates going forward. Several issues are deferred to other proceedings. --- ### ELECTRIC PROGRAM INVESTMENT CHARGE (EPIC) A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K411/600411676.pdf?ref=calregulatory.com) adopts a comprehensive set of strategic objectives to guide the Electric Program Investment Charge Program’s 2026–2030 investment cycle, continuing the state’s ratepayer-funded energy innovation efforts while refining governance and accountability. - The decision authorizes the investor-owned utilities to remain EPIC administrators, permits collection of funds for the next cycle, and updates program rules on intellectual property, evaluation, and oversight. - The decision establishes 13 measurable objectives under five Strategic Goals (e.g., Transportation Electrification, DER Integration, Building Decarbonization), clarifying that future EPIC projects must advance at least one objective but administrators need not address all 13 in their investment plans. - The decision authorizes a new program evaluation in 2028 to address data gaps that may inform Commission consideration of whether to continue EPIC past its current 2030 sunset, while extending the deadline for EPIC 5 investment plan applications to **August 26**, to accommodate the new requirements. IOU community engagement plan advice letters are due by **June 26**. **INSTANT ANALYSIS:** This decision translates previously adopted Strategic Goals into 13 binding objectives that will govern EPIC’s 2026–2030 investment cycle under continued utility administration, narrowing how ratepayer-funded RD&D must align with electrification, DER integration, building decarbonization, gas transition, and climate adaptation priorities. The consequential move is the scheduled 2028 evaluation, positioned to inform whether EPIC continues beyond its 2030 sunset. Program survival is now tied more explicitly to demonstrable ratepayer value and measurable outcomes, while the August 26 application deadline (preceded by June 26 community engagement filings) forces administrators to sequence stakeholder input before proposing portfolios. --- ### VEHICLE-to-EVERYTHING PILOT [Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K860/600860735.pdf?ref=calregulatory.com) approves, with modifications, PG&E’s request to adjust its [Vehicle-to-Everything (V2X) Microgrid Pilot #3](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com), which is designed to test how bidirectional electric vehicles can support community microgrids during outages. The resolution grants PG&E additional time to complete Phase I demonstration work at the [Redwood Coast Airport Microgrid](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com), setting a final completion date of **June 30**, so the utility can repair damaged chargers, resume testing, and collect operational data. - The Commission finds the extension reasonable given delays outside PG&E's control, including federal funding timing, equipment failures, vendor issues, and technical challenges encountered during early testing of frequency-based controls that allow vehicles to charge and discharge in response to grid conditions. - PG&E must file a Tier 2 Advice Letter within 30 days providing both an updated Phase I completion schedule with revised milestones and a narrative explaining how it will meet the pilot's original success metric of demonstrating five to 10 bidirectional vehicles, as only two are currently participating. For Phase II, the resolution approves PG&E’s shift from a customer enrollment and incentive program to a “Hybrid Support Model.” Under this approach, PG&E will stop enrolling new participants, return unspent customer incentive funds to ratepayers by reducing the pilot’s authorized budget, and instead provide technical consulting to community microgrid projects using internal resources. Regulators conclude that this change reflects market realities, including the limited availability of operational community microgrids, slow development timelines, equipment constraints, and the early stage of bidirectional charging technology. Neither the [Schatz Energy Research Center](https://schatzcenter.org/?ref=calregulatory.com) nor the [Vehicle Grid Integration Council](https://www.vgicouncil.org/?ref=calregulatory.com) opposed the modifications. The Council recommended redirecting freed resources to the Residential and Commercial V2X pilots. The modified pilot is intended to apply lessons learned from Phase I to emerging microgrid projects while limiting costs and protecting ratepayers, reducing the pilot's budget from $1.5 million to **$750,000** and lowering the Vehicle Grid Integration subaccount cap within the Transportation Electrification Balancing Account from $11,700,000 to **$10,950,000**. **INSTANT ANALYSIS**: This resolution basically downgrades PG&E’s V2X microgrid pilot from a deployment program to a contained learning exercise, reflecting continued immaturity in bidirectional EV and community microgrid readiness. By extending Phase I but halting enrollment, cutting incentives, and demanding justification for missed success metrics, regulators are prioritizing data extraction and cost control over expansion. The Hybrid Support Model preserves PG&E’s technical role in future microgrid development while limiting ratepayer exposure, suggesting a shift toward slow capacity-building rather than near-term commercialization of V2X microgrid integration. VGIC's recommendation to redirect freed pilot resources toward the Residential and Commercial V2X pilots signals where future funding pressure may concentrate. --- ### MID-TERM RELIABILITY [Resolution E-5446](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K097/600097056.pdf?ref=calregulatory.com) approves two SDG&E mid-term reliability contracts with Golden Fields Solar VI, LLC ([Clearway](https://www.clearwayenergygroup.com/?ref=calregulatory.com)) for standalone battery storage projects totaling 92 MW of nameplate capacity, consisting of a 44 MW four-hour system and a 48 MW eight-hour system expected to begin deliveries on **June 1, 2027**. Both are 15-year power purchase tolling agreements. The contracts, awarded through SDG&E's Tranche 3 solicitation under the state's Integrated Resource Planning procurement mandates, are intended to help the utility meet its 2027 reliability requirements ordered in [D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com). SDG&E's broader mid-term reliability procurement obligation also includes 103 MW of zero-emitting capacity to replace generation retiring at Diablo Canyon, though that requirement applied to resources online by 2025. Notably, shortlisted projects were unable to hold original offer prices due to supply chain cost volatility driven by increased import tariffs, leading SDG&E to negotiate price adjustments. SDG&E asserts the final negotiated prices still resulted in high positive net market values and remained the least-cost/best-fit solutions. The resolution finds the solicitation process, least-cost/best-fit evaluation, and negotiated agreements reasonable, and approves recovery of contract costs from customers through the Portfolio Allocation Balancing Account: - The 8-hour Power Purchase Agreement via the 2021 [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) vintage; and - The 4-hour PPA via the 2023 vintage (applicable to bundled and departing load customers). **INSTANT ANALYSIS:** Three things matter here. - First, SDG&E renegotiated prices after shortlisting because bidders couldn't hold offers through import tariff-driven supply chain volatility (and the draft resolution blessed it without protest). This is now a template for every utility running storage procurement in 2026-2027\. - Second, both contracts go to Clearway (Golden Fields Solar VI), consolidating developer concentration inside SDG&E's portfolio (two standalone battery projects, same developer, same commercial operation date, 15-year tolling agreements). - Third, the 48 MW 8-hour system overshoots SDG&E's 41.5 MW long-duration storage requirement a year early, locking in 8-hour lithium-ion at 2024 bid prices before longer-duration mandates potentially expand under the next IRP cycle. While this matter was unprotested and routine on the surface, the renegotiation precedent, developer concentration, and early long-duration positioning suggest where the next procurement round is heading. --- ### SELF-GENERATION INCENTIVE PROGRAM A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M600/K055/600055458.pdf?ref=calregulatory.com) denies [Bloom Energy Corp.](https://www.bloomenergy.com/?ref=calregulatory.com)’s 2024 petition for modification of a 2011 decision ([D.11-09-015](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/143459.PDF?ref=calregulatory.com)), which governs aspects of the Self-Generation Incentive Program. Bloom sought to increase the program’s annual export cap from 25% to 50% of a project’s net generation, arguing that advancements in its fuel cell technology and evolving SGIP policies now justify greater exports to the grid. The CPUC finds the petition procedurally deficient under its Rules of Practice and Procedure, which requires petitions for modification to be filed within one year of a decision’s effective date unless the petitioner explains why it could not have done so earlier. Because Bloom filed its petition nearly 13 years after the original 2011 decision and relied primarily on technological evolution and policy changes as justification, the CPUC concludes that the late filing was not adequately explained. Although Bloom’s position was [supported](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493283.PDF?ref=calregulatory.com) by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) and jointly by [SoCalGas and the Center for Sustainable Energy](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493284.PDF?ref=calregulatory.com), Cal Advocates [opposed the petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K867/542867049.PDF?ref=calregulatory.com), arguing that SGIP’s purpose is to promote self-generation, not expanded grid exports. **INSTANT ANALYSIS:** This decision keeps export-dependent distributed generation models constrained under current SGIP rules and warns developers that technology evolution alone will not justify reopening settled program limits. ### WEDNESDAY AGGREGATE: Stanpac Transaction Scrutiny; Wildfire Cost Challenge; SDG&E ERRA Dispute URL: https://www.calregulatory.com/wednesday-aggregate-13/ Last updated: 2026-02-25T22:47:02.000Z Today's update focuses on: - **Natural Gas Transmission Assets:** A joint prehearing conference statement for PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com) to acquire Stanpac’s gas transmission pipeline assets and related interests. Cal Advocates is attempting to reframe the proposed transaction as needing a full reasonableness review under the Public Utilities Code, rather than a narrower approval focused on whether the asset transfer and agreements meet certain statutory requirements. - **Wildfire Mitigation Costs:** A Protect Our Communities Foundation application for rehearing of a CPUC decision from January ([D.26-01-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K291/596291467.PDF?ref=calregulatory.com)), which addressed SDG&E's request to recover wildfire mitigation memorandum account costs. Protect Our Communities Foundation argues the CPUC committed multiple legal and procedural errors that unlawfully allowed recovery of unjustified expenses. - **SDG&E ERRA Compliance:** A [joint meet-and-confer report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960170.PDF?ref=calregulatory.com) in SDG&E’s 2024 Energy Resource Recovery Account compliance application ([A.25-06-002](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M568/K462/568462460.PDF?ref=calregulatory.com)), which shows this case moving toward a technical dispute over SDG&E’s Resource Adequacy accounting and cost allocation practices rather than broad procurement prudence challenges. --- ### NATURAL GAS TRANSMISSION PG&E, Standard Pacific Gas Line Incorporated (Stanpac), Chevron Pipe Line Company, and Cal Advocates filed a [joint prehearing conference statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083296.PDF?ref=calregulatory.com) outlining the issues and procedural posture in PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com) to acquire Stanpac’s gas transmission pipeline assets and related interests. The joint applicants seek CPUC approval for the asset sale, associated transportation and inter-utility service agreements, a future stock purchase arrangement involving Chevron’s minority interest, ratemaking treatment, and confirmation that the transaction is exempt from CEQA review. (PG&E already owns 6/7ths of Stanpac; the transaction consolidates the remaining 1/7th interest currently held by Chevron.) - While Chevron supports PG&E’s proposed scope, Cal Advocates argues the proceeding must also examine whether the transaction’s valuations, payment structure, long-term arrangements, and ratemaking impacts are just and reasonable for ratepayers under [Public Utilities Code Section 451](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-451-1/?ref=calregulatory.com). - Cal Advocates airs concerns about (i) PG&E paying the full stated value despite already owning most of Stanpac and (ii) its plans to acquire Chevron’s remaining shares for a nominal amount after 20 years. The parties also differ on whether additional issues (e.g., potential future dissolution of Stanpac or affiliate transaction compliance) belong in the proceeding's scope. **INSTANT ANALYSIS:** Cal Advocates is attempting to reframe the proposed transaction as a full reasonableness review under Section 451\. Its focus is on (i) PG&E paying the full **$150 million** valuation despite already owning most of Stanpac and (ii) the plan to acquire Chevron’s remaining shares for **$1** after 20 years, a structure that may draw skepticism on ratepayer impacts. The underlying stakes involve control of aging natural gas infrastructure tied to refinery service obligations and who bears the costs. If the Commission expands the scope, the decision may set a precedent for deeper valuation review and scrutiny of long-horizon utility transactions where ratepayers fund assets serving specific industrial counterparties. --- ### WILDFIRE MITIGATION COSTS The Protect Our Communities Foundation filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083307.PDF?ref=calregulatory.com) of a CPUC decision from January ([D.26-01-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K291/596291467.PDF?ref=calregulatory.com)), which addressed SDG&E's request to recover wildfire mitigation memorandum account costs. (*See CRI's coverage* [*here*](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/)*.*) [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-48.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--11--1.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/) Protect Our Communities Foundation argues the CPUC committed multiple legal and procedural errors that unlawfully allowed recovery of unjustified expenses. Protect Our Communities Foundation contends the CPUC: - Exceeded the scope of the proceeding by considering costs and issues (such as post-2022 expenditures and securitization) not identified in the scoping memo; - Applied the wrong legal standard by using a “prudent manager” test instead of the statutory “just and reasonable” requirement; - Violated due process by making last-minute changes without allowing other parties to respond; - Improperly approved or deferred review of numerous wildfire mitigation program costs (including drone programs, undergrounding, inspections, and other capital projects) despite finding SDG&E failed to demonstrate their reasonableness or cost-effectiveness; and - Improperly disregarded an unrefuted independent audit finding (the OEIS Crowe Audit) that SDG&E could not document whether it actually spent **$240 millio**n in wildfire mitigation spending the Commission authorized in 2019\. PCF contends the Commission justified ignoring the audit at the last minute, without allowing any party other than SDG&E to comment on that justification. Separately, Protect Our Communities Foundation challenges the CPUC's admission of supplemental SDG&E evidence submitted eight months after the intervenor testimony deadline and four months after briefing closed. It requests rehearing to correct these alleged errors, disallow unsupported costs, and ensure ratepayers are not charged for expenditures the utility did not adequately justify. **INSTANT ANALYSIS:** This request reopens legal risk around SDG&E’s approved wildfire mitigation cost recovery by challenging the CPUC’s procedure, scope decisions, and use of a deferential review standard. If entertained, it could constrain how freely the CPUC approves large mitigation spending with incomplete documentation. Near term, refund risk is low, but precedent risk is real: utilities may face tougher scrutiny on future wildfire portfolios, while intervenors gain leverage to challenge track-based GRC decisions and late-stage revisions. The standard-of-review challenge (prudent manager versus the statutory "just and reasonable" requirement) is the most consequential legal argument here. If courts ultimately take it up, the implications would extend well beyond this docket to how the CPUC evaluates wildfire mitigation cost recovery across all California IOUs. --- ### SDG&E ERRA COMPLIANCE SDG&E, Cal Advocates, San Diego Community Power, and the Clean Energy Alliance filed a [joint meet-and-confer report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960170.PDF?ref=calregulatory.com) in SDG&E’s 2024 Energy Resource Recovery Account compliance application ([A.25-06-002](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M568/K462/568462460.PDF?ref=calregulatory.com)). The report summarizes areas of agreement and dispute following rebuttal testimony. The parties report that many compliance issues are uncontested, including SDG&E’s contract administration, least-cost dispatch, Demand Response management, greenhouse gas compliance activities, and the accuracy of numerous balancing and memorandum accounts. Remaining disputes center on three areas: - Cal Advocates' proposal to disallow **$28,310** in ERRA costs tied to a computer hard drive failure within SDG&E's Continuous Emissions Monitoring System Data Acquisition and Handling System at utility-owned generation; - SDG&E’s handling and accounting of excess Resource Adequacy capacity during 2024 procurement (including whether buffer capacity should have been classified and valued differently); and - An alleged error in assigning [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) vintages to new customer premises that may have affected cost allocation and billing accuracy. SDG&E has indicated its SAP billing system upgrade to correct the vintaging error is targeted for Q1 2026. The report indicates the parties have narrowed contested issues and are exploring settlement, but the Clean Energy Alliance and San Diego Community Power may seek evidentiary hearings (particularly on the RA accounting issue) pending discovery responses. **INSTANT ANALYSIS:** This filing shows the ERRA compliance case moving toward a technical dispute over SDG&E’s Resource Adequacy accounting and cost allocation practices rather than broad procurement prudence challenges. The only issues with real financial or precedent risk are: whether SDG&E improperly withheld and zero-valued excess RA capacity instead of treating it as retained compliance capacity and whether PCIA vintaging errors affected cost responsibility for new customers. Both go directly to how procurement costs are allocated between bundled customers and Community Choice Aggregators. The fact that most operational and dispatch issues are uncontested indicates low likelihood of major disallowances, but the RA buffer treatment could influence future utility incentives around over-procurement and market participation. If hearings proceed, they will likely focus on whether SDG&E’s RA portfolio management shifted costs or market value away from CCA customers, making this a cost-allocation and transparency fight rather than a reliability or procurement failure case. ### March 1, 2026 SDG&E Natural Gas Rate Increase URL: https://www.calregulatory.com/march-1-2026-sdg-e-natural-gas-rate-increase/ Last updated: 2026-02-25T20:33:35.000Z SDG&E filed Advice Letter 3498-G (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) requesting approval to update its natural gas transportation rates effective **March 1**, primarily to reflect changes in SoCalGas's revenue requirement and to incorporate authorized employee compensation costs. The filing implements interim recovery of approximately **$35.5 million** in SoCalGas Distribution Integrity Management Program Balancing Account (DIMPBA) costs from 2019–2023, as authorized by a February 2026 decision ([D.26-02-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K009/598009866.PDF?ref=calregulatory.com)), along with approved non-officer compensation operating costs for 2024–2026 pursuant to [Resolution E-5405](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K488/595488983.PDF?ref=calregulatory.com). (*Related coverage of SoCalGas's parallel advice-letter filing is available* [*here*](https://www.calregulatory.com/march-1-2026-socalgas-rate-increase/)*.*) [March 1, 2026 SoCalGas Rate IncreaseSoCalGas filed Advice Letter 6605-G to implement interim increases to its natural gas transportation rates effective March 1.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-47.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Feb-12-2026--4-.png)](https://www.calregulatory.com/march-1-2026-socalgas-rate-increase/) Because SDG&E is a wholesale customer of SoCalGas, a portion of those costs (about **$428,000**) flows through to SDG&E’s rates under system-wide cost allocation rules. The rate changes produce minimal customer bill effects, increasing the typical bundled residential bill by only a few cents per month (about **0.05%**), while raising SDG&E’s overall gas revenue requirement by roughly **$783,000** across customer classes. The adjustments also modify related rate components for electric generation, natural-gas vehicle service, and transmission-level service to maintain alignment with SoCalGas transportation rates. Protests are due **March 16**. Illustrative tables are provided below. | Customer Class | Vol. (mtherms) | Jan-26 Rate ($/therm) | Mar-26 Rate ($/therm) | Rate Δ ($/therm) | Rev Δ ($000s) | Δ% | | ------------------------------- | -------------- | --------------------- | --------------------- | ---------------- | ------------- | --------- | | **CORE** | | | | | | | | Residential | 270,604 | $2.09918 | $2.10057 | +$0.00139 | +$376 | +0.1% | | Commercial & Industrial | 178,913 | $0.82119 | $0.82194 | +$0.00075 | +$135 | +0.1% | | NGV (Post Sempra-Wide) | 23,179 | $0.32830 | $0.33046 | +$0.00216 | +$50 | +0.7% | | **Total Core** | **472,696** | **$1.52863** | **$1.52982** | **+$0.00119** | **+$561** | **+0.1%** | | **NONCORE C&I** | | | | | | | | Distribution Level | 35,337 | $0.38615 | $0.38675 | +$0.00060 | +$21 | +0.2% | | Transmission Level | 13,965 | $0.07867 | $0.07909 | +$0.00042 | +$6 | +0.5% | | **Total Noncore C&I** | **49,302** | **$0.29906** | **$0.29960** | **+$0.00054** | **+$27** | **+0.2%** | | **NONCORE ELECTRIC GENERATION** | | | | | | | | Distribution (Post Sempra-Wide) | 71,656 | $0.27731 | $0.27871 | +$0.00140 | +$100 | +0.5% | | Transmission Level | 225,945 | $0.07616 | $0.07658 | +$0.00042 | +$95 | +0.6% | | **Total Electric Generation** | **297,600** | **$0.12459** | **$0.12525** | **+$0.00066** | **+$195** | **+0.5%** | | **TOTAL NONCORE** | **346,902** | **$0.14939** | **$0.15002** | **+$0.00063** | **+$222** | **+0.4%** | | **SYSTEM TOTAL** | **819,598** | **$0.94485** | **$0.94581** | **+$0.00096** | **+$783** | **+0.1%** | ### INSTANT ANALYSIS This is a revealing pass-through adjustment that illustrates how upstream SoCalGas cost-recovery decisions propagate across the Sempra gas system, including SDG&E transportation rates. The CPUC’s authorization of interim DIMPBA recovery (pending a final reasonableness determination) places ratepayers on the hook now while preserving the possibility of refunds later, a familiar pattern when safety-related integrity costs are at issue. The negligible residential bill impact masks the larger regulatory signal: pipeline integrity spending and workforce cost pressures continue to accumulate in balancing accounts and are steadily migrating into base rates through interim mechanisms. For market participants and large transportation customers, the more meaningful takeaway is the system-wide alignment of transportation rates effective March 1, 2026, which confirms that SoCalGas revenue requirement changes remain the gravitational center for downstream rate design across Southern California. The advice letter also shows the Commission’s continued tolerance for incremental recovery of O&M labor costs outside a full rate case cycle, reinforcing a gradual normalization of piecemeal rate adjustments tied to safety, integrity, and workforce categories rather than comprehensive proceedings. ### WHO SHOULD CARE? - **Large gas users and transportation customers**. Core commercial, industrial, electric generation, and noncore transportation customers will see small rate changes effective March 1, tied to SoCalGas system costs flowing through SDG&E tariffs. But even minor per-therm shifts matter at scale for facilities burning millions of therms annually. - **Pipeline operators, storage stakeholders, and safety-cost watchers.** The interim recovery of pipeline integrity spending suggests that safety and compliance costs will continue migrating into rates ahead of final reasonableness findings. Anyone tracking the affordability implications of integrity programs should view this as another incremental step in that trend. - **Energy traders, procurement teams, and load-serving entities.** System-wide transportation alignment confirms that SoCalGas revenue requirement changes remain the anchor for Southern California gas economics. Entities exposed to basis risk, fuel costs, or dispatch economics should incorporate the updated transportation components into forward cost assumptions. - **Ratepayer advocates and affordability groups (lower priority here).** Residential impacts are negligible (only a few cents per month) so this is not a headline consumer issue, but it contributes to cumulative upward pressure from successive interim recoveries. ### March 1, 2026 SoCalGas Rate Increase URL: https://www.calregulatory.com/march-1-2026-socalgas-rate-increase/ Last updated: 2026-02-25T19:20:47.000Z SoCalGas filed Advice Letter 6605-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) to implement interim increases to its natural gas transportation rates effective **March 1**. _This post is for paying subscribers only._ ### March 1, 2026 PG&E Noncore Natural Gas Rate Increase URL: https://www.calregulatory.com/march-1-2026-pg-e-noncore-natural-gas-rate-increase/ Last updated: 2026-02-25T17:22:18.000Z PG&E filed [Advice Letter 5184-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5184-G.pdf?ref=calregulatory.com) seeking CPUC approval to implement updated noncore gas transportation tariff rates effective **March 1**, reflecting revenue requirement changes previously authorized by the CPUC. The filing consolidates adjustments tied to recovery of costs from the utility's 2023 Wildfire Mitigation and Catastrophic Event application (in which PG&E sought recovery of costs incurred primarily in 2022). That authorization occurred earlier this month in [D.26-02-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K674/597674515.PDF?ref=calregulatory.com). (*See CRI's coverage* [*here*](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/)). [CPUC Adopts New Flexible Service Connection RulesTopics covered: energization, wildfire cost recovery, SoCalGas Distribution Integrity Management Costs, crude oil transportation.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-45.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-03-2026.png)](https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/) The authorized amount included **$14.6 million** in gas distribution and **$5.4 million** in gas transmission revenue requirements (including interest and RF&U) Under the proposal, noncore transportation rates would increase by about **$3.6 million** annually, while concurrent changes to core transportation rates would add roughly **$16.4 million**, producing an overall gas revenue increase of about **$20 million** on an annualized basis. Protests are due **March 16**. Illustrative rates are noted below. | Customer Class | January 2026 | March 2026 | Percentage Change | | | | | | | | ---------------------------------------------- | --------------------- | ------------ | ----------------- | -------------- | ------ | ------ | -------------- | ------ | ----- | | | Transportation (1)(5) | G-PPPS \[2\] | Total | Transportation | G-PPPS | Total | Transportation | G-PPPS | Total | | RETAIL CORE | | | | | | | | | | | Residential Non-CARE (4) | $2.155 | $.121 | $2.276 | $2.163 | $.121 | $2.284 | 0.4% | 0.0% | 0.3% | | Small Commercial Non-CARE (4) | $1.374 | $.106 | $1.480 | $1.378 | $.106 | $1.484 | 0.3% | 0.0% | 0.3% | | Large Commercial | $.810 | $.085 | $.894 | $.812 | $.085 | $.896 | 0.2% | 0.0% | 0.2% | | NGV1 - (uncompressed service) | $.861 | $.048 | $.909 | $.863 | $.048 | $.911 | 0.3% | 0.0% | 0.2% | | NGV2 - (compressed service) | $2.534 | $.048 | $2.583 | $2.544 | $.048 | $2.592 | 0.4% | 0.0% | 0.4% | | RETAIL NONCORE (6) | | | | | | | | | | | Industrial - Distribution | $.608 | $.128 | $.736 | $.610 | $.128 | $.739 | 0.4% | 0.0% | 0.4% | | Industrial - Transmission | $.339 | $.066 | $.405 | $.340 | $.066 | $.406 | 0.3% | 0.0% | 0.2% | | Industrial - Backbone | $.126 | $.066 | $.191 | $.126 | $.066 | $.192 | 0.7% | 0.0% | 0.5% | | Electric Generation - Transmission (G-EG-D/LT) | $.344 | | $.344 | $.345 | | $.345 | 0.3% | | 0.3% | | Electric Generation - Backbone (G-EG-BB) | $.139 | | $.139 | $.140 | | $.140 | 0.6% | | 0.6% | | NGV 4 - Distribution (uncompressed service) | $.608 | $.048 | $.656 | $.610 | $.048 | $.659 | 0.4% | 0.0% | 0.4% | | NGV 4 - Transmission (uncompressed service) | $.329 | $.048 | $.378 | $.330 | $.048 | $.378 | 0.3% | 0.0% | 0.2% | | WHOLESALE CORE AND NONCORE (G-WSL) (6) | | | | | | | | | | | Alpine Natural Gas | $.262 | | $.262 | $.263 | | $.263 | 0.3% | | 0.3% | | Coalinga | $.264 | | $.264 | $.265 | | $.265 | 0.3% | | 0.3% | | Island Energy | $.284 | | $.284 | $.285 | | $.285 | 0.3% | | 0.3% | | Palo Alto | $.257 | | $.257 | $.258 | | $.258 | 0.3% | | 0.3% | | West Coast Gas - Castle | $.577 | | $.577 | $.580 | | $.580 | 0.5% | | 0.5% | | West Coast Gas - Mather Distribution | $.792 | | $.792 | $.796 | | $.796 | 0.5% | | 0.5% | | West Coast Gas - Mather Transmission | $.266 | | $.266 | $.267 | | $.267 | 0.3% | | 0.3% | - *(1) Transportation-Only rates include: (i) a transportation component that recovers customer class charges, customer access charges, CPUC fees, local transmission (where applicable), distribution costs (where applicable), and the* [*Assembly Bill 32*](https://ww2.arb.ca.gov/resources/fact-sheets/ab-32-global-warming-solutions-act-2006?ref=calregulatory.com) *Cost of Implementation fee (wholesale and certain large customers are directly billed by the* [*California Air Resources Board*](https://ww2.arb.ca.gov/?ref=calregulatory.com)*, and are exempt from PG&E's AB 32 COI rate component of *$0.00294 per therm*).* - *(2) A 2004 decision (*[*D.04-08-010*](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/39314.PDF?ref=calregulatory.com)*) authorized PG&E to remove the gas Public Purpose Program surcharge that recovers the costs of low-income California Alternate Rates for Energy (*[*CARE*](https://webtraining.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com)*), low-income energy efficiency, energy efficiency, the Research Development and Demonstration program and BOE/CPUC administration costs from transportation rates and into its own separate surcharge tariff. Certain customers are exempt from paying the PPP surcharge.* - *(3) Rates are rounded up to three decimals for viewing ease. Percentage rate changes are calculated on a five-digit basis.* - *(4) CARE customers receive a 20% discount off of PG&E's total bundled rate and are exempt from the CARE portion of PG&E's PPP surcharge (G-PPPS) rates and cost recovery of the* [*California Solar Initiative Thermal program*](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/california-solar-initiative/csi-thermal-program-solar-water-heating?ref=calregulatory.com)*.* - *(5) Billed transportation rates paid by all customers include an additional GHG Compliance Cost of *$0.08595* and Operational Cost component of *$-0.00005*.* - *(6) Covered entities within classes and the wholesale class (i.e., customers that currently have a direct obligation to pay for allowances directly to CARB) will see a line-item credit on their bill equal to the GHG Compliance Cost of *$0.08595* per therm times their monthly billed volumes.* ### **INSTANT ANALYSIS** This is a modest, across-the-board increase. The entire $20 million revenue increase flows from a single cost recovery driver (the WMCE decision from earlier this month) with no base rate changes, no new tariff structures, and no General Rate Case adjustments embedded. - A "Separately Funded Projects" line carries the full $19.7 million load before Revenue Fees and Uncollectibles, with the remaining $318 thousand attributable to RF&U. Everything else in the revenue requirement (local transmission, distribution base, balancing accounts, GHG costs) is held flat from January. - On a per-therm basis, the increases run approximately $0.001 to $0.004 depending on customer class, producing percentage changes clustered between 0.2% and 0.7% across the board. Industrial Backbone registers the largest percentage move at 0.7% (a function of its low base rate, not the magnitude of the underlying cost shift). - For covered entities (including the oil company and industrial customers who comprise some of CRI's readership) the effective net increase is smaller still. The GHG compliance cost of $0.08595/therm is embedded in every billed rate, but covered entities receive that amount back as a line-item credit, partially offsetting the nominal increase. - The PPP surcharge is structurally unchanged across all classes, a consequence of the cost separation established in D.04-08-010\. Wholesale customers (G-WSL) face the smallest absolute increases in the filing ($0.001/therm across Alpine, Coalinga, Island, and Palo Alto) and remain exempt from the PPP surcharge entirely. The main story is $20 million of wildfire cost recovery landing on gas customers effective March 1, with the burden falling disproportionately on core residential and small commercial ratepayers who absorb $16.4 million of the total increase and lack the covered-entity offsets available to industrial and electric generation customers. ### WHO SHOULD CARE - **Noncore industrial and electric generation customers**. If you're taking gas at distribution, transmission, or backbone level under rate schedules G-NT or G-EG, your transportation rate is moving March 1\. The increases are small but they're real, and if you're running high volumes, the per-therm math adds up. Covered entities should confirm their billing system is properly applying the GHG compliance cost credit to net the increase down. - **Gas traders and trading desks** should note this filing as a cost basis input. It doesn't contain market-moving numbers, but March 1 is a clean effective date and the per-therm shifts need to be reflected in any California gas transportation cost modeling. - **Wholesale customers**.Palo Alto, Coalinga, Island Energy, Alpine, and West Coast Gas have the smallest exposure here but should confirm the $0.001/therm adjustment is captured in their tariff tracking. - **Regulatory affairs teams at utilities and large industrials** monitoring D.26-02-004 implementation should treat this as confirmation that the WMCE revenue requirement is now flowing into rates. Anyone considering a protest has until March 16\. Given the Tier 1 designation and compliance-only nature of the filing, opposition is unlikely. But parties who contested costs in the underlying WMCE proceeding should verify the authorized amounts implemented here ($14.6 million in gas distribution, $5.4 million in gas transmission) match their expectations from D.26-02-004. ### MONDAY AGGREGATE: Aliso Canyon Clash; PCIA/ERRA Reform (Track 3); Criticism of IRP Continues URL: https://www.calregulatory.com/monday-aggregate-aliso-canyon-clash-pcia-erra-reform-track-3-criticism-of-irp-continues/ Last updated: 2026-02-23T22:10:55.000Z Today's update examines party criticisms of Aliso Canyon natural gas storage levels, consequential portfolio recovery issues in the ERRA/PCIA Reform docket, and the scoping memo for SoCalGas and Lakeside Pipeline LLC’s application to recover cost overruns from a dairy biomethane pilot project. The latter item is an early stress test for Commission tolerance on RNG cost escalations. Additionally, parties continue to characterize the current [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083681.PDF?ref=calregulatory.com) in the IRP rulemaking as overly rigid, potentially oversized, and misaligned with affordability risks. --- ### ALISO CANYON STORAGE On February 20, multiple parties responded to SoCalGas’s compliance application in [A.26-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com), presenting divergent views on the future role of the Aliso Canyon storage facility. (*See CRI's recent coverage of this matter* [*here*](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/)*.*) At issue is SoCalGas's request for CPUC review of Energy Division’s [2025 Aliso Canyon Biennial Assessment](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/2025%5Faliso%5Fcanyon%5Fbiennial%5Fassessment.pdf?ref=calregulatory.com), which recommends reducing the facility’s maximum inventory level by **10 Bcf** from the current **68.6 Bcf** authorized in a 2024 decision ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)). [IRP Cycle 2024-2026 Changes; Woolsey Fire Financing OrderCovers: IRP; Woolsey Fire; Aliso Canyon; 2026 ERRA Forecasts of PG&E and SCE![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-41.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/photo-1688040637388-d2c0aa7b9907-6)](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/) In their remarks, stakeholders advance competing reliability, safety, and cost arguments. - Sierra Club [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K064/600064174.PDF?ref=calregulatory.com) the application exaggerates gas demand and reliability risks. Pointing to declining gas use, rapid renewable and battery resource growth, and Energy Division's own modeling (which shows 44% or lower inventory levels sufficient across 19 scenarios), Sierra Club urges the CPUC to reduce storage capacity by as much as **38 Bcf**, bringing the limit down to **30 Bcf**. Sierra Club also calls for accelerated transition away from gas infrastructure and enhanced coordination with electric system planning. - Cal Advocates similarly [protests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960151.PDF?ref=calregulatory.com) the requested increase, focusing on whether expanding inventory above the current authorized level would exceed the safe reservoir operating pressure of **3,600 psi**, conflict with the scope of prior decisions, or impose unjustified risks and costs on ratepayers. Cal Advocates urges additional analysis of systemwide storage coordination and safety oversight. - Porter Ranch resident **Issam Najm** likewise [contends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K049/600049551.PDF?ref=calregulatory.com) that SoCalGas dismissed Energy Division's analysis without justification. Using SoCalGas's own withdrawal data, Najm shows that even at 40 Bcf stored, withdrawal capacity (approximately 900 MMcfd) far exceeds the 550 MMcfd threshold Staff identified as the reliability requirement, leading him to recommend a specific **20 Bcf** reduction to **48.6 Bcf** rather than any increase. On the other hand, the Indicated Shippers (representing major noncore industrial gas users including Chevron, Marathon Petroleum, California Resources Corp., BP, and PBF Holding) [support](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K049/600049550.PDF?ref=calregulatory.com) the application. The Shippers assert that reducing storage would heighten outage risk, price volatility, and curtailment exposure during extreme weather. The Shippers criticize the Biennial Assessment for unrealistic assumptions that understate the need for storage and overstate available pipeline supplies. Separately, the Southern California Generation Coalition (SCGC) [seeks party status](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K953/599953805.PDF?ref=calregulatory.com) to protect gas-fired power generators' interests, emphasizing that changes to inventory limits could materially affect fuel reliability and energy costs for electric generation dependent on SoCalGas transmission. SCGC's distinguishing contribution is a proposal to use backcasts (historical data analysis of whether the system could have operated without Aliso Canyon) rather than forecasts to evaluate storage need, a methodological position the Commission previously declined to mandate but did not prohibit. **INSTANT ANALYSIS:** Environmental and ratepayer parties are pushing for deeper storage cuts on safety and demand-decline grounds, while industrial users and generators argue reductions would raise outage risk and price volatility. This may become a slow-moving proceeding with a compromise outcome (partial reduction or added safeguards), and not a decisive shift toward closure of the Aliso Canyon facility. --- ### PCIA/ERRA REFORM The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960141.PDF?ref=calregulatory.com) in the Energy Resource Recovery Account and Power Charge Indifference Adjustment reform rulemaking ([R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com)), directing the investor-owned utilities and inviting other parties to file comments on the scope of Track 3. Track 3 will address the proceeding’s remaining broad issues. - Opening comments are due **March 27**; and - Reply comments are due **April 10**. Parties are asked to identify which issues Track 3 should cover, how they should be prioritized, potential data confidentiality constraints, and expected timing and interdependencies. The ruling notes that earlier tracks addressed narrower topics and that Track 3 is intended to tackle the wider set of unresolved ERRA and PCIA policy questions outlined in the original Order Instituting Rulemaking. Party input will inform a forthcoming Track 3 scoping memo and possibly a future status conference. **INSTANT ANALYSIS:** This ruling opens the agenda-setting phase for Track 3 of the ERRA/PCIA reform proceeding, where the Commission will finally address the most consequential unresolved cost-allocation and portfolio recovery issues left outside the narrower earlier tracks. By asking parties to propose scope, priorities, confidentiality frameworks, and timing, the ALJ is effectively inviting stakeholders to shape the battlefield before formal policy positions harden. This dynamic favors well-resourced utilities and sophisticated intervenors. For load-serving entities, Community Choice Aggregators, and large customers, the Track 3 scope will determine whether such contentious topics as legacy cost treatment, portfolio optimization rules, and future PCIA mechanics are handled incrementally or in a single high-stakes phase. --- ### BIOMETHANE **Commissioner John Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083265.PDF?ref=calregulatory.com) in [A.25-08-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395999.PDF?ref=calregulatory.com) establishing the procedural framework for the CPUC’s review of SoCalGas and Lakeside Pipeline LLC’s request to recover approximately **$7.8 million** in cost overruns from the Lakeside Maas Energy Works Dairy Biomethane pilot project. The latter is one of several projects authorized to demonstrate dairy biomethane interconnection to the gas pipeline system. The ruling defines the key issues for review, including whether project management and cost increases above the original bid were reasonable, whether proposed rate recovery is justified, and how the project affects environmental and social justice goals. The proceeding's timeline reflects an application the Commission found deficient at the outset. At the November 2025 prehearing conference, the ALJ highlighted missing engineering documentation in three areas: - Foundation redesign for compressors; - Power distribution center scope increases; and - instrumentation additions. SoCalGas addressed these issues through supplemental testimony. The ruling cites supplemental testimony as the reason intervenors received 75 days to prepare testimony rather than the 60 days Cal Advocates had requested. Intervenor testimony is due **April 24**, with rebuttal testimony served on **June 19**. Opening briefs are scheduled for **August 12**, with reply briefs due **September 11**. **INSTANT ANALYSIS:** This scoping memo frames the proceeding around whether SoCalGas and Lakeside can justify $7.8 million in biomethane pilot cost overruns and recover those amounts in rates. But it also leaves the door open to a broader examination of project management practices that could influence future renewable gas initiatives. The inclusion of environmental and social justice impacts as a formal issue reflects the CPUC’s continued effort to apply ESG criteria even in infrastructure cost-recovery cases, which may complicate approval for similar projects going forward. The timeline suggests a methodical review rather than an expedited pathway, which creates uncertainty for developers pursuing dairy biomethane interconnections under earlier pilot authorizations. Generally speaking, the case is shaping up to be an early test of Commission tolerance toward cost escalation in state-backed renewable gas pilots. For utilities, agricultural methane developers, and ratepayer advocates evaluating the financial viability of California’s biomethane build-out, this process bears watching. --- ### SELF-GENERATION INCENTIVE PROGRAM **Commissioner Karen Douglas** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960147.PDF?ref=calregulatory.com) in the SGIP docket directing program administrators to immediately strengthen verification of Total Eligible Project Costs for Residential Solar and Storage Equity projects before incentive payments are issued, after evidence showed reported project costs far exceeding both incentive levels and market averages. The Residential Solar and Storage Equity program, funded at **$252 million** to support low-income households installing solar-plus-storage systems, was designed so incentives (paired with the federal tax credit) would cover most project costs. However, reviews found average reported costs of roughly $46,000 across all developers and $58,000 among the largest developers, compared with an expected cost near $30,000 and market estimates closer to $25,000\. These elevated costs reduce the number of households the program can serve and may require low-income participants to pay unexpected out-of-pocket expenses. Finding wide and unexplained price variations for similar equipment and installations, the ruling now requires enhanced documentation for any project whose reported costs exceed 90% of the maximum allowable incentive, including receipts, labor contracts, and potentially more extensive verification for projects above 100%. **INSTANT ANALYSIS:** By conditioning payments on cost verification above the 90% threshold, the ruling shifts enforcement risk onto developers and program administrators while preserving the headline incentive structure adopted in a 2024 CPUC decision ([D.24-03-071](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M527/K963/527963349.PDF?ref=calregulatory.com)). The move also functions as a soft market correction: if inflated bids cannot be substantiated, either prices will compress or project volume will fall, slowing Residential Solar and Storage Equity deployment but extending budget reach. Expect heightened scrutiny of third-party ownership models, contractor practices, and potential arbitrage of stacked subsidies, with possible downstream implications for SGIP participation economics and developer consolidation in the equity segment. --- ### INTEGRATED RESOURCE PLANNING The [Alliance for Retail Energy Markets](http://www.retailenergymarkets.com/?ref=calregulatory.com) (AReM) submitted a written ex parte communication urging the CPUC to revise its [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083681.PDF?ref=calregulatory.com) in the Integrated Resource Planning rulemaking. [February 26, 2026 CPUC Voting Meeting PreviewIRP 6,000 MW Order; Closure on Winter Gas Price Investigation![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-44.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Feb-10-2026--16-.png)](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-preview-irp-6-000-mw-order-closure-on-winter-gas-price-investigation/) The PD, scheduled for consideration on **February 26**, require major electric resource procurement for 2029–2032\. AReM argues the PD relies on [effective load carrying capability](https://stanwichenergy.com/insights/understanding-effective-load-carrying-capability-elcc-how-renewable-reliability-impacts-costs-for-energy-users?ref=calregulatory.com) (ELCC) metrics that could translate a nominal 6 GW procurement mandate into more than **40 GW** of solar-plus-storage capacity on a nameplate basis, raising feasibility, market, and cost concerns. - Based on recent CPUC modeling, AReM estimates annual procurement costs could rise from roughly **$691 million** under earlier assumptions to as much as **$2–$5 billion**, particularly as data center load growth drives demand while policy on allocating those costs remains unsettled. - AReM further contends the proposal risks shifting costs unfairly onto existing customers (especially those served by electric service providers in the [Direct Access program](https://www.cpuc.ca.gov/consumer-support/consumer-programs-and-services/electrical-energy-and-energy-efficiency/community-choice-aggregation-and-direct-access-/direct-access?ref=calregulatory.com), which is capped and cannot enroll new data center loads) while also removing compliance flexibility that currently allows load-serving entities to manage procurement delays without penalties. AReM asks the CPUC to reduce procurement volumes, preserve compliance flexibility, prevent cost shifting, and adopt a more programmatic, technically grounded procurement framework aligned with affordability and broader state policy objectives. (*Additional CRI coverage of ex parte meetings in this proceeding are provided at the links below*.) [SONGS Cost Fight, IRP Flex PushToday’s roundup covers disputes over the Nuclear Decommissioning Cost Triennial Proceeding for SONGS, and ex parte influences on the IRP PD![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-42.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Feb-12-2026--1-.png)](https://www.calregulatory.com/friday-aggregate-songs-cost-fight-irp-flex-push-mega-load-interconnection-changes/) [Wildfire Financing, Gas Backbone UpgradesPG&E’s CPCN withdrawal and emergency exemption move is procedural arbitrage: move fast now, and litigate cost recovery in a General Rate Case.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-43.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Feb-12-2026--25-.png)](https://www.calregulatory.com/wednesday-aggregate-12/) **INSTANT ANALYSIS:** The AReM ex parte filing adds to a rapidly consolidating stakeholder narrative that the proposed 2029–2032 procurement mandate in the IRP docket is overly rigid, potentially oversized, and misaligned with affordability risks. - Like CalCCA, the Joint IOUs, and Cal Advocates, AReM warns that inflexible procurement volumes combined with constrained compliance pathways could force load-serving entities into inefficient resource choices and elevated costs, particularly if storage limits, procurement deadlines, and modeling assumptions remain unchanged. AReM’s focus on ELCC math translating a nominal 6 GW mandate into far larger nameplate procurement (and potentially billions in annual costs) intensifies the affordability argument already advanced by CCAs and consumer advocates. - AReM's filing also introduces a distinct distributional concern: cost exposure tied to data-center-driven load growth may fall on existing customers, especially Direct Access participants who cannot serve new loads due to the statutory cap. This echoes Cal Advocates’ warnings about over-procurement and ratepayer harm, while aligning with utility requests to reassess need using updated forecasts and preserve flexibility for delayed projects. With ex parte activity intensifying days before the February 26 vote, the probability of late edits is rising. Any revisions to procurement size, ELCC assumptions, storage treatment, or compliance mechanisms would cascade into Resource Adequacy positioning, contract timing, transmission planning, and long-term resource mix decisions. The proceeding remains in flux, and the final order could differ significantly from the current draft. ### WEEKEND NEWS CODEX: Assembly Bill 1777; Flexible Service Connection; Diablo Canyon URL: https://www.calregulatory.com/weekend-news-codex-8/ Last updated: 2026-02-21T02:06:36.000Z - **Bill Would Expand CARB Authority Over Indirect Emissions Sources:** "California Assemblymember Robert Garcia introduced legislation to expand the state’s authority to regulate greenhouse gas emissions. [AB 1777](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1777&ref=calregulatory.com) would empower the California Air Resources Board to adopt regulations targeting emissions linked to 'indirect sources,' which are facilities and land uses that attract significant mobile emissions but have historically fallen outside direct regulatory control by state authorities." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/bill-would-expand-carb-authority?ref=calregulatory.com) - **CAISO Requests Input on Large Load Considerations Report:** "CAISO laid out [these issues in a paper](https://www.caiso.com/documents/issue-paper-large-load-consideration-jan-20-2026.pdf?ref=calregulatory.com) released Jan. 20, and is asking for written comments [to be submitted](https://www.caiso.com/notices/large-load-considerations-comment-deadline-on-information-session-moved-to-2-25-26?ref=calregulatory.com) by Feb. 25\. Data center load in the CAISO grid is expected to increase by 1.8 GW by 2030 and 4.9 GW by 2040, according to a January forecast from the California Energy Commission." [**UTILITY DIVE**](https://www.utilitydive.com/news/caiso-california-grid-data-centers-transmission-large-loads/812440/?ref=calregulatory.com) - **California's Energy Transition is Failing the Middle Class – and We Need to Admit It**: "This isn’t a distant hypothetical. Seasonal fuel blend changes, refinery outages, rising summer demand, and grid strain are converging on a system with no margin left. When that happens, prices won’t just rise, they will surge. And when energy costs more, everything costs more." [**ORANGE COUNTY REGISTER**](https://www.ocregister.com/2026/02/15/californias-energy-transition-is-failing-the-middle-class-and-we-need-to-admit-it/?ref=calregulatory.com) - **California Has Abundant Solar Power – Here's How Factories Can Use It:** "Some 36,000 manufacturing facilities operate in California, and many use large amounts of fossil gas to produce everything from cheese, olive oil, and canned fruit to cardboard, medicines, and plastic resins. Switching to electrified processes would [significantly and immediately slash emissions](https://www.canarymedia.com/articles/clean-industry/report-electrifying-factories-heat-cut-emissions?ref=calregulatory.com) from those factories, experts say. Yet industrial firms are generally hesitant to change — and sky-high power bills are a major reason why." [**CANARY MEDIA**](https://www.canarymedia.com/articles/clean-energy-manufacturing/california-abundant-solar-power-factories?ref=calregulatory.com) - **CPUC Decision on "Limited Load Profiles" Offers Important Solution for Faster EV Charger Rollout in California:** "A limited load profile is a schedule of how much power the system can draw from the grid at different times of the day or year, based upon when capacity is available. The decision establishes the use of limited load profiles as a temporary, 'bridging solution' that projects may utilize to get connected and start operating while waiting for the utility to complete grid upgrades. Historically, if the electric grid required upgrades to safely and reliably supply the maximum amount of power a project required, projects could not connect until the utility completed those upgrades—the construction of which can take years. The use of limited load profiles, a type of 'flexible service connection,' changes this scenario." [**INTERSTATE RENEWABLE ENERGY COUNCIL**](https://irecusa.org/blog/irec-news/cpuc-decision-on-limited-load-profiles-offers-important-solution-for-faster-ev-charger-rollout-in-california/?ref=calregulatory.com) - **Data Center Growth Has Helped PG&E Cut Rates 11% Since 2024, CEO Says:** "The company’s total large load pipeline declined from 9.6 GW in September 2025 to 7.3 GW at the end of the year, but more projects are entering final engineering phases. PG&E maintains that it can reduce customers’ electric bills by about 1% for each gigawatt of new load on the system." [**UTILITY DIVE**](https://www.utilitydive.com/news/data-center-growth-has-helped-pge-cut-rates-11-since-2024-ceo-says/812230/?ref=calregulatory.com) - **Hard Landing – Motorists in Northern California Enter the Hurt Locker:** "...decades of aggressive regulatory harassment have left California’s hydrocarbon fuels industry teetering on the edge of a collapse that will shake the state’s economy to its core. To summarize briefly, California is effectively two fuel islands, one clustered around San Francisco and the other around Los Angeles. Neither half of the state is connected by inbound oil or refined product pipelines to the outside world, and links between north and south are skimpy. Northern California [in particular](https://newsletter.doomberg.com/p/bay-watch?ref=calregulatory.com) faces an urgent crisis, as one of its few remaining petroleum refineries is shutting down, leaving the region largely unable to provide for its own gasoline, diesel, or jet fuel. Everybody sees the problem coming, and few doubt it’s just a matter of time before calamity strikes." [**DOOMBERG**](https://newsletter.doomberg.com/p/hard-landing?ref=calregulatory.com) - **Is California Going to Shut Down This $16 + Billion Nuclear Plant in 2030?** "Diablo Canyon provides clean, emission-free electricity 24 hours a day, 365 days a year. It generates roughly 18 terawatt-hours annually—the equivalent of five Hoover Dams every year—without air pollution, carbon emissions, or reliance on weather. Retiring it early would almost certainly require replacement with fossil fuel generation, increasing emissions precisely when California is trying to reduce them." [**GREEN NUKE**](https://greennuke.substack.com/p/is-california-going-to-shut-down) - **Mitigating Hydro Risks in Western US Power Markets:** "While hydro serves as the system backbone in the PNW, with prices and scarcity conditions strongly dependent on the water year, annual hydro variability in California makes it hard to rely on. CAISO can see enormous year-to-year variation in hydro generation, with cascading dams increasing the operational complexity. When it comes to price dynamics, solar drives low on-peak prices while gas and carbon pricing drive higher off-peak prices." [**ASCEND ANALYTICS** ](https://www.ascendanalytics.com/blog/hedging-hydro-us-energy-markets?ref=calregulatory.com) - **Octopus Energy Invests $1 Billion in California Clean Technology:** "As part of its investment, Octopus will acquire a solar and battery project in California, which is expected to become fully operational by July. It will also invest in heat battery innovation to target industries that are hard to electrify, as well as two Californian carbon removal companies." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/02/19/octopus-energy-invests-1-billion-in-california-clean-technology/?ref=calregulatory.com) - **PG&E Accelerating Home Electrification for Customers vis SPAN Edge:** "SPAN Edge is an at-the-meter device that enables real-time load management and allows homes to add new electric appliances or electric vehicle charging without costly electric panel or service upgrades—addressing one of the most significant barriers to residential electrification. PG&E will deploy the new SPAN Edge devices coupled with next-generation metering infrastructure through its new PanelBoost program, a grid-edge innovation initiative designed to reduce upgrade costs for customers adopting electric vehicles, heat pumps, induction cooking, and other high efficiency electric technologies." [**PV MAGAZINE**](https://pv-magazine-usa.com/press-releases/pge-accelerating-home-electrification-for-customers-via-span-edge/?ref=calregulatory.com) - **When the Sun Sets, Batteries Rise – 24/7 Solar in California:** "California’s aims in deploying their battery fleet are to blend together many energy resources, including soon to be integrated [New Mexican](https://pv-magazine-usa.com/2022/11/15/regulatory-approval-for-sunzia-transmission-paves-the-way-for-a-southwest-renewable-energy-corridor/?ref=calregulatory.com) and eventually offshore wind – to rid the state of fossil fuels. These batteries coupled with such a massive solar initiative are [expediting the gaa to solar process](https://pv-magazine-usa.com/2025/07/09/solar-becomes-top-source-of-electricity-in-california/?ref=calregulatory.com)." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/02/17/when-the-sun-sets-batteries-rise-24-7-solar-in-california/?ref=calregulatory.com) ### CPUC Draft Resolution Imposes Stricter Interconnection Refund Terms for PG&E Data Center in Sunnyvale URL: https://www.calregulatory.com/cpuc-draft-resolution-imposes-stricter-interconnection-refund-terms-for-pg-e-data-center-in-sunnyvale/ Last updated: 2026-02-21T02:54:49.000Z The CPUC issued [Draft Resolution E-5433](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K319/599319897.PDF?ref=calregulatory.com), which approves, with modifications, PG&E’s agreement to energize a new 49-MW data center and computing lab in Sunnyvale for [Menlo Equities](https://www.menloequities.com/?ref=calregulatory.com). The data center requires the construction of new transmission facilities, including a 115-kV line extension, and substation upgrades. The draft resolution finds the project reasonable but imposes additional ratepayer protections due to the scale and uncertainty of a transmission-level large load. These protections include limiting refunds of the customer's upfront energization costs to **75%** of PG&E's annual net revenues from the project, plus an income-tax component adjustment. In this scenario, "net revenues" is defined as the transmission component of Menlo Equities' electric rates plus the per-meter customer charge, explicitly excluding generation costs and Public Purpose Program charges. The draft resolution also extends the refund period from 10 to 15 years. Additionally, the draft resolution allows PG&E to recover costs on an actual-cost basis, removes certain tariff options that could shift risk to ratepayers, and treats the filing as an exceptional case while broader rules for transmission-level retail service are being considered in a separate proceeding. The earliest the CPUC will consider this item is **March 19**. ### INSTANT ANALYSIS This draft resolution shows the CPUC moving toward a stricter, risk-containment framework for transmission-level large loads, particularly data centers and computing facilities. By capping refunds at 75% of net revenues and extending the recovery horizon, the Commission is demonstrating that future hyperscale customers will be expected to shoulder more interconnection risk rather than relying on optimistic load forecasts. The draft resolution also functions as a live prototype for the pending Rule 30 framework on transmission-level retail service, though its language explicitly disclaims that linkage, stating the draft resolution should not prejudge the PG&E Rule 30 proceeding ([A. 24-11-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com)) or be considered precedential. That disclaimer notwithstanding, the parallels are real: the cost-containment mechanisms, ratepayer risk logic, and refund modifications adopted here will almost certainly inform how Rule 30 is ultimately written. For CRI readers, the takeaway is that large-load siting, interconnection negotiations, and transmission planning in PG&E territory are entering a new phase where policy risk, not engineering constraints, may become the binding factor. ### FRIDAY AGGREGATE: SONGS Cost Fight, IRP Flex Push, Mega-Load Interconnection Changes URL: https://www.calregulatory.com/friday-aggregate-songs-cost-fight-irp-flex-push-mega-load-interconnection-changes/ Last updated: 2026-02-21T02:53:19.000Z Today's roundup covers ongoing disputes over the [2024 Nuclear Decommissioning Cost Triennial Proceeding for San Onofre](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M548/K362/548362332.PDF?ref=calregulatory.com), ex parte influences on a proposed decision in the IRP docket, and PG&E's handling of large load interconnections. Also, on February 13 parties served intervenor testimony in [PG&E's 2027 General Rate Case Phase 1](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com). The volume is substantial and will shape the trajectory of the proceeding. CRI is available to produce a comprehensive synthesis for clients who require rapid situational awareness in this proceeding. ([*Contact*](https://www.calregulatory.com/contact-us/) *if needed.*) *If you are finding our work useful, please consider becoming a* [***paid subscriber***](https://www.calregulatory.com/pricing/)*, or* [***inquiring***](https://www.calregulatory.com/contact-us/) *about tailored work for your organization.* ### NUCLEAR DECOMMISSIONING In the [2024 Nuclear Decommissioning Cost Triennial Proceeding for San Onofre (SONGS)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M548/K362/548362332.PDF?ref=calregulatory.com), the major parties’ reply briefs highlight ongoing disputes over cost assumptions, contingency levels, spent fuel timelines, and the handling of Department of Energy litigation proceeds. - The Joint Utilities (SCE and SDG&E) [defend their decommissioning cost estimates and core assumptions against intervenor critiques](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101727.PDF?ref=calregulatory.com). They argue that assuming federal removal of spent nuclear fuel beginning around 2034 is reasonable given longstanding Commission practice and pervasive uncertainty about federal action. - The utilities oppose modeling multiple long-duration storage scenarios as speculative and instead support using DOE litigation recoveries as a funding buffer if removal is delayed. They also reject calls to include an alternative “Settlement Scenario” for dismantlement timing in future estimates, contending that only the Operational Scenario reflects the actual strategy being implemented. - On cost issues, the utilities defend contingency levels for contractor work and other forecast assumptions as grounded in risk analysis and expert studies. - Notably, the utilities' defense of contingency is specific: they argue the Decommissioning General Contractor contingency increase above the previously approved 10% level is justified by the costs of settling COVID-19 pandemic claims, not a blanket defense of all contingency assumptions. - TURN’s [reply brief](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K083/600083246.PDF?ref=calregulatory.com) presses the opposite direction, arguing the utilities’ forecasts overstate costs and contingencies. TURN urges the CPUC to: - Keep the contractor contingency at the previously approved level rather than increasing it; - Trim multiple SONGS Unit 1 cost forecasts to align with recent actual spending; and - Remove or reduce contingencies tied to staffing, leases, incentives, security overtime, inspection fees, and contracted services where historical data does not support higher projections. - On funding policy, TURN contends trust balances appear sufficient for decades of storage costs and therefore DOE litigation proceeds should flow back to ratepayers rather than being retained in decommissioning trusts. - Cal Advocates [focuses on specific cost components it views as unsupported or premature](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101828.PDF?ref=calregulatory.com). It: - Argues the utilities failed to justify certain cleanup costs tied to returning land parcels to the Navy; - Challenges proposed increases in IT-related decommissioning expenses; - Questions a higher contingency assumption for Palo Verde decommissioning estimates; and - Recommends splitting DOE litigation proceeds between customer refunds and trust funding rather than diverting all proceeds to the trusts. - The Alliance for Nuclear Responsibility [emphasizes long-term uncertainty and intergenerational equity risks](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101610.PDF?ref=calregulatory.com). It argues the utilities rely on overly optimistic assumptions about the timing of federal removal of spent nuclear fuel and should analyze longer onsite storage scenarios and stress-test funding adequacy accordingly. - The Alliance also supports continued evaluation of an alternative dismantlement scenario in case coastal or regulatory decisions require earlier structural removal, and it cautions against additional contributions to decommissioning trusts absent clearer need. - On trust funding, the Alliance's position is the inverse of what it might appear to be: the Alliance is not advocating for additional contributions to the decommissioning trusts, but rather cautioning against diverting DOE litigation proceeds into those trusts without first conducting proper quantitative analysis of whether the funding is actually needed. **INSTANT ANALYSIS:** The main conflict here is who carries long-term risk if spent fuel stays onsite longer than assumed. Utilities want to preserve DOE litigation proceeds inside decommissioning trusts as a hedge; consumer groups want refunds to ratepayers now. That decision will determine whether future funding pressure lands on utility balance sheets or customers. The battle over fuel-removal timelines is equally significant. Longer storage assumptions would inflate projected costs and could reopen collection debates; maintaining current assumptions keeps liabilities contained for now. A second, underappreciated axis of conflict is the [California Coastal Commission](https://www.coastal.ca.gov/?ref=calregulatory.com)'s potential authority over the timing of subsurface structure removal at the SONGS site. The Alliance for Nuclear Responsibility argues the utilities are making an unsupported assumption that the CCC will indefinitely defer requiring structural removal until all spent fuel has left the site. If the CCC takes a different view when SCE files its required permit amendment by June 2028, it could force earlier and more costly dismantlement activity (independent of the spent fuel timeline entirely). The utilities and the Alliance genuinely disagree about this risk, and it represents a regulatory wildcard that current cost estimates may not adequately capture. This proceeding is a precedent-setting test of how the CPUC will ultimately allocate multi-decade infrastructure risk, with implications beyond nuclear. --- ### INTEGRATED RESOURCE PLANNING Ex parte meetings continue to mount in the CPUC's Integrated Resource Planning docket, as parties address the pending [IRP proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083681.PDF?ref=calregulatory.com), which is scheduled for consideration on February 26. [February 26, 2026 CPUC Voting Meeting PreviewIRP 6,000 MW Order; Closure on Winter Gas Price Investigation![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-40.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Feb-18-2026--8-.png)](https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-preview-irp-6-000-mw-order-closure-on-winter-gas-price-investigation/) In meetings with CPUC personnel, parties advanced competing visions of how the 2029–2032 procurement framework should be structured (*see CRI's discussion of CalCCA and Cal Advocates' recent ex parte meetings* [*here*](https://www.calregulatory.com/wednesday-aggregate-12/)*.*) - California Resources Corporation (CRC) [urged](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K260/600260818.PDF?ref=calregulatory.com) commissioners’ offices to modify the PD to explicitly allow natural-gas generation paired with carbon capture and storage (including retrofits of existing plants and CCS-enabled fuel-cell configurations) to qualify as eligible interim resources and planning assumptions. - CRC also separately asked the Commission to include NGCCS as a resource type in the [2026–2027 Transmission Planning Process](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/2024-26-irp-cycle-events-and-materials/assumptions-for-the-2026-2027-tpp?ref=calregulatory.com) Base Case modeling, a distinct request from the 2029–2032 interim procurement window. - CRC argued that a “least-regrets” approach would recognize NGCCS as a clean, firm, dispatchable option that could deliver emissions reductions, reliability, and cost control sooner than a renewables-plus-storage pathway alone. CRC cited [CARB’s Scoping Plan](https://ww2.arb.ca.gov/our-work/programs/ab-32-climate-change-scoping-plan?ref=calregulatory.com), ongoing federal permitting, and the prospect of near-term CO₂ injection projects in California as evidence that the technology is ready for deployment. - In a separate ex parte meeting, the three large electric utilities (PG&E, SCE, and SDG&E) [jointly urged revisions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M600/K064/600064159.PDF?ref=calregulatory.com) that would moderate the PD's procurement mandate rather than expand eligible resource types. The utilities asked the Commission to: - Retain flexible compliance mechanisms; - Consider reducing or delaying the 2032 procurement requirement based on updated load forecasts from the [California Energy Commission’s 2025 Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr/2025-integrated-energy-policy-report?ref=calregulatory.com); - Clarify effective load carrying capability assumptions; - Allow any Diablo Canyon extension to count toward requirements; and - Ensure that a proposed storage cap would not restrict hybrid resources. - The utilities' message focused on feasibility, cost containment, and implementation risk, warning that rigid targets or penalty exposure amid uncertain forecasts and project delays could drive unnecessary customer costs. **INSTANT ANALYSIS:** Stakeholders across the IRP docket are converging on one message: the proposed 2029–2032 procurement order is too rigid given load uncertainty, project risk, and resource constraints. The Joint IOUs, CalCCA, and Cal Advocates have all pressed for greater flexibility (reassessing the 2032 target with updated forecasts, easing the storage cap’s application, and preserving compliance mechanisms for delayed projects) while resource developers simultaneously push to expand eligible technologies such as gas with carbon capture. The alignment across utilities, CCAs, and consumer advocates increases the odds of late revisions before the February 26 vote. Any changes to procurement volumes, storage limits, or compliance rules would ripple into RA strategy, contract timing, and gas-fleet planning, extending uncertainty for load-serving entities that expected the trajectory to stabilize. --- ### LARGE LOAD INTERCONNECTIONS PG&E submitted [Advice Letter 5180-G/7843-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5180-G.pdf?ref=calregulatory.com), requesting CPUC approval to add new exhibits to its existing Agreement to Perform Tariff Schedule Related Work that would govern preliminary services for large electric interconnection projects. - The proposed exhibits establish detailed terms under which PG&E can perform customer-funded design and engineering work, and in some cases procure long-lead equipment, before a formal interconnection agreement is executed. PG&E states the changes respond to a surge in requests from large-load customers whose projects require complex planning and may necessitate ordering equipment such as transformers years in advance to meet proposed operation dates. - Under the proposal, customers requesting these preliminary services must pay PG&E's actual costs through deposits that cover engineering, design, and procurement activities, with remaining funds either credited toward construction if the project proceeds or returned without interest if it does not. - The exhibits also set contractual conditions addressing cost responsibility, scheduling contingencies, liability limits, and procurement risks, including provisions that deposits used to secure long-lead materials may be non-refundable if a project is cancelled. PG&E argues the framework provides commercial clarity for developers while protecting existing ratepayers by ensuring that large projects—not the general customer base—bear the financial risks of early engineering work and equipment purchases undertaken prior to finalized interconnection agreements. **INSTANT ANALYSIS**: PG&E is creating a pathway to start design, engineering, and long-lead equipment procurement for large-load interconnections before a final agreement is signed, with customers funding the work through deposits. The move aims to accelerate timelines for mega-projects while shifting cancellation and cost risk away from ratepayers. The filing refers to these customers generically as "Large Load Customers" without specifying the underlying demand drivers, though the framework is consistent with pressures emerging from data centers and other high-demand facilities (an inference based on market context rather than anything PG&E states in the filing itself). --- ### ELECTRIC VEHICLE INFRASTRUCTURE SDG&E submitted Advice Letter 4805-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) requesting CPUC approval to modify the performance metrics used to judge “per se reasonableness” for its [Power Your Drive for Fleets](https://www.sdge.com/business/electric-vehicles/power-your-drive-for-fleets?ref=calregulatory.com) medium- and heavy-duty electric vehicle infrastructure program. - SDG&E argues that real-world conditions have slowed deployment and made the original targets unrealistic. These conditions include limited availability of heavy-duty EVs, high construction costs, customer unfamiliarity with electrification, supply-chain delays, and policy constraints including a statewide moratorium on new transportation electrification applications after 2026. - As of the end of 2025, the program had built **42 operational sites** supporting about **1,760 vehicles** and spent **$43.1 million** of its $154.8 million authorized budget, while encountering cost variability driven by grid upgrades, trenching, site design, and inflation. Notably, only **622 vehicles** are fully invoiced across 28 completed sites. - To reflect these constraints, SDG&E seeks to reduce the required deployment benchmarks from 300 make-ready installations to **75 completed sites** and from 3,000 electrified vehicles to **1,900 vehicles**, while maintaining other requirements such as spending in disadvantaged communities. SDG&E says these revisions would align performance evaluation with actual market conditions and the shortened program timeline, noting that without adjustments it cannot meet the original targets before the mandated sunset date. The filing also emphasizes ongoing cost-control practices, screening of projects for cost effectiveness, and the expectation that unspent funds will be returned to ratepayers. **INSTANT ANALYSIS:** SDG&E is resetting expectations for utility-led fleet electrification. By reducing deployment targets, it acknowledges that MDHD EV adoption is constrained by vehicle supply, customer readiness, construction costs, and the CPUC’s 2026 program sunset, not utility funding alone. For stakeholders, the message is that authorized budgets will not translate into full buildout under current conditions. The filing follows a path already walked by SCE and PG&E, who received similar metric relief via [Resolution E-5247](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K043/500043680.PDF?ref=calregulatory.com) in 2023, and is likely to further reinforce the precedent for utilities seeking relief as the CPUC shapes its next phase of transportation electrification policy. --- ### UTILITY FINANCES PG&E filed notice of an [ex parte communication](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K960/599960128.PDF?ref=calregulatory.com) in its [application for a limited capital structure adjustment](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M537/K130/537130683.PDF?ref=calregulatory.com). On February 13, PG&E met with CPUC **President Alice Reynolds**’ energy advisor and a utility costs and compliance supervisor. In the meeting, PG&E presented its request as a narrow, temporary measure intended to preserve access to capital and support future financing without increasing customer rates or altering its authorized revenue requirement. PG&E argued that denying the request could raise financing costs by at least **$60 million** annually, potentially affecting customers. Conversely, approval would address timing issues between current accounting charges and expected future cost recoveries or external funding, including wildfire claims and a Department of Water Resources forgivable loan. PG&E emphasized that similar relief has been granted previously and framed the adjustment as critical to funding incremental capital projects while maintaining financial stability. **INSTANT ANALYSIS:** PG&E is prioritizing balance-sheet flexibility ahead of looming capital demands tied to wildfire liabilities and infrastructure spending. By framing its request as rate-neutral and temporary, PG&E is attempting to lower the political temperature while securing financing headroom the Commission has historically allowed in constrained circumstances. The real stakes are forward-looking: approval would ease near-term capital access during a period of heavy investment requirements, while denial would raise financing costs that could surface in later rate cases. Ultimately this proceeding is a significant test of how much financial accommodation the CPUC is willing to extend to investor-owned utilities facing overlapping wildfire, grid hardening, and affordability pressures. --- ### PURPA SDG&E filed Advice Letter 4806-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)), which proposes revisions to its PURPA tariff to comply with CPUC [Resolution E-5425](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K021/594021941.pdf?ref=calregulatory.com), which clarified how utilities must compensate certain customer-generators who lose access to Net Energy Metering or Net Billing tariffs due to contractor violations of prevailing-wage requirements. (*See CRI's coverage of Resolution E-5425* [*here*](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/?ref=california-regulatory-intelligence-newsletter)*.*) [SDG&E Wildfire Costs + Provider of Last Resort FrameworkAn SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-39.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Jan-15-2026--11-.png)](https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/?ref=california-regulatory-intelligence-newsletter) The filing responds to an earlier rejection by Energy Division, which found SDG&E's prior proposal inconsistent with CPUC directives because the 20 MW cap SDG&E had proposed contradicted a 2023 decision ([D.23-11-068](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K977/520977266.PDF?ref=calregulatory.com)), which required the tariff apply to all facilities eligible under pertinent provisions of the Public Utilities Code without a size limit. Resolution E-5425 subsequently authorized the 20 MW cap, resolving the conflict and enabling this compliance filing. Under the revised tariff, affected renewable generators would be compensated at avoided-cost rates based on CAISO day-ahead prices, and eligibility would be limited to facilities up to 20 MW, consistent with the resolution's findings. The tariff: - Applies automatically to customers whose projects are disqualified from NEM/NBT programs due to willful wage violations; - Provides either **30-day notice** (for single generating accounts without aggregated accounts) or **60-day notice** (for accounts with benefitting or aggregated accounts) before transition; and - Allows customers to return to their prior tariff if the violation finding is overturned. **INSTANT ANALYSIS:** This is a narrow but consequential compliance filing with real project-finance implications. SDG&E is implementing Resolution E-5425 by establishing a fallback PURPA pathway for projects disqualified from NEM/NBT due to prevailing-wage violations, capping eligibility at 20 MW and tying export compensation to avoided-cost pricing. The result converts labor-compliance risk into tariff risk: projects that fail wage rules lose retail-rate economics and fall to wholesale-style compensation. ### February 26, 2026 CPUC Voting Meeting Preview: IRP 6,000 MW Order; Closure on Winter Gas Price Investigation URL: https://www.calregulatory.com/february-26-2026-cpuc-voting-meeting-preview-irp-6-000-mw-order-closure-on-winter-gas-price-investigation/ Last updated: 2026-02-26T17:32:52.000Z The CPUC's [**February 26** voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M599/K309/599309283.pdf?ref=calregulatory.com) is set to include significant decisions in the Integrated Resource Planning docket and the Natural Gas Price Spike investigation. - A proposed decision in the IRP orders **2,000 MW** of Net Qualifying Capacity by 2030, and an additional **4,000 MW** by 2032,with no more than half of each tranche met by storage. - A PD in the Price Spike investigation treats the winter 2022–2023 gas price spike as a system-level stress event rather than a failure of utility conduct. The remainder of the agenda includes actions related to the Electric Program Investment Charge (EPIC), PG&E's [Vehicle-to-Everything](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com) Microgrid Pilot at the [Redwood Coast Airport Microgrid](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com), and two SDG&E mid-term reliability contracts resulting from the company's Tranche 3 solicitation, authorizing **92 MW** of standalone battery storage projects. --- ### INTEGRATED RESOURCE PLANNING A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083681.PDF?ref=calregulatory.com) requires California load-serving entities to procure additional clean reliability resources to address forecasted system needs in the 2029–2032 period. The PD orders **2,000 MW** of NQC online by **June 1, 2030**, and an additional **4,000 MW** by **June 1, 2032**, with no more than half of each tranche met by storage. The PD also transmits updated base and sensitivity portfolios to the CAISO for use in its 2026–2027 Transmission Planning Process. The procurement finding is based on updated [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) load forecasts, reliability modeling using [SERVM](https://power-gem.co/software/servm-resource-adequacy-planning/?ref=calregulatory.com), and the risk of delayed long-lead-time resources. Eligible resources must follow the Mid-Term Reliability framework and be new, non-GHG-emitting and/or [RPS](https://www.energy.ca.gov/programs-and-topics/programs/renewables-portfolio-standard?ref=calregulatory.com)\-eligible, with limited credit for repowering only to the extent of incremental capacity added. The PD does not impose a separate energy-procurement mandate, relying instead on [ELCC](https://blog.ucs.org/mark-specht/elcc-explained-the-critical-renewable-energy-concept-youve-never-heard-of/?ref=calregulatory.com)\-based capacity requirements and existing RPS and Resource Adequacy programs. - An [accompanying attachment](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K201/595201050.PDF?ref=calregulatory.com) allocates the 6,000 MW NQC obligation across investor-owned utilities, Community Choice Aggregators, and aggregated Electric Service Providers based on adjusted 2026 load shares (see table below). - The largest shares fall on PG&E and SCE bundled service, followed by major CCAs such as Clean Power Alliance, East Bay Community Energy, and San Diego Community Power. ESP obligations are shown only in aggregate and will be conveyed confidentially to individual providers within two weeks of the decision's adoption. R.25-06-019 · Proposed Decision · Attachment A ## Procurement Obligations by Load Serving Entity Net Qualifying Capacity targets for 2030 and 2032 compliance years 6,000 Total MW NQC 31 LSEs 177K GWh 2026 Load | Load Serving Entity | Type | 2026 Load (GWh) | Adj. Share | 2030 MW NQC | 2032 MW NQC | Total MW NQC | | ------------------------------------------- | ---- | --------------- | ---------- | ----------- | ----------- | ------------ | | Pacific Gas and Electric (bundled) | IOU | 5,144 | 17.3% | 347 | 694 | 1,041 | | PG&E Direct Access (aggregated)\* | ESP | 11,393 | 4.1% | 82 | 164 | 245 | | Clean Power San Francisco | CCA | 3,394 | 1.7% | 34 | 68 | 103 | | East Bay Community Energy | CCA | 9,432 | 4.7% | 95 | 190 | 285 | | King City Community Power | CCA | 36 | 0.0% | 0.4 | 1 | 1 | | Marin Clean Energy | CCA | 5,966 | 3.0% | 60 | 120 | 180 | | Central Coast Community Energy | CCA | 5,791 | 2.9% | 58 | 117 | 175 | | Peninsula Clean Energy Authority | CCA | 3,831 | 1.9% | 39 | 77 | 116 | | Pioneer Community Energy | CCA | 1,793 | 0.9% | 18 | 36 | 54 | | Redwood Coast Energy Authority | CCA | 634 | 0.3% | 6 | 13 | 19 | | San Jose Clean Energy | CCA | 4,543 | 2.3% | 46 | 91 | 137 | | Silicon Valley Clean Energy | CCA | 4,132 | 2.1% | 42 | 83 | 125 | | Sonoma Clean Power Authority | CCA | 2,236 | 1.1% | 23 | 45 | 68 | | Valley Clean Energy Alliance | CCA | 724 | 0.4% | 7 | 15 | 22 | | Southern California Edison (bundled) | IOU | 51,858 | 35.8% | 716 | 1,431 | 2,147 | | SCE Direct Access (aggregated)\* | ESP | 12,003 | 4.3% | 86 | 172 | 259 | | Apple Valley Choice Energy | CCA | 250 | 0.1% | 3 | 5 | 8 | | City of Pomona | CCA | 431 | 0.2% | 4 | 9 | 13 | | Clean Power Alliance of Southern California | CCA | 11,166 | 5.6% | 112 | 225 | 337 | | Desert Community Energy | CCA | 369 | 0.2% | 4 | 7 | 11 | | Lancaster Clean Energy | CCA | 618 | 0.3% | 6 | 12 | 19 | | Orange County Power Authority | CCA | 2,275 | 1.1% | 23 | 46 | 69 | | Energy for Palmdale's Independent Choice | CCA | 497 | 0.3% | 5 | 10 | 15 | | Pico Rivera Innovative Municipal Energy | CCA | 218 | 0.1% | 2 | 4 | 7 | | Rancho Mirage Energy Authority | CCA | 286 | 0.1% | 3 | 6 | 9 | | San Jacinto Power | CCA | 172 | 0.1% | 2 | 3 | 5 | | Santa Barbara Clean Energy | CCA | 347 | 0.2% | 3 | 7 | 10 | | San Diego Gas & Electric (bundled) | IOU | 2,658 | 1.8% | 37 | 73 | 110 | | SDG&E Direct Access (aggregated)\* | ESP | 3,942 | 1.4% | 28 | 57 | 85 | | Clean Energy Alliance | CCA | 2,492 | 1.3% | 25 | 50 | 75 | | San Diego Community Power | CCA | 8,340 | 4.2% | 84 | 168 | 252 | | Total — All LSEs | | 176,972 | 100% | 2,000 | 4,000 | 6,000 | KEY IOU Investor-Owned Utility CCA Community Choice Aggregator ESP Electric Service Provider **\*ESP Note:** Procurement obligations for electric service providers are presented in aggregate. Individual ESP obligations remain confidential and will be conveyed to each ESP within two weeks of adoption. **INSTANT ANALYSIS:** On resource eligibility, the PD excludes fossil resources, limits repowering to incremental capacity only, and permits energy-only resources solely when co-located with fully deliverable storage. The 50% storage cap is the central policy choice: it constrains over-reliance on storage and indirectly drives additional energy procurement without reopening the Renewables Portfolio Standard or imposing a separate energy mandate. Why the PD matters for CRI readers: it establishes the next reliability obligation after Mid-Term Reliability, shapes procurement behavior through 2032, and feeds directly into the CAISO's transmission approvals with cost-recovery implications. The PD also creates a narrow window for projects to secure remaining federal incentives, increasing near-term procurement pressure even asthe [Reliable and Clean Power Procurement Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/the-reliable-and-clean-power-procurement-program?ref=calregulatory.com) remains under development. --- ### NATURAL GAS PRICE SPIKE INVESTIGATION A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K227/595227206.PDF?ref=calregulatory.com) in [I.23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) finds that the winter 2022–2023 natural gas price spike resulted from a convergence of adverse market conditions, not misconduct by regulated utilities or storage providers. The PD concludes that sustained cold and high precipitation significantly increased gas demand, while interstate pipeline outages and maintenance (particularly on the El Paso system) restricted supply into California at critical moments. These constraints were compounded by reduced inflows from Western Canada, the Rockies, and the Permian Basin, low regional storage inventories, and bid-week pricing that captured peak spot prices during [Winter Storm Elliott.](https://en.wikipedia.org/wiki/December%5F2022%5FNorth%5FAmerican%5Fblizzard?ref=calregulatory.com) After reviewing extensive record evidence, the PD finds no improper or imprudent conduct by PG&E, SoCalGas, SDG&E, their core procurement departments, or independent storage providers. The PD emphasizes application of the Prudent Manager Standard, rejecting hindsight-based critiques of procurement, contracting, or storage decisions. It also finds no evidence of prohibited affiliate transactions, intentional withholding of supply, or manipulation of storage withdrawals. Rather than attempting to regulate gas commodity prices, the PD adopts a bill-shock mitigation and transparency framework for future events. It defines a "gas price spike event" as a 150% increase in the monthly core procurement charge relative to the 10-year monthly average for that month during the winter season (November–March), which would trigger a temporary cap on core procurement charges and amortization of any resulting undercollection over nine months. Under this framework, utilities would also be required to provide earlier, clearer customer notifications and information about assistance options. The PD further orders reforms to PG&E’s Core Procurement Incentive Mechanism and SoCalGas’s Gas Cost Incentive Mechanism. Any shareholder rewards would require approval through an application rather than an advice letter, and utilities must document procurement performance and risk management more clearly. In addition, the PD directs utilities to incorporate the specific constraints observed in 2022–2023 into future procurement and hedging strategies, to expand public reporting of storage inventories, and to improve transparency for both core and noncore customers. **INSTANT ANALYSIS:** The PD treats the 2022–2023 gas price spike as a system-level stress event rather than a failure of utility conduct, concluding that extreme weather, pipeline outages, reduced regional inflows, low storage inventories, and bid-week timing combined to overwhelm California’s gas supply chain. Applying the Prudent Manager Standard, the PD clears PG&E, SoCalGas, SDG&E, their core procurement departments, and independent storage providers of wrongdoing, rejecting hindsight critiques of contracting, storage use, or affiliate activity. Rather than pursuing commodity price intervention, the PD pivots toward future bill-shock mitigation by defining a "gas price spike event" as a 150% increase relative to the ten-year monthly average for that month during the winter season (November–March), triggering a temporary cap on core procurement charges, nine-month amortization of undercollections, and enhanced customer notice requirements. The cap and notice obligations apply to PG&E, SoCalGas, SDG&E, and Southwest Gas Corporation. The PD also tightens oversight of procurement incentive mechanisms by requiring formal applications for any shareholder rewards and expands transparency through standardized monthly storage inventory reporting. --- ### ELECTRIC PROGRAM INVESTMENT CHARGE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495688.PDF?ref=calregulatory.com) in R.19-10-005 establishes the framework for the EPIC Program's next investment cycle. The PD adopts 13 measurable Strategic Objectives to guide EPIC 5 investments from 2026 through 2030, authorizes PG&E, SCE, and SDG&E to continue as administrators, and sets total annual funding at **$185 million** ($147.26 million to the California Energy Commission, the remainder split among the three IOUs). The PD refines intellectual property rules, allowing open-source waivers and adopting the CEC's declaration-at-outset practice for pre-existing intellectual property, while denying SCE's broader request to exempt enhancements to pre-existing IP from flow-down requirements. The PD also denies waivers of state march-in and direct licensing rights for projects involving federal entities. A more comprehensive program evaluation is ordered for 2028, and the EPIC 5 investment plan application deadline is extended to **June 26, 2026**. **INSTANT ANALYSIS:** This PD narrows EPIC's focus rather than expanding it. The 13 Strategic Objectives shift accountability from spend to outcomes, and retaining the IOUs as administrators is a conditional extension; real leverage moves to those objectives and the 2028 evaluation. SCE's pre-existing IP exemption request is denied outright. EPIC 5 is positioned as an implementation vehicle for affordability, electrification, and resilience; whether the new objectives are used to shape or reject project proposals will be the test. --- ### PG&E/ELECTRIC VEHICLES [Draft Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K288/596288531.PDF?ref=calregulatory.com) approves (with modifications) PG&E’s requests to extend and restructure Pilot #3 of its [Vehicle-to-Everything](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com) (V2X) Microgrid Pilot at the [Redwood Coast Airport Microgrid](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com). The draft resolution grants PG&E additional time to complete Phase I testing and data collection, extending the deadline to **June 30, 2026**, after documented delays tied to Federal Aviation Administration funding, vendor instability, firmware issues, and charger damage during testing. While Energy Division acknowledges meaningful technical progress in Phase I (particularly the validation of frequency-based controls for bidirectional EV charging), it explicitly notes that the original success metric of demonstrating five to 10 bidirectional EVs has not yet been fulfilled, given that only two vehicles are currently participating. The draft resolution directs PG&E to explain how it intends to close that gap. For Phase II, the draft resolution approves PG&E’s proposal to abandon the original customer-enrollment and incentive structure and instead adopt a Hybrid Support Model, under which PG&E will close enrollment, return approximately **$750,000** in unspent incentive funds to ratepayers, and provide V2X technical consulting to Microgrid Incentive Program projects using non-pilot resources. Energy Division concludes that this approach reasonably adapts the pilot to current market and technology constraints while preserving lessons learned and protecting ratepayers from further costs. The earliest the Commission will consider this item is **February 26**. **INSTANT ANALYSIS**: This draft resolution marks a retreat from scale rather than a failure of the underlying technology. It allows PG&E to complete Phase I because the operational data remains valuable, but it refuses to extend a customer-facing incentive program that lacked viable sites, equipment, and timelines. By approving a pivot to a hybrid support model and requiring unused funds to be returned to ratepayers, the draft resolution reinforces a clear principle: experimental pilots must either produce usable evidence or wind down cleanly. For stakeholders, the message is that V2X and community microgrids remain conceptually supported, but the CPUC is no longer willing to finance prolonged demonstrations ahead of real-world readiness.[](https://www.calregulatory.com/proposed-decision-lands-in-cpucs-natural-gas-price-spike-investigation/) --- ### SDG&E ENERGY STORAGE [Draft Resolution E-5446](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K980/595980485.PDF?ref=calregulatory.com) approves two SDG&E mid-term reliability contracts resulting from the company's Tranche 3 solicitation, authorizing a combined **92 MW** of standalone battery energy storage projects expected to come online **June 1, 2027**. The draft resolution approves a 44 MW four-hour battery and a 48 MW eight-hour battery, both under 15-year tolling agreements with Golden Fields Solar VI, LLC (a [Clearway](https://www.clearwayenergygroup.com/?ref=calregulatory.com) project), procured to help SDG&E meet its mid-term reliability obligations under prior Integrated Resource Planning decisions. Energy Division found the contracts were supported by a competitive least-cost/best-fit solicitation process overseen by an independent evaluator, and reasonable despite price adjustments driven by evolving supply-chain and tariff conditions. Contract costs remain confidential, but the draft resolution approves SDG&E’s proposed cost recovery through the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com), allocating the eight-hour battery costs to the 2021 vintage and the four-hour battery costs to the 2023 vintage, with charges borne by bundled and departing-load customers as applicable. **INSTANT ANALYSIS:** This draft resolution continues the CPUC’s steady build-out of mid-term reliability resources through utility-contracted storage rather than new generation, with SDG&E adding 92 MW of standalone battery capacity timed for a June 2027 online date. While contract pricing remains confidential, the draft resolution locks in long-duration (8-hour) and shorter-duration (4-hour) storage as compliance tools under the IRP-driven mid-term reliability framework, reinforcing storage's role as a reliability resource under California's capacity planning framework rather than a bridge to new gas. The PCIA vintage split is notable: costs are explicitly assigned to 2021 and 2023 vintages, ensuring that departing load customers share in the cost responsibility and limiting future cost-shift disputes. More broadly, the approval suggests continued regulatory comfort with negotiated price adjustments in response to tariff and supply-chain volatility, provided utilities can demonstrate least-cost/best-fit outcomes under independent evaluator review. --- ### DISTRIBUTED GENERATION [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com) increases funding for the California Distributed Generation Statistics platform to **$2.6 million** per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion. The draft resolution directs PG&E, SCE, and SDG&E to improve data quality by revising their online interconnection application interfaces, including standardized equipment drop-downs, stronger cost validation, corrected system size calculations, and retroactive fixes to existing data. The item also orders a rebranding of [DGStats](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) to reflect the inclusion of non-distributed-generation programs and authorizes publication of anonymized Contractors State License Board disclosure document data. Finally, the IOUs must host a public workshop and improve tracking and reporting of system decommissioning to address growing accuracy gaps as legacy systems retire. **INSTANT ANALYSIS:** This draft resolution upgrades DGStats into useful regulatory infrastructure by nearly tripling funding, allowing inflation adjustments, and positioning the platform as a long-term backbone for forecasting, planning, and enforcement. The draft resolution targets data quality failures directly, mandating automated sizing, validated equipment lists, retroactive corrections, standardized cost inputs, and structured decommissioning tracking (changes that will alter historical and forward-looking Distributed Energy Resource analyses). Publishing anonymized CSLB disclosure data and rebranding the platform expands DGStats from a reporting site into a transparency and compliance tool with real market discipline effects. --- ### SELF-GENERATION INCENTIVE PROGRAM A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495666.PDF?ref=calregulatory.com) denies [Bloom Energy Corp.](https://www.bloomenergy.com/?utm%5Fterm=bloom%20energy%20corp&utm%5Fcampaign=be%5Fgg%5Fppc%5Fbr%5Fbrand-core&utm%5Fsource=google&utm%5Fmedium=cpc&hsa%5Facc=9429233231&hsa%5Fcam=22688023156&hsa%5Fgrp=179839685886&hsa%5Fad=758760772746&hsa%5Fsrc=g&hsa%5Ftgt=kwd-352728153804&hsa%5Fkw=bloom%20energy%20corp&hsa%5Fmt=e&hsa%5Fnet=adwords&hsa%5Fver=3&gad%5Fsource=1&gad%5Fcampaignid=22688023156&gbraid=0AAAAAC2AeZbfxgy-dhd8u0CTXHy70CvNy&gclid=CjwKCAiAssfLBhBDEiwAcLpwfjJuZ3uEptparFJitFG35irRH6YLfKhrKUG53p3Z2DByDKD23lTpcRoCA8cQAvD%5FBwE)'s [petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M539/K203/539203565.PDF?ref=calregulatory.com) to modify a 2011 decision ([D.11-09-015](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/143459.PDF?ref=calregulatory.com)) governing the Self-Generation Incentive Program, finding the request procedurally deficient. Bloom sought to raise the program's 25% cap on annual electricity exports from incentivized systems to 50%, arguing that advances in fuel-cell technology now make greater grid exports commercially viable. SoCalGas, [filing jointly](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493284.PDF?ref=calregulatory.com) with the [Center for Sustainable Energy](https://energycenter.org/?ref=calregulatory.com), supported the petition on broader grounds, contending that SGIP's post-2011 policy evolution toward renewable gas constituted independent justification for revisiting the cap. The [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) [also supported the petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493283.PDF?ref=calregulatory.com). Cal Advocates [opposed it](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K867/542867049.PDF?ref=calregulatory.com), maintaining that SGIP exists to promote on-site self-generation, not grid exports. The PD rejects all justifications for the petition's timing, finding that technological progress and policy evolution over time are insufficient grounds for late-filed petitions. **INSTANT ANALYSIS**: This is a procedural denial, not a policy judgment, but the practical effect is the same: the 25% export cap stays intact and SGIP's behind-the-meter focus is preserved. The PD demonstrates clearly that legacy program rules will not be reopened through petitions tied to technology, and any expansion of export flexibility requires a new rulemaking or legislation. Going forward, SoCalGas will need a different procedural vehicle to advance export flexibility goals for its gas-adjacent distributed resource strategy. Developers and distributed resource players should treat the constraint as durable absent a future-focused policy proceeding. ### Newsom Installs John Reynolds as CPUC President, Framing Affordability and Wildfire Spending Oversight as Top Priorities URL: https://www.calregulatory.com/newsom-installs-john-reynolds-as-cpuc-president-framing-affordability-and-wildfire-spending-oversight-as-top-priorities/ Last updated: 2026-02-19T06:39:30.000Z Governor **Gavin Newsom** [announced](https://www.gov.ca.gov/2026/02/18/governor-newsom-names-new-california-public-utilities-commission-president-to-launch-new-phase-in-effort-to-protect-consumers-from-escalating-utility-costs/?ref=calregulatory.com) the designation of current CPUC Commissioner [**John Reynolds**](https://www.cpuc.ca.gov/about-cpuc/commissioners/page-content/profile-list/commissioner-john-reynolds?ref=calregulatory.com)as the next President of the agency, succeeding [**Alice Reynolds**](https://www.cpuc.ca.gov/about-cpuc/commissioners/page-content/profile-list/president-alice-reynolds?ref=calregulatory.com), who will step down later this month and join the California Independent System Operator’s Governing Board. John Reynolds' designation requires Senate confirmation. He has served as Commissioner since 2022 and held multiple staff roles at the agency from 2013–2018. Newsom also appointed [**Christine Harada**](https://www.linkedin.com/in/christine-j-harada/?ref=calregulatory.com) as a new CPUC Commissioner and highlighted the recent selection of [**Leuwam Tesfai** as Executive Director](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-announces-leuwam-tesfai-as-executive-director?ref=calregulatory.com), framing the leadership changes as part of an affordability and reliability agenda focused on: - Lowering utility bills; - Strengthening wildfire safety investments; - Modernizing the grid; and - Advancing the state’s goal of 100% clean electricity by 2045\. The administration emphasized continued oversight of utility spending, rate reforms, and major investments in grid hardening and storage, alongside a new law providing up to **$60 billion** in electricity bill refunds through 2045\. ### **INSTANT ANALYSIS** This leadership transition places a Newsom-aligned insider atop the CPUC at a moment when affordability pressure is colliding with aggressive clean-energy procurement and wildfire spending. Expect continuity rather than disruption: stronger scrutiny of utility capital plans, heightened focus on rate impacts, and sustained emphasis on grid hardening, storage deployment, and liability mitigation. For regulated utilities and load-serving entities, the practical effect is a Commission likely to press harder on cost justification and performance metrics while still advancing reliability and decarbonization mandates. Alice Reynolds’ move to the CAISO Governing Board brings closer policy alignment between the CPUC and the grid operator, which could smooth coordination on procurement, transmission planning, and reliability rules but may also concentrate influence within the Governor’s energy apparatus. Christine Harada’s appointment adds federal permitting experience, suggesting attention to infrastructure delivery. CRI readers should anticipate an affordability-framed regulatory phase of the Commission with assertive oversight of wildfire and grid investments, not a retreat from the state’s long-term clean-energy buildout. ### WEDNESDAY AGGREGATE: Wildfire Financing, Gas Backbone Upgrades, IRP Procurement Pressure URL: https://www.calregulatory.com/wednesday-aggregate-12/ Last updated: 2026-02-19T16:20:03.000Z Today's roundup spans wildfire securitization, compressor station upgrades, customer billing infrastructure, IRP ex parte communications, and Resource Adequacy scheduling. - **Woolsey Fire**: in SCE's financing order application, Cal Advocates makes the opening challenge in what might be a hard-fought securitization battle. - **PG&E and the Hinkley Compressor Station Upgrade**: PG&E's CPCN withdrawal and emergency exemption move is procedural arbitrage: move fast now, and litigate cost recovery in a General Rate Case. - **SoCalGas Customer Billing System**: This is a cost-overrun battle, but a settlement with the Small Business Utility Advocates is a significant development. - **Integrated Resource Planning**: A pending PD is fluid and both CalCCA and Cal Advocates are pushing against its perceived rigidity. --- ### WOOLSEY FIRE Cal Advocates filed [a protest](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K152/599152765.PDF?ref=calregulatory.com) opposing [SCE's application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com) for a financing order to securitize approximately **$1.951 billion** in approved costs from the 2018 Woolsey Fire through recovery bonds repaid by ratepayers. [IRP Cycle 2024-2026 Changes; Woolsey Fire Financing OrderCovers: IRP; Woolsey Fire; Aliso Canyon; 2026 ERRA Forecasts of PG&E and SCE![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-37.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/photo-1688040637388-d2c0aa7b9907-5)](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/?ref=california-regulatory-intelligence-newsletter) While the underlying wildfire costs were previously authorized in [a December 2025 settlement decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894945.pdf?ref=calregulatory.com), Cal Advocates argues the CPUC must closely scrutinize whether issuing bonds (and imposing long-term fixed charges on customers) is truly just, reasonable, and in the public interest compared with traditional cost recovery. The protest raises concerns about bond terms, duration, cumulative ratepayer impacts from prior securitizations, allocation of charges, financing costs, and whether the proposal actually reduces customer rates on a present-value basis. **INSTANT ANALYSIS:** Cal Advocates' protest is the opening move in what will be a hard-fought securitization proceeding, not a rubber stamp. Cal Advocates is skeptical that recovery bonds automatically benefit ratepayers, especially given the growing stack of prior wildfire securitizations already embedded in bills. Expect heavy litigation over bond duration, interest costs, and cumulative bill impacts, areas where intervenors can reshape outcomes even after the underlying wildfire costs were approved. If the Commission strengthens ratepayer protections or shortens bond maturities, the near-term rate profile could rise even if lifetime costs fall, affecting procurement assumptions and affordability narratives. This case also functions as a precedent test for how aggressively the CPUC will police post-[Senate Bill 901](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb901?ref=calregulatory.com) wildfire securitization tools going forward. --- ### PG&E WILDFIRE & GAS SAFETY PG&E recently [filed a motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K053/597053746.PDF?ref=calregulatory.com) in its Wildfire and Gas Safety cost-recovery proceeding ([A.23-06-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M511/K547/511547762.PDF?ref=calregulatory.com)) to reopen the evidentiary record so it can introduce updated revenue requirements for 2023–2030 tied to capital costs already under review from 2020–2022 safety work. PG&E argues that subsequent procedural developments (specifically the exclusion of these costs from both its 2023 and pending 2027 General Rate Cases pending reasonableness review) have stranded the associated revenue requirement until at least 2031, which would cause ratepayers to bear substantial additional interest expense. PG&E therefore proposes admitting updated figures now and implementing final amounts later through a ministerial advice-letter process after the Commission rules on the underlying costs. PG&E frames this as a narrow, efficiency-oriented fix supported by some parties, estimating that earlier recovery could avoid **$52.2 million** in interest costs while not prejudicing intervenors because the ultimate revenue requirement would still depend on whatever costs the CPUC ultimately approves. PG&E estimates total interest exposure reaches approximately **$174.1 million** if cost recovery is delayed to 2028\. PG&E also cites a recent SDG&E precedent ([D.26-01-021](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K291/596291467.PDF?ref=calregulatory.com)) in which the CPUC rejected the same Cal Advocates argument (that later-period revenue requirements require a separate proceeding) finding such a proceeding "unnecessary" when the underlying capital costs had already been reviewed. - In [a response dated February 17](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K155/599155081.PDF?ref=calregulatory.com), Cal Advocates opposes the motion, arguing that reopening the record to consider 2023–2030 revenue requirements would exceed the defined scope of the proceeding, which is limited to reviewing the reasonableness of specific wildfire-mitigation and safety expenditures incurred mainly in 2020–2022\. - Cal Advocates contends PG&E is attempting to introduce a new issue long after the record closed, without adequate justification for why the evidence was not presented earlier, and warns that doing so could violate procedural rules, prejudice other parties, and potentially saddle ratepayers with interest costs stemming from PG&E’s own delay rather than from Commission action. Consequently, it urges denial of the motion and suggests any future recovery for later years should be pursued in a separate application with full discovery and hearings. **INSTANT ANALYSIS**: PG&E is trying to prevent a ratemaking gap: safety capital already under review cannot enter rates until reasonableness is decided, but the GRC timeline would otherwise delay recovery for years, adding large interest costs. PG&E wants the Commission to treat the 2023–2030 revenue requirement as a mechanical update handled by advice letter rather than a new case. The SDG&E precedent is PG&E's strongest card (the Commission has already rejected this precise Cal Advocates argument once). Cal Advocates argues this would improperly expand the proceeding’s scope and necessitates a separate application, which would push recovery further out and test whether those added carrying costs are recoverable. An eventual decision on this subject could shape how future safety spending converts into rates when regulatory timelines fall out of sync. --- ### PG&E COMPRESSOR STATION UPGRADES In a [February 17 filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K154/599154473.PDF?ref=calregulatory.com), TURN addresses PG&E's [recent motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K051/597051566.PDF?ref=calregulatory.com) to withdraw its application for approval of electrical upgrades at the Hinkley Compressor Station. TURN argues that PG&E has not provided enough factual detail to justify using an emergency exemption to proceed without prior CPUC review. [PG&E Looks to Bypass CPCN Review for Hinkley ProjectTopics covered: PG&E’s S-238 Hinkley Compressor Station Electrical Upgrades Project; PG&E’s Billing Modernization Initiative![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-38.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Jan-28-2026--10--1.png)](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/) TURN also questions the project's scope, cost estimates, and underlying need, noting evidence that compressor capacity and related electrical work could potentially be reduced as gas demand declines and storage plays a larger role. If the CPUC allows the withdrawal, TURN urges it to require strict conditions, including a full reasonableness review of project costs in the next General Rate Case, to prevent the expenditures from being added to rate base without scrutiny. TURN's particular concern is that costs incurred in 2025-2026 predate the next rate case base year and could be buried within a single budget line item covering both Hinkley and Topock stations, escaping meaningful review absent explicit CPUC direction. **INSTANT ANALYSIS:** PG&E’s move to withdraw the CPCN application and proceed under an emergency exemption is a procedural end-run that shifts the battle from upfront need review to back-end cost recovery, where scrutiny is weaker and delayed. The true risk is not the project itself but the possibility that tens of millions in capital spending enter rate base years later with minimal interrogation, especially if intervenors lack a clean evidentiary record. - And the gap is stark: the 2023 GRC authorized approximately **$25 million** combined for electrical upgrade work at both Hinkley and Topock compressor stations, against a **$93 million** estimate for Hinkley alone (with no Hinkley-specific costs included in the 2027 GRC forecast). - TURN’s filing reframes the dispute around capacity planning: if compressor capacity can decline as storage substitutes for peak demand, then the electrical upgrade may be oversized relative to future system needs. For gas utilities and large customers, the key implication is precedent: approval could normalize bypassing CPCN review for aging backbone assets by invoking reliability concerns, accelerating capital deployment ahead of formal policy direction on gas system contraction. --- ### CUSTOMER INFORMATION INFRASTRUCTURE SoCalGas's [opening brief](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K152/599152756.PDF?ref=calregulatory.com) in [A.25-05-004](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K498/565498664.PDF?ref=calregulatory.com) asks the CPUC to approve **$21 million** in incremental funding to complete its Customer Information System (CIS) Replacement Project. The $21 million figure reflects [a settlement SoCalGas reached with the Small Business Utility Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056577.PDF?ref=calregulatory.com), down from the original **$24.9 million** application request. This project is a major modernization effort to replace a roughly 30-year-old legacy billing and customer-service platform built on technology that will be over 40 years old at the time of implementation, underpinning core operations for 5.9 million accounts. SoCalGas argues the previously authorized funding from its Test Year 2024 General Rate Case will be exhausted by **September 2026** (before project completion in 2027), putting implementation, employee training, transition staffing, and retirement of legacy systems at risk without additional funds. SoCalGas says the upgrade is necessary to address obsolete technology, maintain reliable billing and customer service functions, and meet evolving regulatory and business requirements. It claims the rate impact would be modest (about $0.31 per month for a typical residential customer). It also seeks approval of a two-way balancing account to reconcile forecast versus actual costs. Cal Advocatesdisputes the need for additional funding, but SoCalGas maintains its forecasts, contracts, and expenditures demonstrate a genuine shortfall and that completing the project will benefit customers through improved functionality, scalability, and long-term operational reliability. **INSTANT ANALYSIS:** This is a cost-overrun recovery battle. Because the CIS system supports billing and customer operations, the CPUC faces risk in denying funds if project completion or service reliability are jeopardized. The Small Business Utility Advocates settlement is a significant development (having a ratepayer advocate aligned with SoCalGas gives the CPUC political cover for full approval of the $21 million). That said, approval would still demonstrate tolerance for reopening General Rate Case funding mid-cycle for large tech projects, and the Commission may attach conditions regardless of the settlement. --- ### INTEGRATED RESOURCE PLANNING CalCCA provided notice of multiple recent ex parte meetings with CPUC commissioners and staff in the Integrated Resource Planning docket ([R.25-06-019](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K276/571276511.PDF?ref=calregulatory.com)). In its meetings, CalCCA pressed for significant revisions to the proposed decision on 2029–2032 procurement and transmission planning portfolios, arguing the order as drafted could impose unnecessary costs and constrain load-serving entities’ ability to procure resources efficiently. [Proposed Decision Allocates 6 GW Across California LSEsAdministrative Law Judge Fitch issued a PD that requires LSEs to procure additional clean reliability resources![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-36.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/photo-1554735231-7cf7be4c7126)](https://www.calregulatory.com/new-cpuc-irp-proposed-decision-allocates-6-gw-across-california-load-serving-entities/) CalCCA’s meetings focused on three core concerns: - A requirement to procure resources for 2032 without a commitment to reassess need using updated load forecasts - A **50%** cap on the share of procurement that can be met with storage resources, which CalCCA argued is unsupported by [RESOLVE modeling](https://www.ethree.com/tools/resolve/?ref=calregulatory.com) and could inflate costs in a seller’s market - The absence of flexible compliance pathways that would allow load-serving entities to meet obligations cost-effectively CalCCA recommended that the CPUC commit to reassessing 2032 needs closer to the delivery year and remove (or revise) the storage cap. It also urged the Commission to expand compliance options by extending the “good faith efforts” standard, permitting obligation trading, and carrying forward flexibility granted in prior procurement orders. CalCCA expressed support for several elements of the proposed decision, including counting excess procurement, refraining from adopting a local procurement requirement, counting energy-only co-located resources paired with deliverable resources, and maintaining decentralized LSE procurement. --- Separately, Cal Advocates [disclosed a series of February 12 ex parte meetings](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K155/599155086.PDF?ref=calregulatory.com) with advisors to multiple commissioners regarding the same proposed decision. Cal Advocates similarly sought modifications but emphasized ratepayer protections and least-cost procurement outcomes. It urged the Commission to clarify that the 50% storage cap applies only to standalone storage resources, warning that applying it broadly would force unnecessary generation procurement at higher cost. Cal Advocates also recommended allowing load-serving entities to use the compliance flexibility mechanism from a 2025 decision ([D.25-09-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K576/581576925.PDF?ref=calregulatory.com)) to manage project delays. Finally, it asked the Commission to reserve transmission capacity for the full **7,036 MW** of modeled 2036 out-of-state wind resources (not just the **6,096 MW** proposed in the PD) to prevent lower-value projects from crowding out higher-value resources supported by IRP modeling. **INSTANT ANALYSIS**: Major stakeholders in the IRP docket are converging on a common theme: the current PD's procurement order is too rigid relative to uncertainty in load forecasts, project execution risk, and resource availability. CalCCA’s pushback centers on affordability and procurement feasibility, while Cal Advocates focuses on avoiding over-procurement and protecting ratepayers from inefficient resource choices. The 2029–2032 procurement trajectory remains fluid ahead of the February 26 voting meeting, where it is scheduled for consideration on the Regular Agenda. Late revisions could modify procurement volumes, technology mix, compliance flexibility, and transmission allocations, with downstream implications for RA strategy, storage deployment, and long-term gas demand planning. --- ### RESOURCE ADEQUACY A new [ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056589.PDF?ref=calregulatory.com) in the CPUC's Resource Adequacy rulemaking ([R.25-10-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K934/583934825.PDF?ref=calregulatory.com)) modifies the Track 1 schedule after delays in the Energy Division’s report on “transactability issues.” The report, originally due **February 6**, was not completed on time due to unforeseen preparation issues and is now expected around **February 23**. As a result, all Track 1 deadlines specifically tied to transactability issues (such as proposals, workshops, and comments on those issues) are suspended pending a future ruling that will reset those dates once the report is released. Other Track 1 milestones (including workshops on broader proposals and comments due **March 6** and **March 20**) remain unchanged. The ruling emphasizes that transactability reforms will still be addressed in Track 1 despite the delay, and a subsequent ruling will establish a revised schedule to ensure parties have adequate time to review and respond to the forthcoming report. **INSTANT ANALYSIS**: The ruling delays only the transactability portion of the Resource Adequacy proceeding, indicating that reforms affecting the usability and liquidity of RA contracts are slipping while other Track 1 items continue. This extends uncertainty for 2027 procurement planning and secondary market strategy. The delay also points to unresolved disputes over how RA obligations can be traded or adjusted, making the forthcoming Energy Division report a major inflection point for load-serving entities, Community Choice Aggregators, and generators once released. ### MONDAY AGGREGATE: Proposed Decisions on Flex Alerts, GCIM Year 31, and SDG&E ERRA Compliance URL: https://www.calregulatory.com/monday-aggregate-proposed-decisions-on-flex-alerts-gcim-year-31-and-sdg-e-erra-compliance/ Last updated: 2026-02-16T22:38:41.000Z Today's report rounds up a flurry of items covering flex alerts, shareholder incentive mechanisms, and transmission projects, many of which will populate the agenda for a busy CPUC voting meeting on March 19. --- ### FLEX ALERTS **Commissioner John Reynolds** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/599037490.PDF?ref=calregulatory.com) in [R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com) to extend the statewide Flex Alert paid media campaign through calendar year 2026, authorizing a one-year budget of **$15 million** funded by customers of the three large investor-owned utilities. The program, originally created after the 2020 heat-related outages, uses marketing and outreach to encourage voluntary electricity conservation during periods of grid stress, and studies cited in the PD indicate high public awareness and measurable reductions in usage on Flex Alert days. While most parties supported continuing the campaign, there was disagreement over funding levels and structure, with some urging a reduced budget due to the end of related emergency programs like [Power Saver Rewards](https://help.pge.com/s/article/What-is-Power-Saver-Rewards?language=en%5FUS&ref=calregulatory.com), and others opposing continuation altogether on affordability or equity grounds. (*See CRI's previous Flex Alert coverage* [*here*](https://www.calregulatory.com/in-focus-flex-alert-funding/)*.*) [Flex Alert FundingFlex Alerts are voluntary conservation appeals designed to reduce electricity demand during peak periods, particularly heat events![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-33.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/IMG_5420.JPG)](https://www.calregulatory.com/in-focus-flex-alert-funding/) The PD adopts a middle path by lowering funding from prior levels (**$22 million** in 2024-2025) but maintaining the program to preserve reliability benefits for summer 2026\. The PD also directs SCE to extend the existing contract with the campaign vendor ([Doyle Dane Bernbach Communications Group](https://en.wikipedia.org/wiki/DDB%5FWorldwide?ref=calregulatory.com)) through **December 31, 2026**. The PD allocates costs among PG&E, SCE, and SDG&E based on their shares of peak load. Comments are due **March 5**. The earliest the CPUC will consider this item is March 19. **INSTANT ANALYSIS**: This PD preserves a familiar grid-reliability tool rather than introducing new Demand Response mechanisms, confirming the CPUC will continue relying on mass public conservation appeals as a backstop for summer peak risk. The reduced budget reflects the end of emergency programs like Power Saver Rewards while acknowledging that Flex Alerts still deliver measurable load relief at relatively low implementation complexity compared to new program design. For market participants, the main takeaway is continuity: the PD creates no new compliance obligations or market opportunities, but planners should assume Flex Alerts will remain part of California’s peak-management stack through 2026, especially amid rising load from electrification, electric vehicles, and data centers. The cost allocation across IOU territories also reinforces that ratepayers (not taxpayers or statewide funds) will continue bearing the expense for at least one more year, postponing the broader funding debate rather than resolving it. --- ### GAS COST INCENTIVE MECHANISM The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K024/599024344.PDF?ref=calregulatory.com) approving SoCalGas’s request for an **$8.37 million** shareholder reward under its Gas Cost Incentive Mechanism for Year 31 (April 2024–March 2025), after finding the utility procured natural gas supplies significantly below its benchmark cost. SoCalGas’s actual gas procurement costs were about **$42.1 million** under the benchmark, producing **$33.8 million** in savings for core ratepayers and the remainder as a shareholder incentive under the GCIM’s established sharing formula, which rewards utilities for acquiring gas at or below market prices. Cal Advocates independently verified the calculations and recommended approval, and no parties disputed the figures. The PD concludes that the reward complies with prior Commission rules governing the mechanism and authorizes SoCalGas to recover the approved amount through its Purchased Gas Account. Comments are due **March 5**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** This PD is a routine but consequential validation of the GCIM framework as a functioning procurement incentive for SoCalGas, confirming that the utility captured substantial below-benchmark gas costs during a mild-weather, oversupplied market cycle and will retain a modest shareholder reward while passing the majority of savings to core customers. - For regulatory affairs and gas trading desks, the key takeaway is not the $8.37 million reward itself but the reaffirmation that the Commission continues to support market-indexed procurement incentives and tolerance-band sharing without recalibration, even amid public opposition to shareholder gains. - The absence of disputes, adjustments, or methodological changes indicates policy stability around gas procurement oversight heading into the next GCIM cycles, reducing regulatory risk for procurement strategy planning. Practically, this decision also confirms that weather-driven storage conditions materially shaped Year 31 outcomes. Notably, SoCalGas absorbed **$8.2 million** in hedging losses above benchmark but overcame this cost headwind through superior commodity procurement (**$29.4 million** under the benchmark) and secondary market services (**$20.1 million** in net revenue). This demonstrates that strategic spot market execution and portfolio optimization (rather than derivatives performance) drove the savings outcome. This reinforces that procurement performance – not rate design – remains the best method through which SoCalGas can produce near-term customer bill relief under current rules. --- ### SDG&E ERRA COMPLIANCE The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038878.PDF?ref=calregulatory.com) approving (with modifications) SDG&E's 2023 Energy Resource Recovery Account compliance application, finding that the utility’s power procurement, contract administration, dispatch decisions, and related accounting were largely prudent and consistent with CPUC-approved plans. The PD adopts several negotiated changes, including revising the valuation of retained Resource Adequacy capacity, correcting the accounting of Renewable Energy Certificates for RPS compliance, and reallocating certain battery storage revenues to a broader customer base. The PD also determines that SDG&E recorded a net undercollection of about **$214.6 million** across its procurement-related balancing accounts (excluding confidential subaccounts) and allows recovery of those costs through established mechanisms. A major contested issue involved stranded costs from SDG&E’s failed Green Tariff Shared Renewables programs, which suffered from declining enrollment and eventual suspension. The PD authorizes SDG&E to recover those outstanding program costs from all ratepayers through the Public Purpose Programs charge (rather than only former participants or shareholders) finding the utility followed statutory and regulatory direction and that program flaws, not mismanagement, produced the losses. The PD also affirms that SDG&E prudently managed generation resources, demand response programs, fuel procurement, greenhouse-gas compliance instruments, and numerous balancing accounts, while directing the utility to file a follow-up advice letter allocating renewable program costs among customer classes based on participation levels. Comments are due **March 5**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** By approving cost recovery and negotiated accounting fixes, the CPUC is showing that utilities will be judged on adherence to approved plans, which maintains procurement stability and avoids chilling future resource decisions. The treatment of the failed Green Tariff Shared Renewables programs reflects a pragmatic choice: spreading stranded costs broadly prevents rate shock to a small group and avoids retroactive penalties for a program the state required utilities to run. This is an attempt to stabilize outcomes when policy design produces unintended financial gaps. For market participants, the takeaway is predictability. The CPUC is prioritizing continuity in cost recovery rules and portfolio accounting, which reduces uncertainty for procurement planning even as allocation disputes between IOUs and CCAs continue. --- ### TRANSMISSION INFRASTRUCTURE The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038893.PDF?ref=calregulatory.com) in a 17-year-old proceeding granting SCE a certificate of public convenience and necessity to construct the [Alberhill System Project](https://www.sce.com/sites/default/files/inline-files/Alberhill%5FSystem%5FProject.pdf?ref=calregulatory.com) in western Riverside County. The PD concludes that new transmission and substation infrastructure is needed to address growing electricity demand, reliability risks, and resilience concerns in the Valley South System. The PD finds that this load pocket (which serves hundreds of thousands of residents and lacks tie-lines to neighboring systems) faces increasing exposure to outages and capacity constraints during extreme heat and contingency events, and that the project’s benefits outweigh its environmental impacts. The PD sets a cost cap of **$482 million** (2023 dollars) for the three-year construction project. The PD determines that relying on an existing spare transformer is not a viable long-term solution, cites recent peak demand levels approaching system limits, and concludes that additional infrastructure is necessary to maintain safe and reliable service. The decision rejects opposition arguments from TURN challenging SCE's capacity calculations, reliability metrics, and resilience assumptions. Comments are due **March 5**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS: T**he CPUC is prioritizing grid capacity and reliability investments in fast-growing, heat-exposed load pockets, even where environmental impacts are unavoidable. The Valley South System (an electrically isolated area serving hundreds of thousands of customers) is operating near its limits without tie-lines to import power during outages, creating elevated risk of curtailments during extreme conditions. The PD's willingness to grant a CPCN on these grounds in the face of sustained opposition indicates a resilience-first approach as electrification and demand compress planning timelines. - The PD points to a coming pipeline of transmission and substation approvals tied to reliability needs, with downstream effects on rate cases, cost recovery fights, and local capacity procurement. Traders and large customers should view it as a warning that infrastructure constraints (not just fuel supply) will shape operational risk during peak events. - The $482 million capital investment will flow through SCE's rate base, with quarterly reporting requirements to Energy Division creating transparency on project execution and cost control. - Community Choice Aggregators and IOUs should anticipate tighter scrutiny of load pockets lacking redundancy. If adopted, Alberhill could serve as a template for how the CPUC justifies major grid expansions in constrained regions over the next several years. --- ### TRANSMISSION UPGRADES The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056564.PDF?ref=calregulatory.com) granting [LS Power Grid California](https://www.lspowergrid.com/utilities/ls-power-grid-california/?ref=calregulatory.com) a certificate to construct the [Power Santa Clara Valley Project](https://www.lspowergrid.com/wp-content/uploads/Power-Santa-Clara-Valley-2-Pager.pdf?ref=calregulatory.com), a **$1.6 billion** transmission upgrade initially approved to address reliability issues in the San José area's 115-kV system. The project was subsequently modified in November 2024 to respond to load forecast increases from 2,100 MW to potentially 4,200 MW through a new HVDC link between major substations. The PD finds the project necessary despite significant environmental impacts, adopts an environmentally superior configuration with mitigation measures, and authorizes cost recovery through CAISO transmission rates subject to FERC oversight, emphasizing that rising load forecasts and grid stability needs outweigh unavoidable cultural resource impacts. Notably, the PD declines to apply the statutory rebuttable presumption in favor of the CAISO's needs determination due to cost estimate discrepancies, but independently finds the project meets present and future reliability requirements. An [accompanying appendix](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K152/599152723.PDF?ref=calregulatory.com) details the CEQA findings supporting approval of the project’s environmentally superior alternative, concluding that most impacts can be mitigated but that significant effects on cultural and tribal resources remain unavoidable. The PD determines these harms are outweighed by reliability benefits, long-term load growth needs in the San Jose area, and improved delivery of renewable energy to the Bay Area. The document also outlines the mitigation measures, monitoring requirements, and alternatives analysis underpinning that determination. Comments are due **March 5**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** This PD advances a reliability-driven transmission project in one of California's fastest-growing load pockets. It shows that the CPUC will prioritize grid stability and renewable deliverability over localized environmental concerns when CAISO planning need is established through load forecasting and system analysis, regardless of whether the statutory rebuttable presumption applies. By selecting the environmentally superior alternative and relying on CEQA overriding considerations, the PD provides a replicable pathway for future urban transmission projects facing cultural or siting conflicts. For utilities, CCAs, and large loads, the strategic implication is clear: Bay Area transmission constraints are being addressed through high-cost infrastructure that will ultimately flow into CAISO transmission charges, shaping long-term cost exposure and congestion dynamics rather than immediate retail rates. --- ### NATURAL GAS TRANSMISSION PG&E submitted an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5178-G.pdf?ref=calregulatory.com) notifying the CPUC of its plan to downrate a segment of gas transmission Line 1217-01 between milepoints 0.00 and 4.10 that serves the Fresno high-pressure distribution system. The project will reduce the line’s maximum allowable operating pressure from 400 psig to 390 psig while maintaining the normal operating pressure at 340 psig, which PG&E states will produce no downstream hydraulic impacts. PG&E estimates the work will cost about **$20,000** and be completed around **March 31, 2026**, requiring only minor regulator adjustments with no new pipeline construction. The economic driver: PG&E will avoid **$3.6 million** in strength tests that would otherwise recur every seven years to address identified pipeline integrity threats, which is approximately **$18 million** in avoided costs over three decades. **INSTANT ANALYSIS:** This filing exemplifies PG&E's strategy of using downrates to escape expensive integrity management cycles rather than repair/replace threatened pipelines. PG&E is reducing pressure on a Fresno-area gas transmission feeder because full capacity is no longer needed, implementing the CPUC’s directive to downrate surplus assets while maintaining reliability. Individually, it's a minor filing but it has cumulative importance. Repeated downrates reduce system headroom over time and can affect deliverability during stress events. --- ### DIABLO CANYON PG&E submitted an [advice lette](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7835-E.pdf?ref=calregulatory.com)r notifying the CPUC that the Internal Revenue Service issued a favorable private letter ruling on tax normalization issues associated with the extended operation of the Diablo Canyon Power Plant under [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com). - The IRS ruling addresses the unusual cost-recovery framework requiring extended-operations costs to be treated as operating expenses rather than placed in rate base. - The IRS concluded that Diablo Canyon's extended-operations assets are not "public utility property" under [IRC § 168(i)(10)](https://bradfordtaxinstitute.com/Endnotes/IRC%5FSection%5F168i.pdf?ref=calregulatory.com) because SB 846's special ratemaking method is not rate-of-return ratemaking. This means the federal normalization rules do not apply to these assets in the first place. Consequently, amounts tracked in a memorandum account will be reversed and no rate adjustment is required on that issue. A second IRS private letter ruling (on whether Diablo Canyon Volumetric Performance Fees qualify for nontaxable treatment) remains pending and will be disclosed in a future advice letter. **INSTANT ANALYSIS:** This filing removes a technical tax risk from the Diablo Canyon extended-operations framework without changing the underlying policy trajectory. - By confirming that SB 846's operating-expense recovery structure falls outside the scope of federal normalization requirements, the IRS ruling preserves the Legislature's chosen approach and spares the CPUC from reopening rate treatment disputes tied to nuclear extension costs. The immediate effect is procedural stability: PG&E can unwind its tracking account entries and proceed without seeking retroactive rate fixes on this issue. - The deeper takeaway is precedent. California has now stress-tested a non-rate-base recovery model for a major baseload asset and cleared a key federal tax constraint. That matters for any future efforts to keep large infrastructure online through bespoke cost mechanisms outside traditional rate-of-return regulation. The filing does not move markets today, but it strengthens the legal architecture supporting the state's nuclear retention strategy. The ruling also reduces one pathway for opponents to challenge the financing structure (though it is taxpayer-specific and cannot be cited as precedent). --- ### SELF-GENERATION INCENTIVE PROGRAM **Commissioner Karen Douglas** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056565.PDF?ref=calregulatory.com) that, if adopted, would deny ENGIE North America’s [petition to modify](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K757/542757352.PDF?ref=calregulatory.com) a 2021 decision in the Self-Generation Incentive Program rulemaking ([D.21-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M387/K064/387064243.PDF?ref=calregulatory.com)). The petition sought an exemption for wastewater treatment plants from the requirement that on-site biogas used in internal combustion engine projects contain at least **96% methane**. The PD finds the petition procedurally defective. It would leave the existing methane quality standard in place while keeping the broader SGIP rulemaking open. Comments are due **March 5**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** The PD blocks ENGIE’s request on procedural grounds, leaving the 96% methane requirement for SGIP biogas engine projects intact and avoiding any reopening of the emissions standard debate. Wastewater biogas projects that cannot meet the purity threshold remain effectively sidelined from SGIP incentives. The message to stakeholders is procedural discipline: exemptions must be pursued through future program changes, not late petitions to modify old decisions. Near term, developers face pressure to upgrade gas quality, pivot technologies, or seek non-SGIP funding. ### EPIC 5 Shaping Up as Continuity Program With Some Course Corrections URL: https://www.calregulatory.com/epic-5-shaping-up-as-continuity-program-with-some-course-corrections/ Last updated: 2026-02-13T23:55:14.000Z In a series of opening comments on the CPUC’s [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495688.PDF?ref=calregulatory.com) establishing strategic objectives for the Electric Program Investment Charge (EPIC) program, parties largely support renewing the program but urge revisions to ensure it addresses commercialization gaps, emerging technologies, security risks, and implementation clarity. Recall that the PD [sets the framework](https://www.calregulatory.com/friday-aggregate-pg-e-electric-rates-slice-of-day-impacts-vehicle-to-everything/?ref=california-regulatory-intelligence-newsletter) for EPIC’s next investment cycle (EPIC 5). The PD adopts 13 measurable Strategic Objectives that will guide EPIC 5 investments from 2026 through 2030, translating previously adopted high-level goals into concrete, near-term targets. [PG&E Electric Rates; Slice-of-Day ImpactsPG&E filed an AL to comply with a December 2025 CPUC decision approving its consolidated 2026 ERRA forecast and related trigger application![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-32.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Jan-28-2026--8-.png)](https://www.calregulatory.com/friday-aggregate-pg-e-electric-rates-slice-of-day-impacts-vehicle-to-everything/?ref=california-regulatory-intelligence-newsletter) - The Bay Area Science and Innovation Consortium [backs](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056527.PDF?ref=calregulatory.com) the program’s focus on affordability and reliability but asks the Commission to expand building-decarbonization research to include commercial buildings and to strengthen support for emerging zero-carbon generation and storage technologies, while also emphasizing the role of regional innovation clusters in turning research into deployable solutions. - The California Energy Commission likewise [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K162/599162470.PDF?ref=calregulatory.com) the proposed 13 objectives and equity framework but recommends edits to better capture full charging-infrastructure costs, broaden interconnection reforms to all clean resources and new loads, incorporate near-term climate-adaptation planning, and rely on existing reporting mechanisms rather than new administrative layers. - Entrepreneurial organizations [argue](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K155/599155000.PDF?ref=calregulatory.com) the PD undervalues commercialization pathways, urging stronger recognition and funding of Regional Energy Innovation Clusters that help startups bridge financing gaps and deliver ratepayer benefits through technology deployment. - The major utilities ([PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056546.PDF?ref=calregulatory.com), [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K162/599162487.PDF?ref=calregulatory.com), and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K154/599154418.PDF?ref=calregulatory.com)) generally support continuing EPIC and its funding levels but focus on operational concerns, including clearer budget mechanics, treatment of intellectual property, and risks from certain proposed requirements. PG&E seeks detailed budget tables, clarification on inflation adjustments, and recognition of innovation needs such as wildfire mitigation and faster interconnection of all new loads. - SDG&E and SCE warn that provisions calling for open access to grid-equipment data could create cybersecurity and physical-security vulnerabilities, while also requesting clarification on budget increases and program governance. ### INSTANT ANALYSIS These comments reveal broad institutional support for renewing EPIC as California’s flagship ratepayer-funded energy innovation program, but they also expose a tug-of-war over what EPIC 5 is actually for: pure research, commercialization pipeline, or grid-operations tool. - Universities and innovation clusters are pushing to widen the aperture toward commercialization, entrepreneurship, and emerging supply technologies, while the CEC is focused on flexibility, planning integration, and administrative efficiency. - The utilities’ filings are more defensive and operational, centering on budgets, intellectual-property constraints, interconnection scope, wildfire innovation, and especially security risks tied to any requirement to release granular grid data. A final decision will likely preserve the 13 objectives but narrow or clarify implementation language (particularly around data access, reporting burdens, and funding mechanics) to keep utilities on board. For CRI readers, the main takeaway is that EPIC 5 is shaping up as a continuity program with incremental course corrections, not a radical redesign, meaning stakeholders should focus on influencing investment plans and project selections where the real money and policy leverage will sit. ### WHO SHOULD CARE? - **Utilities and Load-Serving Entities**. EPIC 5 will shape the technology pipeline that utilities will later seek to deploy and recover in rates, especially in areas like wildfire mitigation, grid hardening, interconnection tools, and electrification infrastructure. If you manage planning, regulatory affairs, or grid strategy, this is upstream influence over future capital programs and compliance obligations. - **Developers, DER Providers, and Grid-Tech Vendors**. EPIC funding often determines which technologies get validated in California first (and which do not). Interconnection acceleration tools, EV charging infrastructure cost reductions, flexible demand tech, and resilience solutions are all on the table, making this relevant to anyone trying to sell into the California market later this decade. - **Energy Investors and Infrastructure Players**. EPIC is an early indicator of where public money and policy attention will concentrate, which tends to de-risk private capital. Venture funds, project developers, data-center operators, and electrification infrastructure investors should treat it as a forward map of future procurement categories. - **Large Energy Users and Industrial Customers**. The program’s stated goals include affordability, reliability, and load integration, meaning the outcomes can influence rates, interconnection timelines, and demand-side opportunities for major customers. Industrials, data centers, and electrifying facilities should watch for technologies that could lower costs or enable faster service. - **Security and Risk Stakeholders**. Proposals involving open access to grid data and new operational tools raise physical and cybersecurity concerns flagged by the utilities, making this relevant to anyone responsible for infrastructure protection or critical-facility resilience. If your exposure to California energy policy is measured in millions of dollars rather than headlines, you should care. EPIC 5 is not a media story, it is a project pipeline story. The work funded here tends to reappear later as mandates, procurement programs, or cost-recovery battles. ### Storage Market Review Likely Despite ISP Clearance; PG&E Warns Price Cap Could Create $3 Billion Liquidity Requirement URL: https://www.calregulatory.com/storage-market-review-likely-despite-isp-clearance-pg-e-warns-price-cap-could-create-3-billion-liquidity-requirement/ Last updated: 2026-02-13T22:34:31.000Z On February 12 parties filed comments responding to the CPUC's [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K227/595227206.PDF?ref=calregulatory.com) in I.23-03-008, which addresses the winter 2022–2023 natural gas price spike. Recall that, rather than pursuing commodity price intervention, the PD pivots toward bill-shock mitigation by defining a “gas price spike event” as a **150% increase** relative to the ten-year monthly average, triggering a temporary cap on core procurement charges, amortization of under-collections, and enhanced customer notice requirements. The PD also enhances oversight of procurement incentive mechanisms (the Core Procurement Incentive Mechanism and the Gas Cost Incentive Mechanism) by requiring formal applications for any shareholder rewards and expands transparency through standardized monthly storage inventory reporting. [PD Lands in CPUC’s Natural Gas Price Spike InvestigationThe PD finds that the winter 2022–2023 natural gas price spike resulted from a convergence of adverse market conditions.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-31.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Nov-25-2025--7--1.png)](https://www.calregulatory.com/proposed-decision-lands-in-cpucs-natural-gas-price-spike-investigation/) --- Parties broadly accept the PD's conclusion that the winter 2022–2023 gas price spike was driven by market conditions rather than misconduct by any single regulated utility or storage provider. (Although the Sierra Club [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038854.PDF?ref=calregulatory.com) that SoCalGas either contributed to the spike or retained 21.6 Bcf of excess storage capacity, beyond reliability needs.) Beyond this broad consensus, parties disagree over how the Commission should respond going forward. - The utilities argue that several proposed mitigation measures (especially a temporary cap on procurement charges and rigid notification rules) could backfire by weakening utility finances, distorting price signals, or complicating operations during volatile market periods. - PG&E [warns](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K152/599152702.PDF?ref=calregulatory.com) the temporary cap could trigger a financing scenario "not unlike events experienced in 2001" when retail rate freezes trapped utilities between soaring wholesale costs and capped retail recovery, leading to PG&E's bankruptcy. PG&E notes it would have needed over **$3 billion** in liquidity utilization (including **$2.4 billion** in collateral for gas procurement plus additional short-term debt) had the cap been in effect during winter 2022-2023. - The utilities also seek clearer triggers for declaring a price-spike event, more workable timelines for customer alerts, and relief from requirements they say could produce inaccurate or confusing information if prices move rapidly. All three major utilities want "one business day" instead of "24 hours" for notifications to align with when customer support is available. Southwest Gas [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/599037466.PDF?ref=calregulatory.com) 45-50 days (not 30) for bill inserts due to billing cycle realities. PG&E objects to providing estimated bill impacts within 24 hours, arguing volatility makes accuracy impossible. - Storage operators and independent storage providers emphasize that competitive storage access helped stabilize prices during the crisis, oppose further scrutiny of their market structure, and urge the CPUC to consider expanding storage capacity as a long-term safeguard against future spikes. Central Valley Gas Storage [notes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K056/599056541.PDF?ref=calregulatory.com) the Commission affirmed the ISP market remains competitive less than one year ago (in [D.25-04-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M565/K249/565249273.PDF?ref=calregulatory.com)) and argues the PD's plan to evaluate Independent Storage Provider market structure creates the same "unnecessary market uncertainty" the PD claims to avoid by declining a cost-of-service study. - Consumer advocates and small-business groups focus on the severity of the bill shock experienced by customers, citing dramatic increases and arguing the decision lacks strong protections if prices surge again. They call for lower caps, stricter review of cost recovery, stronger communication requirements, and policies aimed at preventing extreme affordability impacts on households and small firms. - The Utility Consumers Action Network (UCAN) [emphasizes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K152/599152701.PDF?ref=calregulatory.com) California's ongoing affordability crisis, noting SDG&E customers saw bills jump **114%** in January 2023 and one in four customers fell into arrears. UCAN wants a **20% price increase trigger** (not 150%), a disconnection moratorium during spikes, and a ban on reporting delinquencies to credit agencies. The Small Business Utility Advocates [want](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K162/599162483.PDF?ref=calregulatory.com) the cap lowered to 115% above historical averages or, alternatively, require cost recovery through formal application proceedings. - Environmental and public-interest organizations press for deeper reforms, including earlier intervention triggers, customer support resources during extreme weather, greater transparency on gas procurement and storage practices, and accelerated electrification to reduce dependence on volatile gas markets. - The Environmental Defense Fund [proposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K155/599155007.PDF?ref=calregulatory.com) a **100% trigger threshold** and is disappointed the PD rejects community resource centers. Sierra Club [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038854.PDF?ref=calregulatory.com) a moratorium on GCIM/CPIM shareholder rewards until the incentive mechanisms are reformed, a **1%** fuel cost sharing program to align utility and ratepayer incentives, and quarterly distribution of CPUC-provided electrification fact sheets. - Cal Advocates [concentrates on](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K154/599154399.PDF?ref=calregulatory.com) protecting its independent oversight role and revising directives it views as unrealistic or inconsistent with statute. Cal Advocates objects to PD language requiring it to issue monitoring reports within four months and in specific formats, arguing this violates language in the Public Utilities Code that establishes its independence. Cal Advocates states it needs 6-12 months to complete Core Procurement Incentive Mechanism monitoring reports and wants reporting requirements placed on the utilities, not on Cal Advocates. ### **INSTANT ANALYSIS** The PD offers a no-fault finding paired with new oversight tools for future gas price spikes. Utilities are trying to prevent measures that could trap them between volatile wholesale costs and capped retail recovery, while storage operators are defending the current competitive market structure. Consumer and environmental advocates are pushing the affordability narrative to justify earlier intervention triggers, stricter safeguards, and shifting more risk away from customers. Several proposals would expand the Commission’s role from monitoring gas markets to actively managing outcomes during price shocks. A key issue going forward is storage. Despite being cleared in the investigation, storage parties are positioning for a future conflict over storage market structure, capacity expansion, and transparency requirements. The PD proposes to evaluate ISP ownership, contract pricing, market concentration, and tariff structures "outside this proceeding" at an unspecified future time, creating exactly the regulatory uncertainty storage operators warn will increase costs and constrain capital access. ### WHO SHOULD CARE? - **Gas utilities and their regulatory teams.** The final version of this decision could constrain procurement flexibility, impose new notification duties, and shape how future price spikes are managed financially and operationally. - **Gas marketers, storage operators, and large noncore customers.** Storage policy, market transparency rules, and potential future reviews of Independent Storage Provider market structure could affect access to capacity and price formation. - **Industrial, commercial, and small-business gas users.** Consumer advocates are pushing bill-stabilization tools and cost-recovery limits that could determine who ultimately bears the cost of the next spike. - **Policymakers tracking affordability and electrification.** Some parties want earlier intervention triggers and policies that reduce dependence on gas during extreme winters. In short, anyone exposed to California gas price volatility or procurement policy should be watching this closely before the next winter event. ### FRIDAY AGGREGATE: Scoping Memo Lands in CPUC's Demand Response Rulemaking URL: https://www.calregulatory.com/friday-aggregate-scoping-memo-lands-in-cpucs-demand-response-rulemaking/ Last updated: 2026-02-13T21:04:47.000Z Today's end-of-week roundup includes: - A scoping memo in the CPUC's Demand Response rulemaking confirming that the CPUC is moving toward a comprehensive reset of DR policy, not just a bridge-year funding patch; - PG&E's opposition to a motion by Cal Advocates, TURN, and CLECA to pause the Electric Rule 30 proceeding on transmission-level retail electric service; - SoCalGas's response to parties who protested its Advanced Meter Infrastructure Replacement Project; - A new proposed decision authorizing SCE to issue up to **$9.85 billion** in new debt and **$1.155 billion** in preferred equity; - An SDG&E advice letter that seeks CPUC approval of amendments to long-term bundled renewable energy sales agreements with San Diego Community Power and Clean Energy Alliance; and - A SDG&E request for CPUC approval to update the definition of “mixed-fuel” in its electric and gas service rules to reflect prior Commission guidance on building electrification policy. ### DEMAND RESPONSE **Commissioner John Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038857.PDF?ref=calregulatory.com) in [R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com), which is focused on enhancing Demand Response programs across California by improving their consistency, predictability, reliability, cost-effectiveness, and integration with markets and dynamic rates. The ruling establishes the schedule for addressing topics such as: - Extending funding for existing Demand Response programs authorized in prior decisions; - Continuing the Flex Alert marketing campaign; - Updating guiding principles for Demand Response policy; and - Developing standardized data systems and communication protocols to support these resources. The ruling also raises questions about valuation methods, dual participation, Resource Adequacy treatment, cost-effectiveness evaluation methodology, prohibited resource policy, and CAISO integration, portending a broad review of how DR is planned, measured, and compensated. The memo says that evidentiary hearings may be required for the bridge-year funding issue and adopts a detailed timeline the Commission intends to complete within 24 months, with separate tracks for bridge funding decisions, Flex Alert funding, and data-system reforms. **INSTANT ANALYSIS:** This scoping memo confirms that the CPUC is moving toward a comprehensive reset of DR policy, not just a bridge-year funding patch. The scope inclusion of data systems, valuation methods, resource adequacy treatment, and CAISO integration indicates the Commission is preparing to treat DR as a fully operational grid resource rather than a seasonal emergency tool. Parties with exposure to Resource Adequacy, dynamic pricing, DER aggregation, or load flexibility markets should view this as groundwork for future procurement rules and compensation frameworks. Perhaps most important for near-term planning: the timeline creates a regulatory gap that stakeholders need to manage. The ruling calls for two distinct engagement tracks: - Near-term fights over money and program continuation; and - Longer-term battles over market design and data infrastructure. Bridge-year funding decisions are expected to land in Q3 or Q4 of 2026, well before deeper policy matters are finalized, meaning stakeholders will likely have to operate under temporary rules while the Commission builds a new DR regime. --- ### TRANSMISSION-LEVEL RETAIL SERVICE PG&E recently [filed its opposition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K038/599038853.PDF?ref=calregulatory.com) to a [motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101882.PDF?ref=calregulatory.com) by Cal Advocates, TURN, and CLECA to pause the Electric Rule 30 proceeding on transmission-level retail electric service. PG&E says it will file a motion for leave to submit supplemental testimony on **February 13**, covering three topics: - Revisions to its proposed minimum demand charge methodology; - An option for transmission-level customers to perform undergrounding and certain Facility Type 3 work under the Applicant Build Option; and - Additional ratepayer protections in the Electric Rule 30 form agreement. PG&E moved this filing up from **February 18** and agreed to expedited five-business-day discovery turnaround, framing both concessions as good-faith responses to concerns raised by intervenors on a February 9 call. It argues the current schedule allows fair participation and that an open-ended delay would push a decision well past the expected mid-2026 timeframe. PG&E cites the Commission's own November 2025 comments to FERC ([Docket No. RM26-4-000](https://www.ferc.gov/rm26-4?ref=calregulatory.com)) stating the CPUC expects to issue a decision on Electric Rule 30 by mid-2026, arguing the intervenors' stay request contradicts the Commission's representations to a federal agency. Additionally, PG&E warns that a long delay would force large customers to keep negotiating one-off agreements instead of using a uniform tariff, prolonging uncertainty on cost responsibility and ratepayer protections. It frames this status quo as harmful to both existing ratepayers and prospective transmission-level customers (the very constituencies represented by Cal Advocates, TURN, and CLECA). If the Commission wants more time, PG&E proposes a revised spring 2026 schedule rather than an indefinite stay. It asks the Commission to deny the motion or adopt that alternative timeline to keep the case within statutory deadlines. An attached email chain tells its own story: Cal Advocates gave PG&E roughly two hours' notice before filing the motion to stay, initially declined to take a call, and never responded to PG&E's proposed alternative schedule before filing unilaterally with TURN and CLECA. PG&E clearly wants this procedural record before the ALJ. **INSTANT ANALYSIS:** We are witnessing a battle over whether transmission-level retail service moves from bespoke approvals to a standardized tariff. The current environment is flexible but discretionary, with projects advancing through negotiated agreements that still require Commission sign-off. PG&E wants a predictable framework but intervenors may prefer retaining leverage that comes from case-specific scrutiny. The intervenors' interest in coordinating with PG&E's 2027 General Rate Case (raised on the February 9 call) suggests they want to tie Rule 30 cost-allocation questions to the broader rate case, which would give them more leverage over how costs flow through but could delay resolution into late 2026 or 2027\. For developers and large loads, the real question is flexibility versus certainty. The current path allows tailored deals but carries approval risk and timing uncertainty, while a Rule 30 tariff would create a defined lane with known cost rules. --- ### NATURAL GAS ADVANCED METERING INFRASTRUCTURE SoCalGas filed [a reply](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/599037471.PDF?ref=calregulatory.com) to protests from [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166380.PDF?ref=calregulatory.com) and [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K288/597288878.PDF?ref=calregulatory.com), and a response from the [Small Business Utility Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166392.PDF?ref=calregulatory.com), regarding its Advanced Meter Infrastructure Replacement Project, arguing that the filings provide no valid basis to deny or defer the proposal. [New SoCalGas AMI ApplicationAs we head into 2026, a request: if you or your team find this work useful, please consider becoming a paid CRI subscriber.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-30.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-22-2025--3--1.png)](https://www.calregulatory.com/wednesday-aggregate-6/) SoCalGas maintains that replacing aging meter communication modules through a standalone proceeding is appropriate, necessary to avoid system failures and higher long-term costs, and consistent with prior Commission practice for large projects. It cites decisions in which the Commission directed SDG&E and permitted PG&E to file standalone applications for their own AMI replacement programs. SoCalGas: - Rejects claims that the project should instead be handled in a future general rate case; - Disputes allegations that it failed to justify costs or alternatives; and - Clarifies that the work largely involves replacing communication modules rather than gas meters themselves, with minimal expected service disruption. SoCalGas also pushes back on TURN's call for a retrospective review of SoCalGas's original smart meter system (AMI 1.0). SoCalGas asserts that AMI 1.0 outperformed its original business case and that this was already demonstrated in the Test Year 2019 General Rate Case and through semi-annual reports filed with the Commission's Energy Division. On accounting treatment, SoCalGas distinguishes two mechanisms: - The Advanced Meter Infrastructure Replacement Memorandum Account is an interim cost-tracking tool filed via separate motion; SoCalGas argues it should not be litigated in this proceeding; and - The Advanced Meter Infrastructure Replacement Balancing Account is the cost-recovery vehicle through which authorized costs would ultimately be recorded and recovered in rates. SoCalGas agrees this account is properly within scope. SoCalGas otherwise outlines what issues it considers properly within the proceeding's scope: project prudence, cost forecasts, cost allocation among customer classes, and treatment of stranded assets. It argues that Cal Advocates' proposal to allocate project costs to shareholders is improper and "confiscatory." SoCalGas invokes the regulatory compact framework and foundational ratemaking precedent from *Hope Natural Gas* and *Bluefield* to support that position. **INSTANT ANALYSIS:** SoCalGas is trying to keep its AMI replacement project on a fast, standalone track rather than letting intervenors move it into the next General Rate Case, which would slow approval and expand the scope of review. SoCalGas holds that aging meter communication modules pose an operational risk if replacement authority is delayed, and it characterizes timely approval as necessary to avoid reactive repairs and higher costs later. Readers with exposure to gas utility capital plans, rate impacts, meter data infrastructure, or electrification strategy should watch this proceeding. A CPUC decision allowing the project to proceed independently would show that large gas infrastructure replacements can move outside the crowded GRC process. A decision forcing consolidation into broader proceedings would indicate tougher scrutiny of long-term gas investments going forward. TURN's push for a retrospective benefits review of AMI 1.0 is worth tracking as a proxy fight over whether the Commission should apply greater skepticism to the next generation of gas metering investment, particularly for a gas-only utility with no electric portfolio to fall back on. --- ### UTILITY FINANCES A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M599/K037/99037460.PDF?ref=calregulatory.com) would authorize SCE to issue up to **$9.85 billion** in new debt and **$1.155 billion** in preferred equity, a **$525 million** reduction that SCE itself proposed after updating forecasts to reflect the CPUC's 2025 General Rate Case decision ([D.25-09-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M580/K788/580788967.PDF?ref=calregulatory.com)). The funds would finance capital expenditures, refinance maturing obligations, and address wildfire-related liabilities through 2028. The authority would also allow SCE to use various financing tools such as hedges, swaps, credit facilities, guarantees, and the pledging of utility assets or accounts receivable to lower borrowing costs and manage risk, with proceeds intended to support grid safety, reliability, modernization, and wildfire mitigation investments. - The PD emphasizes that granting financing authority does not approve specific projects or cost recovery in rates; those issues would be evaluated in separate proceedings. - The PD also responds to concerns from consumer advocates and small-business representatives about potential over-borrowing and double recovery of wildfire costs by noting that any borrowing must ultimately be repaid by the utility and remains subject to later regulatory review. The PD rejects Cal Advocates' calls for a cost-effectiveness analysis and the Small Business Utility Advocates' request for additional evidentiary filings, finding the supplemented record sufficient. Comments are due **March 4**. The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** This PD is a major financing authorization that positions SCE to fund wildfire liabilities, grid hardening, and capital programs through 2028 without returning repeatedly to the CPUC for incremental approvals. It ensures liquidity and balance-sheet flexibility at a moment when wildfire exposure, infrastructure spending, and refinancing needs are converging, while preserving Commission oversight by separating financing authority from cost-recovery determinations. For market participants, the main takeaway is timing and scale: once approved, SCE gains a large, pre-cleared borrowing envelope that can be deployed opportunistically based on interest rates and financing conditions. Stakeholders exposed to rates, utility credit, wildfire cost recovery, or capital planning should track how quickly SCE draws on this authority, because proceedings downstream of this one will ultimately determine who pays. --- ### POWER CHARGE INDIFFERENCE ADJUSTMENT ALLOCATIONS/CCA PORTFOLIO MANAGEMENT SDG&E submitted Advice Letter 4803-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) seeking CPUC approval of amendments to long-term bundled renewable energy sales agreements with San Diego Community Power and Clean Energy Alliance. The amendments modify the contract end dates for a portfolio of 26 PCIA-eligible renewable projects totaling roughly **2,000+ MW** of solar PV and wind so that the allocation terms run through the end of the longest contract in the relevant PCIA portfolio, as required by a 2021 CPUC decision ([D.21-05-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M385/K738/385738144.PDF?ref=calregulatory.com)). The two amendments differ slightly: - For San Diego Community Power, the fixed **December 31, 2033** end date is replaced with an open-ended term tied to when SDG&E stops receiving product from the project contracts; and - For Clean Energy Alliance, the original term (tied to the 10th anniversary of the Start Date) is similarly extended but includes a hard backstop of **December 31, 2042**. SDG&E states that no other contract provisions would change and that the updates are needed to comply with the Commission's voluntary allocation framework for renewable resources and associated credits previously approved in [Resolution E-5206](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M479/K339/479339567.PDF?ref=calregulatory.com). Protests are due **March 4**. **INSTANT ANALYSIS:** This is technical compliance filing that keeps San Diego Community Power and the Clean Energy Alliance tied to legacy utility renewable contracts for the full duration of the longest PCIA-eligible agreements, preserving existing cost responsibility. The impact is on long-term PCIA exposure and planning assumptions, not procurement policy or near-term market conditions. The Clean Energy Alliance backstop date of 2042 effectively caps that CCA's maximum exposure window, while SDCP's open-ended language leaves its commitment tied entirely to SDG&E's underlying contract portfolio. --- ### BUILDING ELECTRIFICATION POLICY SDG&E filed Advice Letter 4804-E/3496-G (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) seeking CPUC approval to update the definition of “mixed-fuel” in its electric and gas service rules to reflect prior Commission guidance on building electrification policy. The revision would classify new construction projects as mixed-fuel if they either use gas or are stubbed for future gas or propane service, while projects without gas stubs would be treated as all-electric and remain eligible for electric line-extension subsidies. The changes implement earlier CPUC decisions eliminating subsidies for mixed-fuel new construction as part of the state’s greenhouse-gas reduction strategy (including [D.25-06-034](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M570/K302/570302781.PDF?ref=calregulatory.com)'s extension of the original implementation deadlines). Their purpose is to ensure consistent utility treatment of subsidy eligibility across projects. **INSTANT ANALYSIS:** This filing puts the CPUC’s building electrification policy into SDG&E’s tariffs by tying subsidy eligibility to whether new construction is designed to accommodate gas service, not just whether gas is initially used. By treating projects stubbed for gas as mixed-fuel, SDG&E closes a common developer workaround and increases the financial pressure to commit to fully electric designs upfront. The change does not affect rates or procurement, but it directly shapes project economics, interconnection planning, and future load growth by steering new development toward all-electric pathways aligned with prior CPUC decisions. ### Utilities Must Fix and Reconcile Integration Capacity Maps Under CPUC Draft Resolution URL: https://www.calregulatory.com/utilities-must-fix-and-reconcile-integration-capacity-maps-under-cpuc-draft-resolution/ Last updated: 2026-02-12T21:33:55.000Z The CPUC issued Draft Resolution [E-5440](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K870/598870863.PDF?ref=calregulatory.com), which would approve, with modifications, remediation plans submitted by PG&E, SCE, and SDG&E to fix accuracy, transparency, and usability problems in their [Integration Capacity Analysis](https://irecusa.org/blog/regulatory-engagement/key-lessons-from-the-california-integrated-capacity-analysis/?ref=calregulatory.com) tools. These tools estimate how much distributed energy can be added to the grid without upgrades. ### **TLDR** Draft Resolution E-5440, tentatively scheduled for consideration on **March 19**, approves utility plans to fix errors and gaps in the maps that show where new energy projects and large loads can connect to the grid without upgrades, while imposing new tracking to measure when those maps diverge from real interconnection outcomes. Utilities must improve data transparency, reduce redactions, update maps more consistently, and report the causes of discrepancies. For developers and large customers, the message is straightforward: the state is auditing whether grid capacity information is reliable, and preparing to fix it if it isn’t. --- ### Summary of Draft Resolution E-5440 The draft resolution requires the utilities to correct data errors, reactivate inactive circuits on maps, improve the timeliness of map updates, and expand reporting so stakeholders can track when Integration Capacity Analysis results diverge from real interconnection outcomes. - It also establishes a formal concordance/discordance framework that categorizes interconnection and energization application into one of four scenarios based on whether the ICA map value and the actual engineering outcome aligned. In so doing, it creates, for the first time, a structured taxonomy for measuring ICA usefulness across all three major electric utilities. - The draft resolution orders SDG&E to stop excessive redactions of generation data, directs all utilities to publish more complete system information (including substations up to the transmission level) on public planning portals, and establishes new metrics to measure whether Integration Capacity Analysis outputs align with actual engineering results. - The draft resolution codifies new definitions, distinguishing "ICA accuracy" (whether the utility correctly followed the approved methodology) from "ICA alignment" (whether ICA results match real-world engineering outcomes). Draft Resolution E-5440 concludes that stronger tracking and standardized reporting are needed before further methodological changes, and instructs the utilities to collect concordance data, report progress in biannual filings, and later propose improvements to the Integration Capacity Analysis methodology based on those findings. The draft resolution explicitly declines to impose automatic penalties for noncompliance at this time, though it notes existing penalty authority remains available. ### **INSTANT ANALYSIS** This draft resolution is the Commission’s clearest move yet to turn Integration Capacity Analysis from a planning artifact into an accountability tool. By forcing the utilities to track when Integration Capacity Analysis results diverge from real interconnection outcomes, the CPUC is indicating that inaccurate hosting-capacity maps are now a regulatory compliance issue, not just a stakeholder frustration. The draft resolution finds SDG&E explicitly out of compliance on redaction practices, reinforcing that these are enforceable obligations. For developers, DER providers, and large load customers, the main takeaway is that Integration Capacity Analysis outputs will become more auditable over the next six to 12 months as the new tracking and reporting requirements take effect. Whether ICA results also trend more conservative remains to be seen (the draft resolution does not direct any change in ICA values, but utilities facing new concordance scrutiny may err toward caution). The draft resolution also increases transparency requirements that had limited Integration Capacity Analysis usefulness, especially SDG&E's redactions and the absence of substation-level visibility. That change improves siting intelligence for projects near transmission-connected nodes, while the reaffirmed expectation to refresh changed circuits monthly puts pressure on utilities to keep maps current as electrification accelerates. The draft resolution acknowledges reasonable exceptions to the monthly cadence where model run times or failures prevent timely updates, but the new trigger-date tracking will make delays visible for the first time. At the operational level, the new concordance framework requires utilities to categorize every discordant outcome by root cause: - Miscalculation of limiting criteria; - Minor system adjustments made by the distribution engineer; or - Other limitations of ICA's current scope and methodology. These categories will determine whether future corrective action targets data quality, engineering practice, or ICA methodology itself. In plain English, the Commission is laying groundwork for a future Integration Capacity Analysis methodology overhaul without reopening the underlying proceeding yet. The next conflict may involve whether Integration Capacity Analysis should become a quasi-interconnection screening tool or remain a high-level planning estimate. Draft Resolution E-5440's careful distinction between "accuracy" and "alignment" already frames the terms of that argument. This distinction will shape how quickly DER, EV infrastructure, and large loads can move from concept to application across the investor-owned utilities' territories. ### WHO SHOULD CARE? - **DER developers and storage providers**. Integration Capacity Analysis maps are the first screen for where projects can interconnect without upgrades. More accurate (and more conservative) Integration Capacity Analysis results will affect site selection, queue strategy, and project timelines across all three IOU territories. The new concordance data will also reveal, for the first time, how often each utility's ICA maps overstated or understated available capacity (intelligence that enhances due diligence). - **Large load customers (data centers, hydrogen, electrified industry, large campuses)**. Load ICA is becoming a gating tool for energization timelines. If you are planning megawatt-scale new load, the CPUC is building the data infrastructure to evaluate whether ICA results are meaningfully aligned with actual engineering outcomes, which will eventually inform whether utilities are steering projects appropriately or delaying capacity access. - **EV infrastructure companies and fleet electrification planners**. The draft resolution specifically addresses EV charging application reporting and load hosting accuracy. SCE was found to have interpreted its EV application reporting requirements too narrowly by excluding non-financially-complete projects, and is now ordered to align with PG&E and SDG&E. This directly affects where fast-charging depots and corridor projects can be built without triggering distribution upgrades. - **Interconnection attorneys, consultants, and regulatory teams**. The new reporting regime creates a paper trail for disputes over upgrade requirements, timeline delays, and alleged map inaccuracies. Expect Integration Capacity Analysis concordance data to appear more often in protests, settlement talks, and evidentiary filings. The four-scenario framework and root-cause categories give intervenors a structured basis for challenging utility explanations of ICA discrepancies. - **Utilities' distribution planning and grid modernization teams**. They now face measurable compliance exposure if maps are stale, incomplete, or misaligned with engineering outcomes. This shifts Integration Capacity Analysis from a planning support tool to something closer to a performance metric. SCE has already reduced its inactive circuits from **1,026** to **311** as of December 2025, with full reactivation ordered by **September 30, 2026**. - **Policy watchers and market entrants (microgrids, Virtual Power Plants, community energy)**. The CPUC is shaping the rules for how distributed capacity gets discovered and allocated. The concordance framework will generate the first cross-utility dataset on ICA reliability, which will influence where capital flows in California's next wave of electrification projects. In sum, anyone whose project depends on finding available distribution capacity (generation or load) should care. ICA is moving from "informational map" toward a tool with real regulatory accountability behind it, and the data the Commission is now requiring will determine how far and how fast that transformation goes. ### CPUC Potentially Clears Path for PG&E Data Center Interconnection Facility; Defers Cost Recovery Fights URL: https://www.calregulatory.com/cpuc-potentially-clears-path-for-pg-e-data-center-interconnection-facility-defers-cost-recovery-fights/ Last updated: 2026-02-12T20:43:25.000Z The CPUC issued [Draft Resolution E-5447](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K895/598895478.PDF?ref=calregulatory.com), which approves PG&E's [Advice Letter 7653-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7653-E.pdf?ref=calregulatory.com), authorizing a non-standard Engineering, Procurement, and Construction agreement with [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com) for construction of the 115 kV Ringwood Switching Station in San Jose. The agreement was executed in May 2023, meaning this infrastructure has been in the pipeline for nearly three years before reaching a potential CPUC approval. **TLDR:** Draft Resolution E-5447, which is tentatively scheduled for consideration on **March 19**, approves STACK Infrastructure's build-and-transfer of a switching station for its 90 MW San Jose data center, but limits the decision strictly to construction terms (cost recovery and rate base fights are punted to FERC, where the draft resolution's aside on rate base credits hints at how they'll be resolved). --- The Ringwood facility is a key component of infrastructure needed to energize STACK’s planned 90-megawatt data center load. Under the agreement, STACK will design, procure, and construct the switching station and then transfer ownership to PG&E upon completion. - The draft resolution emphasizes that this approval is limited to the Engineering, Procurement, and Construction agreement itself and does not authorize cost recovery, determine rate base treatment, or modify the refund framework previously adopted by the CPUC for the broader energization project. - Cal Advocates protested PG&E's advice letter, arguing that PG&E should not earn a full rate of return on a customer-financed asset and raising concerns about potential ratepayer exposure to cost overruns. Draft Resolution E-5447 finds these issues outside the scope of this AL disposition, deferring them to the applicable ratemaking forum. - Notably, the draft resolution does not dismiss Cal Advocates' concerns; it explicitly acknowledges the perverse incentive scenario Cal Advocates describes but finds that existing safeguards mitigate it. The draft resolution notes that ratemaking treatment will be addressed in the appropriate forum and that prior modifications to the refund framework (limiting refunds to **75%** of PG&E's annual net transmission revenues from STACK) already provide meaningful ratepayer protection. The draft resolution also includes a pointed contextual aside: "*for context only and without making a ratemaking determination*," it states that customer-provided capital advances (whether in cash or, as here, advanced in-kind through customer construction) are commonly treated as credits offsetting the utility's rate base. Any unrefunded amount would remain as a credit. This suggests likely ratemaking treatment without formally deciding it. ### **INSTANT ANALYSIS** Draft Resolution E-5447 provides insight on how California will handle large new loads trying to self-fund grid upgrades. The draft resolution is allowing a customer-build-and-transfer path to proceed without settling the harder question of whether utilities can later earn returns on those assets. That unresolved tension is where the future fights will occur, especially as data center demand accelerates. The main takeaway: the CPUC will let projects move forward first and push the financial disputes into later proceedings. That sequencing favors speed to energization over upfront clarity on long-term cost treatment. In short, California is not slowing large-load interconnections at the approval stage, even when the ratemaking implications are contested. ### **WHO SHOULD CARE?** - Data center developers and large-load customers. The draft resolution confirms the CPUC will approve customer-built transmission facilities under Rule 15/16 where the broader energization framework is already in place. That matters for timeline certainty. The nearly three-year gap between Engineering, Procurement, and Construction execution and approval demonstrates the patience these projects require. - Utilities facing large interconnection requests. If this draft resolution is approved, PG&E will secure approval of a non-standard Engineering, Procurement, and Construction structure without reopening refund or rate treatment debates. - Transmission and infrastructure investors. The draft resolution is allowing customer-financed, build-and-transfer models to proceed, with refund limits serving as the primary ratepayer safeguard. The rate base credit language, while non-binding, offers a window into how these assets may be treated. - Ratepayer groups. The draft resolution confirms that cost recovery and return treatment fights will be decided in ratemaking venues, not in implementation advice letters. If you track large load growth, transmission cost allocation, or data center siting in California, this is a relevant item. For additional CRI coverage on this matter, visit our [October 30, 2025 CPUC Voting Meeting report](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/): [CPUC authorizes PG&E to revise its gas curtailment processPreviously, PG&E relied solely on localized curtailments to manage pressure on its system of more than 5,600 miles of transmission pipeline![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-29.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Oct-30-2025--13-.png)](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/) ### Draft Resolution Would Advance Utility-Controlled EV Load Management While Deferring Bi-Directional Hardware Support URL: https://www.calregulatory.com/draft-resolution-would-advance-utility-controlled-ev-load-management-while-deferring-bi-directional-hardware-support/ Last updated: 2026-02-12T17:02:14.000Z The CPUC issued [Draft Resolution E-5452](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K873/598873013.PDF?ref=calregulatory.com), which approves with modifications SCE's request to update its [Low Carbon Fuel Standard](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification/charging-infrastructure-deployment-and-incentives/low-carbon-fuel-standard?ref=calregulatory.com) Holdback Implementation Plan to add a new vehicle-grid integration program known as Orchestrated Charging and Advanced Resiliency for Distribution (ORCHARD). **TLDR:** The main storyline is that California is treating EVs primarily as controllable load assets, not compensated grid-export resources. Market participants should plan around that sequencing. The earliest the CPUC will consider this item is **March 19**. *Note: There is no paywall for this post, but if you are finding our reports useful, please consider becoming a* [*paid subscriber*](https://www.calregulatory.com/pricing/) *or* [*inquiring*](https://www.calregulatory.com/contact-us/) *about embedded and personalized intelligence for your firm.* --- ORCHARD would integrate a software layer into SCE’s [Distributed Energy Resource management system](https://www.cgi.com/us/en-us/article/derms-utilities?ref=calregulatory.com) to directly manage residential electric vehicle charging in order to: - Reduce localized distribution peaks caused by Time-of-Use charging patterns; - Defer transformer upgrades; and - Lower system costs. SCE targets enrollment of 25,000 customers on circuits with less than one megawatt of available capacity and at least 100 EVs. The program is limited to light-duty, residential drivers; the draft resolution declines intervenor requests to extend eligibility to medium- and heavy-duty vehicles. The draft resolution authorizes **$11,464,112** in LCFS holdback funds for the orchestrated load management component and approves a **$75** sign-up incentive plus annually declining participation incentives starting at **$50** and reaching **$0** by the customer's fifth year of enrollment. The draft resolution requires SCE to file a supplemental Tier 2 advice letter detailing its budget and methodology for evaluating enrollment and incentive adjustments. The draft resolution denies, without prejudice, SCE's proposed bi-directional charging equipment rebates, finding the justification insufficient. Specifically, SCE proposes no export compensation mechanism and instead relies on the pending [Vehicle Grid Resource Proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M579/K066/579066253.PDF?ref=calregulatory.com) and a Dynamic Rate Pilot that, according to the Commission, lacks sufficient funds to cover the 8,700 targeted bi-directional participants. The draft resolution also identifies ambiguity around required operational modes (Momentary Parallel vs. Isolated) and the associated interconnection requirements. ### **INSTANT ANALYSIS** This draft resolution approves utility-controlled managed charging while rejecting subsidized bidirectional hardware. ORCHARD’s orchestrated load management moves forward; [Vehicle-to-Everything](https://en.wikipedia.org/wiki/Vehicle-to-everything?ref=calregulatory.com) rebates do not. For now, the CPUC is backing distribution deferral through flexible load control, not export-based vehicle-to-grid economics without a defined compensation structure. The Tier 2 advice letter requirement is substantive. SCE must provide detailed budget allocations, attrition and participation thresholds, incentive-adjustment methodology, and analysis of interaction with dynamic rates. That filing will shape whether ORCHARD remains a bounded pilot or becomes a scalable load-flexibility platform. The draft resolution's treatment of the 20% resiliency expenditure requirement is also notable. SCE argued the threshold is "prohibitively difficult" to meet given the narrow definition of resiliency provided by the CPUC in 2020 decision ([D.20-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M356/K223/356223853.PDF?ref=calregulatory.com)). The draft resolution accepts that reasoning (in part because CARB recently added VGI to the pre-approved non-equity holdback project list). That interpretation could influence how PG&E and SDG&E frame their own holdback filings going forward. ### WHO SHOULD CARE? - Utilities' regulatory and grid-planning teams. This draft resolution affirms that managed charging qualifies for LCFS holdback support and can be framed as a distribution deferral tool. The draft resolution also suggests that [Vehicle-to-Everything](https://en.wikipedia.org/wiki/Vehicle-to-everything?ref=calregulatory.com) hardware incentives will face scrutiny absent a defined export compensation pathway. - VGI aggregators and EV software platforms. The Commission is comfortable with utility-orchestrated load control at scale. Vendors positioned around [one-way managed charging](https://fermataenergy.com/sp%5Ffaq/what-is-v1g-unidirectional-smart-managed-or-controlled-charging-and-how-does-this-differ-from-v2x-v2g/?ref=calregulatory.com) and [Distributed Energy Resource Management System](https://www.cgi.com/us/en-us/article/derms-utilities?ref=calregulatory.com) integration have a clearer runway than those anchored in export monetization. - Automotive OEMs and charging manufacturers. Bi-directional capability alone is not enough. Without rate design or compensation mechanisms, hardware-forward Vehicle-to-Grid strategies will struggle to secure ratepayer-backed incentives. - Policy staff tracking legislation and load-shift goals. ORCHARD reinforces that load flexibility, not new infrastructure, is the near-term tool for meeting electrification-driven peak growth. - Energy traders and Resource Adequacy modelers. If orchestrated charging scales, controllable EV load may increasingly factor into distribution planning and future flexible capacity assumptions. ### CARD or Separate Rulemaking? Why PG&E and Storage Providers Are Fighting to Keep ISP Market Scrutiny Out of A.25-11-006 URL: https://www.calregulatory.com/card-or-separate-rulemaking-why-pg-e-and-storage-providers-are-fighting-to-keep-isp-market-scrutiny-out-of-a-25-11-006/ Last updated: 2026-02-12T00:54:41.000Z In [A.25-11-006](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050501.PDF?ref=calregulatory.com), parties filed opening comments on the [draft scope of issues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K051/597051523.PDF?ref=calregulatory.com) for PG&E’s 2027–2030 Gas Cost Allocation and Rate Design (CARD) proceeding. (*CRI's previous CARD coverage is available* [*here*](https://www.calregulatory.com/pg-e-card-filing-first-time-merger-of-the-gcap-and-gt-s-applications/).) [PG&E “CARD” Filing Combines GCAP and GT&SPG&E’s 2027 Gas CARD consolidates GCAP and GT&S into one framework and resets how gas costs are assigned as statewide gas use declines.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-27.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Fri-Nov-21-2025--18-.png)](https://www.calregulatory.com/pg-e-card-filing-first-time-merger-of-the-gcap-and-gt-s-applications/) A recurring concern is "Issue 20" of the draft scope, which asks: > How can the Commission ensure that core customers are charged reasonable rates for storage purchased through the Independent Storage Providers (ISPs) given the concentration of ISP ownership and the proposed increasing dependence of PG&E on ISP storage to meet core peak demand? - Wild Goose Storage and Lodi Gas Storage [argue](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103319.PDF?ref=calregulatory.com) that draft Issue 20 is based on a misunderstanding of the ISP market and should be removed from the final scope. They contend the Commission has repeatedly found Independent Storage Providers lack market power, has approved all ISP tariffs, and recently concluded that ISP contracts did not contribute to the 2022–2023 winter gas price spike. They also note that noncore customer access to ISPs kept the market liquid and reduced gas prices in PG&E's service territory, per the Commission's own [proposed decision in I.23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K227/595227206.PDF?ref=calregulatory.com) (*see CRI's coverage of that item* [*here*](https://www.calregulatory.com/proposed-decision-lands-in-cpucs-natural-gas-price-spike-investigation/)*.*) [PD Lands in CPUC’s Natural Gas Price Spike InvestigationThe PD finds that the winter 2022–2023 natural gas price spike resulted from a convergence of adverse market conditions.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-28.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Nov-25-2025--7-.png)](https://www.calregulatory.com/proposed-decision-lands-in-cpucs-natural-gas-price-spike-investigation/) - Wild Goose and Lodi further emphasize that PG&E's Independent Storage Provider contracts are already subject to a detailed reasonableness review process involving Cal Advocates, TURN, and CPUC approval. Wild Goose and Lodi add that this is a multi-step process adopted in the CPUC's 2019 GT&S decision ([D.19-09-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M314/K894/314894934.pdf?ref=calregulatory.com)), under which PG&E has entered into (or amended) at least 15 ISP contracts for core storage, all approved, and that any broader inquiry into ISP market structure belongs in a separate rulemaking. - Cal Advocates [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101633.PDF?ref=calregulatory.com) the proposed scoping issues but recommends modifying the procedural schedule. Specifically, it opposes PG&E’s proposed **August 18** deadline for intervenor testimony and instead proposes **September 1** citing the complexity of combining Gas Cost Allocation Proceeding and Gas Transmission & Storage issues and uncertainty around related General Rate Case Phase II hearing dates. - PG&E [seeks technical revisions](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100984.PDF?ref=calregulatory.com) to several issues to reflect the combined CARD structure and clarify terminology, and argues that certain proposals — e.g., re-bundling storage costs into transportation rates (Issue 15), implementing new fixed charges in this cycle, or evaluating ISP market concentration — are outside the bounds of its application. - In addition to highlighting several out-of-scope arguments, PG&E identifies nine issues requiring clarification or modification to be properly scoped, including: - Corrections to reflect the combined CARD structure; - Removal of "storage" from the local transmission analysis issue; - A recharacterization of the Baja-Redwood rate differential to reference the backbone paths rather than "PG&E's service territory"; - A specification of "backbone-level end-user service"; and - A clarification that Issue 18 (storage assets to meet the 1-in-10 Reliability Standard) is limited to PG&E's Core Gas Supply and storage cost allocation proposals rather than GRC Phase I storage capacity questions. - Central Valley Gas Storage [similarly requests clarification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101752.PDF?ref=calregulatory.com) of Issue 20\. Central Valley Gas Storage states that if the issue concerns PG&E’s allocation of ISP-related storage costs to core customers, it may be appropriate for this proceeding. However, if it seeks to evaluate the reasonableness of rates charged by ISPs themselves, that inquiry falls outside the scope of a cost allocation case and should occur, if at all, in a dedicated proceeding focused on the ISP market structure. Central Valley Gas Storage proposes narrowing the language of Issue 20 accordingly to avoid expanding the case beyond its intended purpose. ### **INSTANT ANALYSIS** PG&E and all storage providers are aligned: keep ISP market concentration and contract pricing out of this CARD. They argue that if the Commission wants to examine ISP market structure, it should do so in a separate rulemaking, not inside a cost-allocation case. Translation: storage providers want this door closed. The ALJ is deciding whether to leave it slightly open. Beyond Issue 20, the draft scope pushes into territory that PG&E did not propose, particularly on Core Firm Storage Account unbundling (Issue 15) and accelerated fixed charges. These are not minor add-ons. Issue 15 would reverse a quarter-century of procurement rate design, and implementing fixed charges ahead of the [Long-Term Gas Planning docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com)'s resolution could create conflicting policy tracks. If the final scoping memo keeps these issues alive, this proceeding expands well beyond a standard CARD. ### **WHO SHOULD CARE?** - PG&E, SoCalGas, SDG&E. Scope defines risk. If Issue 20 survives, storage procurement and core reliance could face broader scrutiny. That affects contract matters, evidentiary burden, and future storage strategy. If Issue 15 survives, the implications extend to how all California investor-owned utilities structure core storage cost recovery. SoCalGas and SDG&E should be watching for precedent risk even though they are not parties here. - Gas storage providers and investors. This is existential. An expanded ISP inquiry inside CARD creates a cloud of unresolved regulatory risk. Even if nothing changes now, the signal matters for financing and expansion plans. Central Valley Gas Storage's citation of the I.23-03-008 proposed decision (which would limit ISP market reviews to ISP-specific applications) is the strongest legal anchor the storage providers have. If that PD is adopted, it gives storage providers a strong argument to keep this kind of inquiry out of future cost-allocation cases. - Large Industrials. These parties should watch cost allocation. If ISP costs or blending mechanics shift, backbone and core/noncore splits could move. Storage revenue recovery mechanics are not academic. - Core procurement stakeholders/core transport agents (CTAs). Volatility and Core Firm Storage Account mechanics were raised, even if PG&E says they are out of scope. If those matters continue to surface, bill stability and procurement transparency become live issues. Additionally, Issue 15's subparts on CTA-specific transportation rates and storage revenue unbundling directly affect CTAs who secure their own storage. This is not abstract. - Consumer advocates and affordability watchers. Issue 20 ties directly to peak reliability costs flowing into core rates. If dependence on ISP storage grows while throughput declines, the rate design pressure intensifies. The fixed charge questions, if scoped in, could accelerate rate restructuring ahead of PG&E's own timeline, with affordability implications that have not been analyzed in testimony. - Policy observers tracking gas transition risk. The key issue here is the combination of declining load and fixed storage costs. As demand erodes, who carries reliability infrastructure? That question sits underneath the scoping fight. ### WEDNESDAY AGGREGATE: Risk Mitigation Accountability; SoCalGas Gas Line Scope Fight; PG&E Hinkley Emergency Bypass; and POLR Draft Resolution URL: https://www.calregulatory.com/wednesday-aggregate-11/ Last updated: 2026-02-11T23:06:47.000Z Today's roundup covers a wide spectrum of items spanning risk mitigation, gas line extension allowances, Senate Bill 1221, Provider of Last Resort, Diablo Canyon, and natural gas backbone transportation. *Note: There is no paywall for this Wednesday Aggregate, but if you are finding our reports useful, please consider becoming a* [*paid subscriber*](https://www.calregulatory.com/pricing/) *or* [*inquiring*](https://www.calregulatory.com/contact-us/) *about embedded and personalized intelligence for your firm.* --- ### RISK MITIGATION In the CPUC's [Risk-Based Decision-Making Framework proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M344/K081/344081678.PDF?ref=calregulatory.com), Cal Advocates [filed a proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100993.PDF?ref=calregulatory.com) outlining an enforcement framework for utility [Risk Mitigation Accountability Reports](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/safety-policy-division/meeting-documents/rmar-spd-staff-proposal%5F120424.pdf?ref=calregulatory.com), responding to a directive in [D.25-08-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K198/578198350.PDF?ref=calregulatory.com) to develop a clearer accountability structure. Cal Advocates generally supports the[ Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com)’s previously proposed Risk Mitigation Accountability Report enforcement model. That model contemplates escalating responses to infractions depending on the severity, materiality, and impact of reporting errors or failures to meet risk mitigation commitments. However, Cal Advocates recommends two key modifications: - First, that any Safety Policy Division warning emails or notices of violation, along with documentation of final resolution, be formally filed and served in the utility’s current General Rate Case proceeding and appended to its next General Rate Case application to ensure transparency and Commission oversight; and - Second, that any corrective actions required due to insufficient progress, reporting deficiencies, or non-compliance be funded by shareholders rather than ratepayers. The proposal also introduces a political accountability mechanism for utilities demonstrating insufficient progress toward adopted risk reduction or benefit-cost ratio metrics. Under this process, utilities would be required to: - Send letters to the CPUC, the Governor's Office, and the [California State Assembly's Committee on Utilities and Energy](https://autl.assembly.ca.gov/?ref=calregulatory.com) explaining their remediation plans; and - Host a workshop or en banc within six months detailing their progress. The proposal emphasizes tying ratepayer funding to demonstrable, cost-effective risk reduction outcomes and strengthening the Commission’s ability to hold utilities accountable for both the accuracy of Risk Mitigation Accountability Report filings and compliance with adopted General Rate Case risk mitigation requirements. **INSTANT ANALYSIS**: Cal Advocates is trying to embed Risk Mitigation Accountability Report enforcement directly into the General Rate Case cycle. By requiring violations to be filed in active rate cases and appended to future applications, the proposal would turn reporting deficiencies into litigation leverage. More consequential is the proposed cost-allocation shift. Missed risk mitigation metrics or non-compliance would trigger shareholder-funded corrective actions. If adopted, the Risk Mitigation Accountability Report becomes a potential earnings risk mechanism, not just a reporting tool. --- ### SOCALGAS – GAS LINE EXTENSION ALLOWANCE In [A.25-07-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M571/K244/571244390.PDF?ref=calregulatory.com), SoCalGas filed an [objection](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100998.PDF?ref=calregulatory.com) seeking to exclude portions of Sierra Club testimony from the evidentiary record in its pending gas line extension allowance proceeding. SoCalGas argues that the challenged testimony is inadmissible on two distinct grounds: - First, that Sierra Club improperly relies on findings from prior General Rate Case decisions to argue that methane-fueled vehicle infrastructure is categorically inconsistent with state climate policy (an argument SoCalGas characterizes as a collateral attack on [D.22-09-026](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M496/K987/496987290.PDF?ref=calregulatory.com), which expressly created the annual application process for individual project review); and - Second, that Sierra Club's testimony regarding project siting in disadvantaged and Environmental and Social Justice communities falls outside the proceeding's scope because D.22-09-026 expressly declined to adopt ESJ location as an eligibility criterion. According to SoCalGas, the proceeding is limited to evaluating whether proposed projects satisfy the three eligibility criteria established in D.22-09-026: demonstrable greenhouse gas reductions, consistency with California climate goals, and lack of feasible non-gas alternatives. SoCalGas maintains that Sierra Club's references to past General Rate Case rulings, stranded asset concerns, and ESJ-based siting arguments constitute policy advocacy and an attempt to relitigate prior Commission decisions, rather than admissible evidence relevant to the specific criteria at issue. Notably, SoCalGas concedes that if the challenged Sierra Club testimony is excluded, its own rebuttal testimony responding to those portions should likewise be struck, a concession that reflects confidence in the objection. **INSTANT ANALYSIS:** This is a scope fight. SoCalGas is defending D.22-09-026 as a contained eligibility test: GHG reduction, climate consistency, and no feasible non-gas alternative. Sierra Club is attempting to fold prior General Rate Case methane rulings and ESJ findings into the proceeding framework. If the objection is sustained, line extension allowance review stays technical and project-specific. If overruled, methane policy and siting disputes gain a foothold inside future allowance proceedings. The CPUC's response will determine whether D.22-09-026 functions as a narrow subsidy mechanism or absorbs broader decarbonization enforcement pressures. --- ### SENATE BILL 1221 SoCalGas/SDG&E filed [a reply](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103301.PDF?ref=calregulatory.com) in the CPUC's [Long-Term Gas Planning](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com) docket defending their motion to amend their existing [Senate Bill 1221](https://legiscan.com/CA/text/SB1221/id/3022645?ref=calregulatory.com) memorandum accounts to track incremental, verifiable costs incurred in complying with a 2025 decision ([*D.25-12-042*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234578.pdf?ref=calregulatory.com)*; see CRI's coverage of that decision* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)). [December 18 CPUC Voting Meeting ResultsCovers: Cost of Capital; Long-Term Gas Planning; the Woolsey Fire![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-24.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Dec-17-2025-3.png)](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/) Responding to [objections from the Indicated Shippers](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K279/596279562.PDF?ref=calregulatory.com), the utilities argue that no petition for modification is required because they are not seeking to revise a prior decision, but merely to record costs associated with new Commission directives tied to SB 1221 implementation. The utilities note that [PG&E filed a similar motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K217/592217080.PDF?ref=calregulatory.com) on December 23, 2025, and no party objected, underscoring the selective nature of the Indicated Shippers' challenge. - SoCalGas/SDG&E emphasize that the request concerns tracking only (not cost recovery) and is necessary to avoid retroactive ratemaking concerns while ensuring transparent accounting. - The specific costs at issue relate to directed compliance activities under D.25-12-042: stakeholder outreach, hosting and recording a virtual SB 1221 information session with interpretation services, and filing a report by April 1, 2026\. - SoCalGas/SDG&E contend that D.25-12-042 expressly contemplates such motions and that their proposal aligns with both the statutory framework of SB 1221 and prior Commission precedent allowing memorandum accounts for unforeseeable, legislatively directed gas system activities. If the Commission prefers an alternate procedural vehicle, the utilities request that the original motion’s filing date govern the start of cost recordation. **INSTANT ANALYSIS**: This is a procedural skirmish with longer-term implications. The utilities are only seeking authority to track incremental SB 1221 compliance costs tied to D.25-12-042, not recover them. But once tracking is authorized, future recovery debates shift to reasonableness rather than eligibility. If granted, the motion reinforces a streamlined pathway for incorporating new SB 1221 directives into existing memo accounts, reducing friction as long-term gas planning obligations expand. The immediate dollars are modest. The precedent is not. --- ### PROVIDER OF LAST RESORT The CPUC issued [Draft Resolution E-5411](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M598/K879/598879783.PDF?ref=calregulatory.com), which denies SDG&E's request for review of Energy Division’s disposition denying Advice Letter 4475-E, which had sought to preemptively establish a memorandum account to track incremental administrative and procurement costs in the event of a mass involuntary return of customers to Provider of Last Resort service **Background** SDG&E argued that it needed the account in place ahead of any Community Choice Aggregator failure to ensure uninterrupted service and full cost recovery. The Commission disagreed, clarifying that the 2024 POLR Standards Decision ([D.24-04-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M529/K986/529986322.PDF?ref=calregulatory.com)) permits (but does not require) a memorandum account as an alternative tool for calculating reentry fees, and that procurement costs remain recoverable through the annual [Energy Resource Recovery Account](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com) process regardless of whether such an account is opened. **Draft Resolution E-5411** - Draft Resolution E-5411 emphasizes that opening a memorandum account in advance would assume that actual cost tracking is appropriate in all return scenarios, contrary to the discretion framework adopted in D.24-04-009\. - The draft resolution draws a practical distinction: a memorandum account may be necessary in a large-scale unplanned return (such as a failure of [San Diego Community Power](https://sdcommunitypower.org/?ref=calregulatory.com), whose customer load exceeds SDG&E's current bundled base) but could be costlier and unnecessary for a small planned return, such as from [Clean Energy Alliance](https://thecleanenergyalliance.org/?ref=calregulatory.com), where incremental procurement costs could be forecasted and absorbed through the Financial Security Requirement calculator. - Instead, the draft resolution affirms that if a Tier 2 financial trigger indicates material risk of CCA failure, SDG&E may then file a Tier 1 advice letter to establish the account. The draft resolution also confirms that CPUC staff will notify the Provider of Last Resort when a CCA appears at material risk, subject to confidentiality limits, to provide sufficient preparation time. However, the draft resolution acknowledges SDG&E's concern that the Provider of Last Resort is not part of the financial monitoring process and that CCAs would likely object to such notification (an issue that remains unresolved and may surface in Phase 2 of the Provider of Last Resort rulemaking). The earliest the CPUC will consider this item is **March 19**. **INSTANT ANALYSIS:** This draft resolution limits the Provider of Last Resort memorandum account to trigger-based use. SDG&E cannot preemptively establish cost tracking; the Financial Security Requirement calculator remains the default reentry fee mechanism. However, the Commission's practical distinction between large and small returns signals that the memorandum account is envisioned primarily for significant, unplanned CCA failures. Procurement costs remain recoverable through ERRA regardless. The memorandum account only affects how reentry fees are calculated and assessed to returning customers. The draft resolution also commits to notifying the Provider of Last Resort when a CCA is at significant risk, though the mechanism for that notification remains undefined. Bottom line: actual cost tracking remains available, but only situationally and under CPUC control. --- ### NATURAL GAS – INTERSTATE CAPACITY SoCalGas filed Advice Letter 6599-G (available [here](https://tariffsprd.socalgas.com/scg/filings/?ref=calregulatory.com)), requesting expedited Commission approval of two interstate capacity contracts with the [Kern River Gas Transmission Company](https://www.brkenergy.com/our-businesses/kern-river-gas-transmission-company?ref=calregulatory.com) under the streamlined process authorized in a 2004 decision (D.04-09-022). SoCalGas states that Cal Advocates does not oppose the contracts following consultation, while TURN did not participate in the review. Protests are due **February 17**. **INSTANT ANALYSIS:** The AL's heavy confidentiality is par for the course but suggests active portfolio management, not a passive renewal. For shippers and large customers, added Kern River commitments can influence border optionality and backbone flows. --- ### NATURAL GAS – INTERRUPTIBLE TRANSPORTATION SERVICE SoCalGas submitted Advice Letter 6598-G (available [here](https://tariffsprd.socalgas.com/scg/filings/?ref=calregulatory.com)), seeking Commission approval of a First Amendment to its existing Interruptible Transportation Service Agreement with Gasoducto de Aguaprieta, S. de R.L. de C.V. (formerly [Gasoducto Rosarito](https://www.gasoductorosarito.com/?ref=calregulatory.com)). - The amendment updates the agreement to reflect regulatory changes adopted by Mexico’s Energy Regulatory Commission for the Gasoducto Rosarito pipeline system, including revised regulated rates and system segmentation. - Operationally, the agreement continues to provide interruptible transportation service of up to 200,000 Dth per day between the [North Baja Pipeline](https://tcplus.com/North%20Baja?ref=calregulatory.com) interconnect near Los Algodones at the U.S.-Mexico border and [Transportadora de Gas Natural de Baja California](https://www.tgndebajacalifornia.com/?l=en&ref=calregulatory.com) near Tijuana. Protests are due **February 25**. **INSTANT ANALYSIS:** This is a standard housekeeping update, but it matters. SoCalGas is aligning its cross-border interruptible transport contract with new rates and pipeline definitions adopted by Mexico’s regulator for the Rosarito system. No California rates change. No new capacity is added. The practical impact is administrative continuity. Nominations and billing stay synchronized across the border, reducing settlement friction for traders and preserving operational flexibility tied to Baja flows. --- ### DIABLO CANYON PG&E filed [Advice Letter 7834-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7834-E.pdf?ref=calregulatory.com), seeking CPUC approval to revise its electric tariffs to implement the directives of a decision from last December (D.25-12-007), which approved the 2026 Diablo Canyon extended operations forecast, the Volumetric Performance Fee spending plan, and related cost recovery mechanisms. (*See CRI's coverage of that decision* [*here*](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/)*.*) [December 4, 2025 CPUC Voting Meeting ResultsThe CPUC’s meeting included attempts to impose methodological discipline on billion-dollar capital programs![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-25.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-08-2025--12--2.png)](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/) PG&E proposes updates to the Department of Energy Litigation Balancing Account to create a new “Extended Operations” subaccount to track DOE litigation proceeds and associated costs attributable to Diablo Canyon Extended Operations Balancing Account activities, consistent with the decision’s allocation framework. The revisions also update allocation percentages for DOE settlement credits across generation, extended operations, and nuclear decommissioning customers for 2026–2030, and establish monthly accounting and interest procedures for the new subaccount. Protests are due **March 2**. **INSTANT ANALYSIS:** This is a compliance filing, but it's notable. PG&E is proposing a new extended operations subaccount within its Department of Energy litigation balancing account to route federal reimbursement proceeds tied to Diablo Canyon into the dedicated extended operations cost-recovery mechanism This move formalizes the 2026–2030 allocation percentages among generation customers, extended operations customers, and nuclear decommissioning customers, shaping how future federal credits offset Diablo Canyon costs. No immediate rate change will result from this filing, but the structures it proposes will determine where settlement dollars flow. --- ### PG&E COMPRESSOR STATION UPGRADES PG&E submitted [Advice Letter 5175-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5175-G.pdf?ref=calregulatory.com), formally noticing its decision to proceed with the above-**$75-million**\-threshold S-238 Hinkley Compressor Station Electrical Upgrades Project under the emergency exemption in [General Order 177](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com), rather than awaiting a [CPCN](https://en.wikipedia.org/wiki/Certificate%5Fof%5Fpublic%5Fconvenience%5Fand%5Fnecessity?ref=calregulatory.com) decision *(see related coverage from CRI* [*here*](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/)). [PG&E Looks to Bypass CPCN Review for Hinkley ProjectTopics covered: PG&E’s S-238 Hinkley Compressor Station Electrical Upgrades Project; PG&E’s Billing Modernization Initiative![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-23.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Jan-28-2026--10-.png)](https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/) - PG&E states that recent component failures and accelerating obsolescence (emerging after its April 2025 CPCN application) created a risk that the station’s aging electrical distribution equipment could fail before the Commission issues a decision later this year. - Because the Hinkley station supports backbone Lines 300A and 300B on the [Baja Path](https://www.pge.com/en/newsroom/currents/hometowns/a-gas-pipeline-that-changed-california--celebrating-75-years-of-.html?ref=calregulatory.com) and is critical to maintaining system-wide gas pressure, PG&E argues that an unplanned outage could trigger Emergency Flow Orders or curtailments affecting customers across its gas system. PG&E began construction on January 20, 2026, including installation of temporary generators to bypass vulnerable equipment, and expects completion by January 2028\. With the project now underway pursuant to GO 177, PG&E has separately moved to withdraw the CPCN application, arguing that the proceeding no longer serves a purpose and that future review will shift to cost recovery in upcoming General Rate Cases rather than prospective project authorization. **INSTANT ANALYSIS**: PG&E has now moved Hinkley fully into the GO 177 emergency lane, with construction already underway. If the Commission grants the withdrawal, the CPCN proceeding ends without a ruling on project necessity, and review shifts to later GRC cost recovery after capital is spent. At issue is precedent. GO 177 exists to prevent delays during real emergencies. Here, a project already in CPCN review is being reclassified midstream. If that stands, the practical bar for invoking “anticipated emergency” on major backbone work drops. For shippers and large customers, leverage narrows to rate treatment. For advocates and staff, this becomes a test of how much prospective review can be bypassed when reliability risk is asserted. ### IOUs Respond to Resolution SPD-37 with a Unified Playbook for Senate Bill 884 Cost Recovery URL: https://www.calregulatory.com/ious-respond-to-resolution-spd-37-with-a-unified-playbook-for-senate-bill-884-cost-recovery/ Last updated: 2026-02-12T19:50:35.000Z PG&E, SCE, and SDG&E jointly filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101196.PDF?ref=calregulatory.com) with the CPUC seeking approval of standardized methodologies to implement [Senate Bill 884’s 10-year electric distribution undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). The filing is a response to [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) (*see CRI's summary* [*here*](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/)). It asks the CPUC to approve a common benefit-cost ratio calculation methodology, an audit framework, and portfolio-level cost-recovery conditions applicable only to SB 884 undergrounding projects. [December 4, 2025 CPUC Voting Meeting ResultsThe CPUC’s meeting included attempts to impose methodological discipline on billion-dollar capital programs![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-22.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-08-2025--12--1.png)](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/) ### Who Should Care? - Utility regulatory affairs and wildfire mitigation teams. This filing will impact how SB 884 undergrounding is evaluated, audited, and recovered, with direct consequences for execution risk, financing, and internal prioritization across large portfolios. - [CPUC Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) and Energy Division staff. The proposal tests whether SPD-37 will be implemented as a portfolio framework aligned with the [Risk-Based Decision-Making Framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/r-20-07-013?ref=calregulatory.com), or evolve into a more interventionist, project-specific review regime. - Investor-owned utility finance and treasury teams. Portfolio-level benefit-cost ratio and predictable audit standards influence capital planning, cost of capital, and the ability to pace multi-year undergrounding investments. - Ratepayer and consumer advocates. The outcome here will affect how strictly costs are constrained, how benefits are measured, and whether oversight focuses on system-level performance or individual project outcomes. ### Summary of the IOUs' Application The utilities argue that the benefit-cost ratio methodology should align with the CPUC’s existing Risk-Based Decision-Making Framework. They call for a consistent approach across [Energy Safety](https://energysafety.ca.gov/?ref=calregulatory.com)’s project-selection phase and the CPUC’s cost-recovery phase, rather than adopting project-specific or novel methods that could introduce uncertainty or financing risk Under their proposal, undergrounding projects would be evaluated using a standardized benefit-cost ratio that compares total mitigation benefits (including wildfire risk reduction, reliability improvements, and public-safety benefits) to the present value of total implementation costs, including: - Capital expenditures; and - Net operations and maintenance impacts. Total mitigation benefits would encompass not just wildfire risk reduction but also standard reliability benefits from distribution overhead asset failures and public-safety benefits from public contact with electrical equipment (categories that broaden the benefit-cost ratio numerator beyond wildfire alone and improve the economic case for undergrounding). --- The utilities also propose clear rules for discount rates, risk scaling, backcasting when models change, and a single "BCR Year Zero" tied to the effective date of a utility's undergrounding plan to preserve comparability across projects. On the [Interruption Cost Estimate Calculator](https://icecalculator.com/?ref=calregulatory.com) (which sets the standard dollar value of reliability risk used in benefit-cost ratio calculations) the IOUs propose continuing to use version 2.0 rather than immediately adopting the newer Interruption Cost Estimate 2.1, coordinating any update with risk model version changes as defined in the [Energy Safety EUP Guidelines](https://efiling.energysafety.ca.gov/eFiling/Getfile.aspx?fileid=58006&shareable=true&%5Fgl=1%2A12y69pz%2A%5Fga%2ANTExMTYzMjI5LjE3NTk2MDczMDg.%2A%5Fga%5F69TD0KNT0F%2AczE3NzA3NTU5MDYkbzEzJGcxJHQxNzcwNzU2MTk5JGo2MCRsMCRoMA..%2A%5Fga%5F340RFMFNWY%2AczE3NzA3NTU5MDYkbzYkZzEkdDE3NzA3NTYyMDAkajYwJGwwJGgw%2A%5Fga%5FDCP197HRSL%2AczE3NzA3NTU5MDYkbzYkZzEkdDE3NzA3NTYyMDAkajYwJGwwJGgw&ref=calregulatory.com). In parallel, the application lays out a detailed audit methodology to verify compliance with annual cost caps, average unit-cost limits, and minimum benefit-cost ratio thresholds at the portfolio level. Each IOU would define its own criteria for determining when a project is "used and useful," introducing some asymmetry into what is otherwise pitched as a joint standardized framework. This methodology would also confirm that projects are used and useful and that costs are incremental to amounts already authorized in general rate cases. The IOUs request a 2% variance threshold on the portfolio-level cost recovery conditions. Under this proposal, a utility could exceed its annual cost cap, unit cost target, or benefit-cost ratio threshold by up to 2% before any projects would need to be moved to the memorandum account for further reasonableness review. At program scale, this tolerance represents meaningful financial flexibility. --- The application also asks the CPUC to allow utilities to select undergrounding over a cheaper alternative mitigation when the undergrounding benefit-cost ratio is within 70% of the alternative's benefit-cost ratio (what the IOUs call an "estimate uncertainty factor"). In those cases, utilities would supplement the modeling with qualitative assessments of ingress/egress risk, tree-strike risk, and [Public Safety Power Shutoff](https://www.cpuc.ca.gov/psps/?ref=calregulatory.com) dynamics. PG&E previously applied a 50% uncertainty range but narrowed it to 30% after Energy Safety's recommendation in the 2026–2028 Base Wildfire Mitigation Plan (the 70%-of-alternative threshold and the 30% estimate uncertainty range are two expressions of the same concept, not separate provisions). This provision is particularly likely to draw intervenor scrutiny. Last, the IOUs seek to grandfather previously scoped undergrounding projects into the EUP even if those projects were selected under older risk models and cannot demonstrate compliance with current Energy Safety screening requirements. The utilities argue that canceling projects already in planning (where land rights, municipal coordination, and community engagement are underway) would be disruptive and wasteful. Protests and responses are due **March 16**. ### **INSTANT ANALYSIS** PG&E, SCE, and SDG&E are pressing the Commission to ground benefit-cost testing, audits, and cost recovery in the existing Risk-Based Decision-Making Framework, rather than allowing SPD-37 to drift toward a bespoke or project-by-project construct. The main concern is risk containment. A standardized, portfolio-level benefit-cost ratio and audit structure: - Reduces financing uncertainty; - Preserves flexibility to manage execution variability across many circuit segments; and - Limits after-the-fact challenges to individual projects. If the Commission accepts the IOUs' approach, SB 884 undergrounding will operate much more like a General Rate Case-style portfolio with defined guardrails, rather than a sequence of individualized prudency reviews. But the asks go beyond framework alignment. The 2% variance threshold, the 70% estimate uncertainty factor, the broadened benefit categories, and the grandfathering of previously scoped projects all push in the same direction: maximizing the volume of undergrounding that qualifies for streamlined cost recovery. Expect intervenors to argue that these provisions, taken together, weaken the cost discipline that SPD-37 was designed to impose. ### CPUC Freezes Spring Residential Climate Credits, Eyes Summer Bill Relief for IOU Customers URL: https://www.calregulatory.com/cpuc-freezes-spring-residential-climate-credits-eyes-summer-bill-relief-for-iou-customers/ Last updated: 2026-02-10T22:52:13.000Z CPUC **President Alice Reynolds** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101732.PDF?ref=calregulatory.com) in [R.25-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com) (the Climate Credit rulemaking) ordering PG&E, SCE, and SDG&E to pause distribution of the 2026 residential electric [Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) while it considers moving the credit to higher-billed summer months later this year. ### Who Should Care? - Utility regulatory affairs and rates teams at PG&E, SCE, and SDG&E, who will need to adjust billing, customer communications, and internal planning around Climate Credit timing for 2026\. - Affordability and consumer advocates, since this move sets up a likely shift of credits into summer months when bill pressure is highest. - Large energy users and Community Choice Aggregators, as this reflects a broader Commission willingness to actively manage bill credits as an affordability tool rather than a passive, calendar-based practice. - Policy and legislative watchers, because the decision shows how [Assembly Bill 1207](https://icapcarbonaction.com/en/news/california-extends-cap-and-trade-2045-renames-program-cap-and-invest?ref=calregulatory.com)’s “high-billed months” requirement is being interpreted and enforced in real time. ### Proposed Decision The Climate Credit, funded through California’s [Cap-and-Invest](https://ww2.arb.ca.gov/our-work/programs/cap-and-invest-program?ref=calregulatory.com) program, is currently delivered in the spring and fall, but recent statutory changes under Assembly Bill 1207 require electric credits to be provided in no more than four high-billed months to maximize affordability. The PD concludes that allowing the spring 2026 credit to proceed as scheduled would violate the Public Utilities Code, which explicitly requires distribution in high-billed months (and spring is historically a low-bill period for electric customers). The 2026 credits are also 40% to 60% smaller than their 2025 counterparts, making timing even more consequential for affordability impact. Pausing the spring distribution preserves flexibility for a forthcoming March 2026 decision that is expected to address timing and shift delivery into summer months when bill relief would be more meaningful. The pause applies only to large electric utilities' residential credits. Small business and industrial Climate Credits are not affected, and the proceeding remains open. Comments are due **March 2**. The earliest the CPUC will consider this item is **March 19**. ### Instant Analysis This PD is a timing maneuver, not a change to Climate Credit amounts or eligibility. By pausing the spring 2026 residential electric Climate Credit, the Commission is preserving the option to redeploy those dollars into summer billing cycles. For PG&E, SCE, and SDG&E, this creates short-term implementation uncertainty but avoids locking in a low-impact spring distribution of already reduced 2026 credits. The move also indicates that, going forward, Climate Credit timing is likely to be treated as an affordability tool rather than a fixed, twice-annual administrative practice, an important precedent for utilities’ billing, customer communications, and future Cap-and-Invest revenue planning. Note that while the Small Business Climate Credit is explicitly not paused, a 2021 decision ([D.21-08-026](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M402/K296/402296732.PDF?ref=calregulatory.com)) links Small Business Credit timing to residential Credit timing. The PD goes out of its way to clarify that linkage does not apply here, but implementation teams should be aware of the potential for confusion. ### MONDAY AGGREGATE: IOU Cost Discipline Following Senate Bill 254; PG&E Cost of Capital Adjustments; LCFS and EV Program Volatility URL: https://www.calregulatory.com/monday-aggregate-iou-cost-discipline-following-senate-bill-254-pg-e-cost-of-capital-adjustments-lcfs-and-ev-program-volatility/ Last updated: 2026-02-10T22:53:13.000Z Today's roundup has a heavy emphasis on PG&E. - **WILDFIRE COST RECOVERY**: In PG&E's 2027 General Rate Case proceeding, several parties have responded to an amended scoping memo, with thoughts on how [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com) should affect the use of wildfire mitigation memorandum accounts in this GRC. EPUC, joined by the [California Large Energy Consumers Association](https://cleca.org/?ref=calregulatory.com), [filed the most aggressive comments](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100963.PDF?ref=calregulatory.com), invoking the CPUC's [own February 2025 response](https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to-executive-order-n-5-24.pdf?ref=calregulatory.com) to [Executive Order N-5-24](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com). The CPUC's response, they note, found that wildfire mitigation costs totaled approximately **$24 billion** in ratepayer collections from 2019-2024, and that multiple recovery venues decreased transparency. - **COST OF CAPITAL**: PG&E is proposing to modify several gas and electric revenue adjustment mechanisms. These changes, if approved, would allow interest savings from future draws on a Department of Energy loan (excluded from PG&E's authorized 2026 cost of debt) to be returned to customers. - **ELECTRIC VEHICLES:** PG&E is looking to add **$18 million** to the budget of its "[Pre-Owned Electric Vehicle Rebate Program](https://evrebates.pge.com/?ref=calregulatory.com)" in order to keep the program open and issuing rebates through the end of 2026\. PG&E's request demonstrates how Low Carbon Fuel Standard revenues are functioning as a flexible backstop for EV programs during periods of market volatility More detail is available below. --- ### PG&E – GENERAL RATE CASE Parties recently weighed in on how [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com) should reshape the use of wildfire mitigation memorandum accounts in [PG&E’s 2027 General Rate Case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com). Their comments showcase a split between utilities seeking continued flexibility, and ratepayer advocates pressing for stricter discipline and the closure of existing accounts. The impetus for these comments was a [January 26 amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K143/596143006.PDF?ref=calregulatory.com). - [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101607.PDF?ref=calregulatory.com) and SDG&E argue that SB 254 does not mandate closure of existing wildfire mitigation plan and fire risk mitigation memorandum accounts. [SoCalGas joins SDG&E's response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103268.PDF?ref=calregulatory.com) only with respect to Question 4 in the amended scoping memo, concerning requirements or guidance for demonstrating that costs are "unforeseen and incremental." - SCE and SDG&E emphasize that wildfire risk, technology, and regulatory requirements continue to evolve between General Rate Case cycles, and that alignment between Wildfire Mitigation Plans and GRCs will not fully occur until the early 2030s (SCE projects its own alignment at 2033, SDG&E at no earlier than 2032). Until that alignment is achieved, both utilities contend, memorandum accounts remain necessary to address unforeseen and incremental safety needs that cannot reasonably be forecast years in advance, with reasonableness reviews preserving Commission oversight. - SDG&E also raises a distinct argument tied to SB 254's compliance provisions: the legislation now allows fines for any degree of Wildfire Mitigation Plan non-compliance and more closely ties compliance to the safety certificates that are existential for electrical corporations under the Wildfire Fund framework. SDG&E frames this as requiring continued financial flexibility to achieve approved safety goals. - Both SDG&E and PG&E independently argue that the policy and statutory interpretation questions raised by SB 254 should be addressed in an all-utility rulemaking rather than a single GRC. - PG&E [advances a similar position](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100965.PDF?ref=calregulatory.com), asserting that immediate closure of the Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account would be premature and inconsistent with SB 254's structure. PG&E stresses that statutory discretion over memorandum accounts was tied to future alignment of Wildfire Mitigation Plan and GRC cycles, which has not yet occurred for PG&E and will not occur until at least its 2031 GRC. PG&E argues that without these accounts, it would lack a viable mechanism to recover costs for genuinely unforeseen mitigation measures implemented to reduce catastrophic wildfire risk. - In contrast, [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101827.PDF?ref=calregulatory.com), TURN, and the Energy Producers and Users Coalition (a.k.a. EPUC, joined by the [California Large Energy Consumers Association](https://cleca.org/?ref=calregulatory.com), a.k.a. CLECA) read SB 254 as a deliberate pivot away from routine reliance on memorandum accounts. They argue that the statute reflects legislative concern over rising wildfire-driven rate pressures and is intended to force utilities to forecast and manage most wildfire mitigation costs within GRC revenue requirements. These parties maintain that PG&E has now had multiple GRC cycles to internalize wildfire mitigation spending and that the original justification for broad memorandum accounts has mostly dissipated. They point to declining balances in the Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account in recent years as evidence that remaining costs are manageable within authorized budgets. - TURN [provides the most granular spending data](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101720.PDF?ref=calregulatory.com), showing combined Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account recorded costs dropping from over **$1 billion** in 2022 to roughly **$40 million** in each of 2023 and 2024 (a figure TURN characterizes as trivial relative to PG&E's **$13.5–14.2 billion** total GRC revenue requirement). TURN also introduces a nuanced incrementality standard drawn from multiple reasonableness review decisions: completing new work by redirecting existing authorized resources does not constitute an incremental cost, even if the activity itself is new. - EPUC/CLECA [filed the most aggressive comments](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100963.PDF?ref=calregulatory.com), invoking the CPUC's [own February 2025 response](https://www.cpuc.ca.gov/-/media/cpuc-website/industries-and-topics/reports/cpuc-response-to-executive-order-n-5-24.pdf?ref=calregulatory.com) to [Executive Order N-5-24](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com), which found that wildfire mitigation costs totaled approximately **$24 billion** in ratepayer collections between 2019 and 2024 and that multiple recovery venues decreased transparency. - EPUC/CLECA also draws an analogy to the Catastrophic Event Memorandum Account framework as the appropriate template for any future "unforeseen and incremental" standard (a framework none of the other parties invoke). - On the question of closing existing accounts, Cal Advocates would stop recording costs effective **January 1, 2027** and close the accounts once balances through **December 31, 2026** have been considered and discharged, while TURN and EPUC/CLECA call for immediate closure. **INSTANT ANALYSIS:** This dispute is about cost discipline in the wake of SB 254\. Ratepayer advocates are pushing to collapse wildfire mitigation spending back into the GRC process, forcing utilities to forecast more precisely and live within authorized budgets. Utilities are defending memorandum accounts as a pressure-release valve while Wildfire Mitigation Plan and GRC cycles remain misaligned and mitigation tools keep evolving. The strongest counterargument to a pure cost-discipline framing comes from SDG&E, which ties memorandum account continuation to the safety certification process, arguing that removing financial flexibility to achieve WMP compliance could jeopardize the certificates that are essential to utility operations under the Wildfire Fund. Whether that argument carries weight with the CPUC or reads as leveraging safety concerns to preserve spending flexibility will be telling. If the Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account remain open, SB 254 comes off as a soft constraint, with continued after-the-fact review. If the accounts are closed or narrowed, wildfire mitigation becomes a front-loaded planning exercise, with fewer opportunities to socialize cost overruns later. The outcome will shape both rate trajectory and utility risk tolerance beyond this particular GRC. --- ### PG&E – COST OF CAPITAL PG&E submitted an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5174-G.pdf?ref=calregulatory.com) to modify several gas and electric revenue adjustment mechanisms. These changes allow for any interest savings from future draws on a Department of Energy loan (excluded from the authorized 2026 cost of debt) to be returned to customers, as required by the 2026 Cost of Capital decision ([*D.25-12-043*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com)*; see CRI's coverage* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)*.*) [December 18 CPUC Voting Meeting ResultsCovers: Cost of Capital; Long-Term Gas Planning; the Woolsey Fire![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-21.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Dec-17-2025-2.png)](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/) The CPUC authorized a **5.04%** cost of long-term debt for 2026 but required PG&E to calculate and return any savings if DOE loan draws occur, since those loans carry a lower cost of debt. PG&E excluded the DOE loan's lower borrowing cost from its requested long-term debt rate because of uncertainty around the draw schedule. Because PG&E has not yet drawn on the loan, the filing is procedural and forward-looking, updating the accounting rules for multiple accounts so any future interest savings can flow back to customers through the annual electric and gas true-up processes. Protests are due **February 24**. **INSTANT ANALYSIS:** This filing is mechanical compliance, not a policy shift. PG&E is pre-wiring its balancing and adjustment accounts so any interest savings from future DOE loan draws can be credited back to customers without reopening ratemaking disputes. The filing preserves the Commission’s approved 2026 cost of debt while ensuring that lower-cost federal financing, if used, does not become a shareholder windfall. Once DOE funds are drawn, PG&E can flow credits automatically through existing true-up channels, limiting both timing risk and litigation leverage for intervenors. There is no near-term rate effect, but it reduces friction around how and when federal financing benefits are returned to ratepayers. --- ### PG&E – ELECTRIC VEHICLES PG&E filed [Advice Letter 7831-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7831-E.pdf?ref=calregulatory.com), seeking CPUC approval to add **$18 million** to the budget of its "[Pre-Owned Electric Vehicle Rebate Program](https://evrebates.pge.com/?ref=calregulatory.com)" in order to keep the program open and issuing rebates through the end of 2026\. The program, originally approved as part of PG&E’s Low Carbon Fuel Standard holdback implementation plan and funded entirely with LCFS revenues, experienced significantly higher-than-forecast rebate demand in 2025, driven by: - Accelerated purchases ahead of the federal EV tax credit’s expiration; - Increased participation by income-qualified customers receiving higher “Rebate Plus” incentives; and - Expanded marketing and community outreach. Consequently, PG&E reports that approximately **$8.6 million** in rebate spending was effectively pulled forward from 2026 into 2025, leaving an estimated **$16 million** in uncommitted funds for 2026\. This creates a projected funding gap that could force a suspension of new applications as early as June 2026 absent supplemental funding. PG&E argues that uninterrupted operation of the program is important to avoid market disruption, protect access for income-qualified customers, and maintain continuity across its broader residential EV portfolio. It emphasizes that the requested budget increase would not affect rates. Protests are due **February 26**. **INSTANT ANALYSIS:** This filing reflects PG&E managing program continuity risk created by forecast error rather than proposing any expansion of scope or incentives. Higher-than-expected 2025 participation effectively pulled LCFS-funded rebate dollars forward, leaving the Pre-Owned EV Rebate Program exposed to a mid-year funding shortfall in 2026 absent CPUC action. The request demonstrates how LCFS revenues are functioning as a flexible backstop for EV programs during periods of market volatility, particularly around the federal tax credit phase-out. Approval would preserve uninterrupted program operations through 2026 and clear the path for a more deliberate 2027 extension, while denial would force a pause that would fall most heavily on income-qualified customers and disrupt PG&E’s broader Transportation Electrification portfolio. ### High DERs Update: How the CPUC Treats New Electrification Study Will Determine Billions in Utility Spending Authority URL: https://www.calregulatory.com/high-ders-update-how-the-cpuc-treats-new-electrification-study-will-determine-billions-in-utility-spending-authority/ Last updated: 2026-02-07T00:36:52.000Z Below is a synthesis and comparison of stakeholder comments in the CPUC's High DER Future docket, which were filed in response to Cal Advocates' "[Distribution Grid Electrification Model 2025 Study and Report](https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and-analyses/251030-public-advocates-office-distribution-grid-electrification-model-2025.pdf?ref=calregulatory.com)" (DGEM 2025). We explain how consumer advocates, investor-owned utilities, and clean-energy and transportation stakeholders interpret DGEM 2025’s findings, where their views align, and where they diverge (particularly on the role DGEM should play relative to utility "Electrification Impact Studies Part 2," which CRI covered [here](https://www.calregulatory.com/ious-submit-final-electrification-impacts-study-part-2-pg-e-claims-electrification-could-cut-rates-25-despite-billions-in-upgrades/?ref=california-regulatory-intelligence-newsletter)). [PG&E Claims Electrification Could Cut Rates 25%All three studies revaluate multiple futures built on the California Energy Commission’s Integrated Energy Policy Report load forecasts.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-20.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Jan-27-2026--7-.png)](https://www.calregulatory.com/ious-submit-final-electrification-impacts-study-part-2-pg-e-claims-electrification-could-cut-rates-25-despite-billions-in-upgrades/?ref=california-regulatory-intelligence-newsletter) The DGEM 2025 Study has generally been welcomed into the High DER Futures record as a valuable, independent assessment of how widespread electrification could affect California’s distribution grid costs. There is notable agreement among comments that the study complements the utilities’ Electrification Impact Studies Part 2 by offering a top-down, system-wide perspective that contrasts with the utilities’ bottom-up planning analyses. However, parties diverge on how much weight the Commission should assign to DGEM 2025 when evaluating infrastructure needs and cost forecasts. **WHO SHOULD CARE**: Anyone exposed to future distribution spending (or trying to avoid paying for unnecessary infrastructure) should be paying close attention. This includes: - Data centers, electric-vehicle fleet operators, refineries, and manufacturers face the cost consequences of distribution upgrades. Whether DGEM constrains utility spending directly affects interconnection costs and future rates. - Utility regulatory and planning teams. How the Commission uses the DGEM 2025 study will affect how much latitude IOUs have in forecasting and defending distribution capital spending, particularly for secondary systems and feeder upgrades. - Ratepayer and consumer advocates. DGEM strengthens the case that cost growth is not inevitable and that utilities can be held to stricter reasonableness standards. - EV charging, Vehicle-Grid Integration, and Distributed Energy Resource providers. Managed charging and bidirectional solutions move from “nice to have” to system-critical cost controls if DGEM is treated seriously. - Commissioners and administrative law judges. The study frames a clear choice: use DGEM as a benchmark that disciplines utility forecasts, or allow it to remain advisory with limited impact on capital outcomes. - Clean energy and climate policy stakeholders. The record shows electrification can reduce rates *if* load is managed; without enforcement, benefits may not materialize. Below are brief summaries of parties' positions. --- ### Utility Consumers’ Action Network (UCAN) UCAN [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101682.PDF?ref=calregulatory.com) that DGEM 2025 provides a critical reality check on utility projections. UCAN emphasizes that the study identifies managed electric-vehicle charging as the single largest lever for reducing future distribution costs, estimating $5 billion to $18 billion in avoided upgrades by 2040, under scenarios with active load management. UCAN highlights the substantial gap between DGEM’s statewide cost estimates and those advanced by the utilities (particularly PG&E) and contends that this divergence suggests overly conservative engineering assumptions and potential over-building in utility forecasts. UCAN also points to DGEM’s reduction in unit cost assumptions compared to earlier iterations, attributing this change to the use of actual project cost data rather than theoretical models. From UCAN’s perspective, DGEM 2025 should serve as a “reasonableness benchmark,” especially for secondary distribution costs, with utilities bearing the burden of justifying materially higher projections. UCAN urges the Commission to prioritize managed charging, non-wires alternatives, and customer-side solutions over traditional infrastructure expansion. ### INVESTOR-OWNED UTILITIES The investor-owned utilities acknowledge the value of DGEM 2025 but caution against treating it as a substitute for utility planning studies. - PG&E [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101786.PDF?ref=calregulatory.com) inclusion of the study in the record and recognizes broad alignment on the importance of managed load growth. However, PG&E argues that DGEM understates distribution costs by failing to fully capture stand-alone distribution line section upgrades that occur away from substations and feeder heads. - PG&E also criticizes DGEM’s approach to secondary infrastructure costs, noting that they are derived from proportional assumptions rather than independent, bottom-up calculations, and therefore should not be relied upon as definitive estimates. - PG&E further raises concerns about assumptions related to EV charging behavior, emphasizing that vehicles charge at multiple locations rather than solely at registration addresses, complicating feeder-level forecasting. In PG&E’s view, DGEM should be refined in future iterations but should not be used to constrain near-term utility investment planning. --- SCE [similarly praises](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101352.PDF?ref=calregulatory.com) the analytical rigor of DGEM 2025 while stressing that it answers a different question than EIS 2\. - SCE characterizes DGEM as an exploration of alternative electrification futures, testing a range of adoption levels and charging behaviors, whereas EIS 2 is designed to assess how the utility’s existing system responds to electrification once adoption occurs. Because of these methodological differences, SCE cautions that direct numerical comparisons between DGEM and the utilities' Electrification Impact Studies Part 2 are inappropriate. - However, SCE does agree that the studies demonstrate the multidimensional nature of electrification outcomes, shaped by adoption scale, geographic distribution, and customer participation in demand flexibility. ### VEHICLE-GRID INTEGRATION COUNCIL The Vehicle-Grid Integration Council [highlights](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103222.PDF?ref=calregulatory.com) DGEM as independent confirmation that managed EV charging can materially reduce distribution system costs and protect ratepayers. The Council emphasizes that DGEM’s modeled savings depend on active, not passive, load management and notes the gap between modeled outcomes and existing rates or programs capable of delivering that level of participation. The Council urges the Commission to expand managed-charging initiatives and to extend DGEM in future iterations to account for bidirectional charging and vehicle-to-grid capabilities, which could further reduce localized peak demand and defer infrastructure upgrades. ### ENVIRONMENTAL DEFENSE FUND Environmental Defense Fund [similarly views](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101347.PDF?ref=calregulatory.com) DGEM 2025 and the utilities’ Electrification Impact Studies Part 2 reports as mutually reinforcing rather than conflicting. EDF acknowledges the wide variation in cost estimates across studies, particularly with respect to secondary distribution infrastructure, but argues that these differences reflect methodological uncertainty rather than analytical failure. Environmental Defense Fund urges the Commission to focus on directional consistency rather than precision at this stage. Across all studies, Environmental Defense Fund notes a shared conclusion: preparing the grid for electrification will require substantial investment, but pairing load growth with effective load management (especially managed EV charging) can yield net benefits for ratepayers and place downward pressure on rates over time. ### INSTANT ANALYSIS Parties' comments reveal agreement that DGEM 2025 is a credible, independent assessment showing managed electrification (especially EV charging) can substantially reduce future distribution costs. Consumer and clean-energy stakeholders view the study as evidence that unmanaged, capital-heavy planning is avoidable and that active load management could deliver billions in avoided upgrades through 2040. Despite methodological disagreements, all parties (including the utilities) acknowledge that managed EV charging represents a critical cost-control lever. Environmental Defense Fund's analysis emphasizes this cross-cutting consensus: DGEM, PG&E, SCE, and SDG&E all identify transportation electrification paired with demand flexibility as essential to realizing ratepayer benefits. The debate is not on whether managed charging matters, but on what degree of participation is achievable and how quickly programs can scale to meet modeled assumptions. Utilities accept DGEM’s directional value but resist its use as a planning constraint, arguing it abstracts away local engineering realities and should not override Electrification Impact Studies Part 2 forecasts. The main dispute centers on secondary distribution costs, where DGEM’s lower estimates clash with much higher utility projections. How the Commission resolves this (treating DGEM as a benchmark or a sensitivity exercise) will determine whether managed electrification meaningfully restrains future capital spending. ### FRIDAY AGGREGATE: PG&E Looks to Bypass CPCN Review; SDG&E Hydrogen Project Faces Opposition URL: https://www.calregulatory.com/friday-aggregate-pg-e-looks-to-bypass-cpcn-review-sdg-e-hydrogen-project-faces-opposition/ Last updated: 2026-02-07T00:29:43.000Z CRI's Friday roundup compiles activity involving: - **BAJA PATH GAS TRANSMISSION**: PG&E's motion to withdraw its pending CPCN application for the$75 million **\+** S-238 [Hinkley Compressor Station Electrical Upgrades Project](https://ia.cpuc.ca.gov/environment/info/panoramaenv/Hinkley/index.html?ref=calregulatory.com); - **PG&E BILLING INFRASTRUCTURE:** The second joint case-management statement in [PG&E's Billing Modernization Initiative](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2410014/7807/543610817.pdf?ref=calregulatory.com), which confirms that PG&E’s billing environment relies on multiple aging legacy systems that limit flexibility, data visibility, and timely integration; - **BIOMETHANE COST ALLOCATION:** A ruling in [R.22-12-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K216/500216057.PDF?ref=calregulatory.com) directing utilities to submit supplemental comments on unresolved questions related to biomethane procurement cost allocation; and - **DECARBONIZATION:** Protests to SDG&E's [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904936.PDF?ref=calregulatory.com) for approval of its [Palomar Decarbonization Demonstration Project](https://www.distributech.com/2026-event-schedule/san-diego-decarbonization-demonstration-project-tour?ref=calregulatory.com) (and associated cost recovery). --- ### **PG&E HINKLEY COMPRESSOR STATION** PG&E filed a [motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K051/597051566.PDF?ref=calregulatory.com) to withdraw its pending [Certificate for Public Convenience and Necessity](https://en.wikipedia.org/wiki/Certificate%5Fof%5Fpublic%5Fconvenience%5Fand%5Fnecessity?ref=calregulatory.com) application for the **$75 million +** S-238 Hinkley Compressor Station Electrical Upgrades Project after determining that the work qualifies for an emergency exemption under [General Order 177](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com). **WHO SHOULD CARE**: Gas shippers, large end-use customers, and Community Choice Aggregators should pay attention here because this move, if granted, would shift debate from whether the project proceeds to how much ratepayers ultimately bear. Additionally, parties would lose the CPCN forum as a leverage point and are left to challenge costs only after capital has been deployed. - Intervenors and consumer advocates should also care because this is a live test of how broadly GO 177 can be used to sidestep prospective review for major gas infrastructure. A permissive outcome here lowers the practical bar for emergency exemptions when reliability risk is asserted. - Commission staff should also care because an eventual decision would set precedent around procedural discipline. Accepting the withdrawal without conditions reinforces a pattern where emergency authority compresses or bypasses Commission timing, with consequences for how future backbone projects are reviewed. --- **ADDITIONAL DETAILS** The application, which PG&E filed last year, sought CPUC authorization to replace aging and obsolete electrical distribution equipment at the Hinkley compressor station, a critical facility on PG&E’s Baja Path gas transmission backbone that supports gas deliveries to Central and Northern California. (*See CRI's coverage* [*here*](https://www.calregulatory.com/routine-upgrade-or-policy-precedent-pg-es-hinkley-compressor-station-collides-with-general-order-177/)*.*) [PG&E’s Hinkley Compressor Station UpgradeA seemingly routine electrical upgrade has potential to become a test case for how California will handle major gas infrastructure investments.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-18.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Nov-06-2025--21-.png)](https://www.calregulatory.com/routine-upgrade-or-policy-precedent-pg-es-hinkley-compressor-station-collides-with-general-order-177/) Since then, PG&E reports that component failures (which emerged in late summer 2025, after the initial CPCN filing) and accelerating obsolescence created an imminent risk of station outages that could compromise system capacity and force Emergency Flow Orders. The utility emphasizes that much of the equipment is obsolete, with spare or replacement parts difficult or impossible to obtain, and that without station operation, the PG&E gas system may not have enough capacity to meet demand even on non-peak days, potentially requiring curtailments affecting the entire gas system. Accordingly, PG&E began construction on January 20, 2026 under GO 177's emergency project exemption, which allows utilities to proceed without a CPCN when work is necessary to prevent a potential emergency affecting safe and reliable gas service. The project is expected to be completed in January 2028. PG&E formally notified the Commission of its decision on February 4 through an advice letter (and accompanying notices of exemption). Because the project is now proceeding outside the CPCN framework, PG&E argues the application is no longer necessary and that the underlying proceeding serves no remaining purpose. Cost recovery for the project will instead be addressed in PG&E's General Rate Cases (the utility received a revenue requirement for 2023-2026 in its 2023 General Rate Case, requested updated costs for 2027-2030 in its 2027 GRC, and will seek ongoing recovery in the 2031 GRC and beyond). **INSTANT ANALYSIS:** PG&E is seeking to withdraw its application after initiating construction under the General Order 177 emergency exemption. If the Commission grants the motion, the CPCN proceeding would end without a determination on project necessity, and oversight would shift to cost review in future General Rate Cases, meaning ratepayers will face retrospective cost review after the two-year construction timeline is complete, rather than prospective scrutiny before capital deployment. Until the motion is acted on, the application technically remains pending. However, PG&E’s filing frames the CPCN as functionally moot, arguing that emergency conditions and active construction remove the need for prospective authorization. The key inflection point now is whether the Commission concurs that General Order 177 fully displaces the CPCN process for this project. --- ### **PG&E BILLING MODERNIZATION** PG&E filed a [second joint case management statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166418.PDF?ref=calregulatory.com) in its application for a Billing Modernization Initiative. The filing confirms that PG&E’s billing environment relies on multiple aging legacy systems that limit flexibility, data visibility, and timely integration. **WHO SHOULD CARE**: Community Choice Aggregators should care because the outcome affects their ability to communicate with customers, access timely billing data, and avoid being allocated IT costs that do not improve CCA-facing functionality. This case goes directly to competitive parity and cost exposure. Large bundled and unbundled customers should care because billing modernization costs are proposed as common costs, meaning they can flow into rates even if customer-facing benefits are limited or uneven. Small businesses, in particular, face downside risk if execution issues translate into higher bills without clearer or more usable billing information. Regulatory counsel and policy teams should care because the proceeding tests how strictly the Commission will scrutinize large IT programs justified as foundational upgrades, especially when prior GRC representations, scope control, and contingency levels are under dispute. **ADDITIONAL DETAILS** Settlement discussions among PG&E, Cal Advocates, TURN, the Small Business Utility Advocates, CCAs, and Leapfrog have not produced agreement, and the parties expect roughly three days of evidentiary hearings. The CCAs seek hearings on whether proposed upgrades will actually improve bill presentment, customer communications, data quality, and competitive neutrality, and on whether PG&E’s cost allocation approach and interim upgrade decisions are justified. TURN disputes PG&E’s characterization of its prior General Rate Case representations, questions whether the promised benefits could have been achieved at lower cost, and challenges PG&E’s claim that the current proposal avoids cost increases that would have occurred anyway. The Small Business Utility Advocates raise concerns about cost-overrun risk, contingency levels, integration of affected edge systems, and whether small business billing needs were adequately considered. **INSTANT ANALYSIS:** This filing confirms the Billing Modernization Initiative is moving into a contested evidentiary phase rather than toward settlement. CCAs, TURN, and the Small Business Utility Advocates are converging on a shared concern that PG&E may be spreading significant IT costs across customers without delivering proportional gains in billing functionality, data quality, or customer communication. The key concern is whether the Billing Modernization Initiative will actually change outcomes or simply preserve PG&E’s control over billing and data (while reallocating costs more broadly). TURN’s focus on PG&E’s prior General Rate Case representations raises credibility risk, while the Small Business Utility Advocates' testimony highlights execution and cost-overrun concerns that could flow through to rates with uncertain customer benefit. --- ### **BIOMETHANE** **ALJ Sotero** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103216.PDF?ref=calregulatory.com) in R.22-12-011 directing utilities (and authorizing other parties) to submit supplemental comments on unresolved questions related to biomethane procurement cost allocation. **WHO SHOULD CARE:** This ruling affects anyone with exposure to natural gas rates, biomethane procurement costs, or environmental attribute counting, with the most direct impacts on gas utilities, noncore customers, and electric generators. It focuses on three areas: - Whether "[Renewable Thermal Certificates](https://3degreesinc.com/what-we-do/implement-your-strategy/renewable-thermal-certificates-rtcs/?ref=calregulatory.com)" are an appropriate and sufficient mechanism for valuing biomethane’s environmental attributes and how any value should accrue to ratepayers; - What principles and methodologies should govern the allocation of above-market biomethane costs across customer classes, including treatment of electrification goals, Public Purpose Program surcharge precedents, benchmarks for natural gas commodity costs, and potential caps or mitigations for energy-intensive trade-exposed customers; and - How any resulting surcharges should be implemented for noncore customers, including whether costs should be embedded in transportation rates, recovered through new non-bypassable charges, or subject to exemptions. Gas utilities are required to respond to detailed questions on existing noncore charges and exemptions, while other parties may also comment. Comments are due **March 7**. **INSTANT ANALYSIS:** This ruling reopens significant issues the Commission left unsettled in the biomethane framework, especially whether Renewable Thermal Certificates are merely a compliance tool or a rate-relevant asset with monetizable value for customers. By questioning Renewable Thermal Certificate ownership, sale restrictions, and risk allocation, the ALJ is testing assumptions that directly affect how above-market biomethane costs are defined and recovered. On cost allocation, the ruling is inviting alternatives to standard Equal Cents Per Therm and Equal Percent Change approaches and probing whether existing exemptions for electric generators and potential mitigations for Emissions-Intensive Trade-Exposed customers still hold as costs grow. The detailed focus on non-core surcharge mechanics signals that implementation and rate design, not just policy theory, are now central to the proceeding. --- ### DECARBONIZATION/HYDROGEN On February 5, multiple parties protested SDG&E's recent [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904936.PDF?ref=calregulatory.com) seeking CPUC approval and cost recovery for its [Palomar Decarbonization Demonstration Project](https://www.distributech.com/2026-event-schedule/san-diego-decarbonization-demonstration-project-tour?ref=calregulatory.com). The project is an integrated renewable hydrogen system installed at the [Palomar Energy Center](https://www.energy.ca.gov/powerplant/combined-cycle/palomar-energy-project?ref=calregulatory.com), a 588-megawatt combined-cycle natural gas plant in Escondido. (*See CRI's coverage* [*here*](https://www.calregulatory.com/wednesday-aggregate-5/)*.*) [Final CPUC Meeting of 2025; Palomar Decarbonization ProjectThis edition highlights consequential proposed decisions on cost of capital, long-term gas planning, and wildfire cost recovery.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-19.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Tue-Dec-16-2025--4-.png)](https://www.calregulatory.com/wednesday-aggregate-5/) **WHO SHOULD CARE**: Large energy users and gas-exposed customers should pay attention, particularly those sensitive to upstream rate pressure and cost-allocation outcomes. If approved, the project would test how far the Commission will allow speculative decarbonization costs to flow into base rates. - Community Choice Aggregators should care because the proceeding raises early markers on vintaging, re-vintaging, and improper cost shifting. The outcome could shape how future upgrades to legacy utility-owned generation are treated for Power Charge Indifference Adjustment and indifference purposes. - Investor-owned utilities should care because this case probes the limits of what can be advanced as “demonstration” spending without a defined policy framework. A denial would reinforce that hydrogen pilots must clear a high bar on cost discipline and learning value. - Regulatory counsel and intervenors should care because the record may become a reference point for future hydrogen and RD&D applications. The Commission’s handling of scope, hearings, and dismissal standards here will matter well beyond Palomar. **PARTIES' PROTESTS** Across filings, parties argue the project would impose tens of millions of dollars in ratepayer costs for minimal benefits. They state the claimed greenhouse gas reductions are trivial and driven by very small volumes of hydrogen use. The Utility Consumer Action Network argues the project may actually increase emissions when full lifecycle impacts are considered. Several parties emphasize that low-percentage hydrogen blending at Palomar cannot meaningfully decarbonize the facility. - Parties also argue the project offers no unique or scalable learning. They note the electrolyzer and blending approach relies on off-the-shelf technology and duplicates or overlaps with other pending hydrogen pilots. In their view, SDG&E has not shown why similar insights could not be obtained through industry research efforts at far lower cost. - Some filings also stress that the Commission has not yet defined the proper role of investor-owned utilities or ratepayers in the hydrogen sector. They point to unresolved jurisdictional, policy, and eligibility questions around hydrogen-fueled generation. Given that uncertainty, they argue it is premature to require ratepayers to fund hydrogen infrastructure. - Consumer and public-interest groups further argue the project would worsen affordability pressures during a period of rapidly rising rates. They also criticize the diversion of limited green hydrogen to inefficient uses such as vehicle fueling and minimal turbine blending. - CCAs and others raise separate concerns about cost allocation and cost shifting. They argue the project constitutes a major modification to an existing utility-owned generation asset that could trigger re-vintaging issues. Absent clarity, they warn that costs could be improperly shifted to departed load customers through distribution or non-bypassable charges. Below are direct links to the protests. - [Air Products and Chemicals](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103229.PDF?ref=calregulatory.com) - [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K100/598100913.PDF?ref=calregulatory.com) - [San Diego Community Power/Clean Energy Alliance ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101128.PDF?ref=calregulatory.com) - [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K101/598101350.PDF?ref=calregulatory.com) - [Utility Consumers Action Network](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M598/K103/598103223.PDF?ref=calregulatory.com) **INSTANT ANALYSIS:** The Palomar application is facing opposition that frames it as a re-filed version of the hydrogen pilot already rejected in SDG&E’s 2024 GRC. Across parties, a recurring claim is that the project still delivers negligible emissions benefits at high ratepayer cost, with no credible path to scale or distinct learning value. TURN goes further, requesting outright dismissal on procedural grounds. TURN argues SDG&E failed to satisfy the five specific requirements from the Commission's 2024 SoCalGas/SDG&E GRC decision ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)): - Leveraging new public funding; - Establishing public-private partnerships; - Lowering ratepayer costs; - Demonstrating scalability; and - Showing the project is more effective than participating in collaborative research efforts like the [Electric Power Research Institute](https://www.epri.com/?ref=calregulatory.com)'s $500,000/year hydrogen initiative. Cal Advocates proposes expanding the scope to require SDG&E to quantify GHG reductions across all four claimed use cases (generator cooling, power generation, vehicle fueling, and RD&D), demonstrate scalability with associated costs, and prove consistency with state RD&D policies. Ultimately, the application lands amid unresolved policy questions about the utility's role in hydrogen and eligibility of hydrogen blending under clean procurement programs. Approving cost recovery now would force the Commission to decide those issues indirectly. ### February 5, 2026 CPUC Voting Meeting Results: Commission Clears Path for Immediate Energization Under New Flexible Service Connection Rules URL: https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-results-commission-clears-path-for-immediate-energization-under-new-flexible-service-connection-rules/ Last updated: 2026-02-05T21:32:53.000Z The CPUC's February 5 voting meeting authorized several notable decisions. First and foremost, the Commission adopted a decision in the Energization rulemaking (R.24-01-018) that directs PG&E and SCE to establish a standardized, tariffed “Standard Offer” Flexible Service Connection to accelerate energization for customers facing distribution capacity constraints. "A flexible service connection allows customers waiting for an upgrade to use power in the interim when it is safe to do so," said **Commissioner Darcie Houck** from the dais. "This tool allows investor-owned utilities to connect customers to the grid while limiting energy use during constrained periods and while grid upgrades proceed in a more cost-effective manner." The Commission also adopted the following items. - **Wildfire Cost Recovery:** A decision granting partial approval of PG&E’s request to recover recorded costs related to wildfire mitigation, vegetation management, catastrophic events, and several customer- and policy-driven programs, primarily incurred in 2022\. The decision authorizes recovery of **$1.607 billion** in revenue requirement, largely reflecting wildfire mitigation activities, emergency storm response, and compliance with Commission-mandated programs, while denying **$172.5 million** in vegetation management costs after a reasonableness review. - **SoCalGas Distribution Integrity Management Costs**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K021/597021734.PDF?ref=calregulatory.com) partially granting SoCalGas interim recovery of costs recorded in its Distribution Integrity Management Program Balancing Account for the 2019–2023 period. The decision authorizes **$35.5 million**, equal to **60%** of a [$59.1 million request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com), to be recovered over a 12-month period through interim rates. - **Clean Energy Contracts**: [Resolution E-5445](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673037.PDF?ref=calregulatory.com), which approves SCE’s request to enter into 10 clean energy contracts resulting from its 2024 Clean Energy Request for Offers. The approved portfolio totals **2,093 MW** of nameplate capacity across 10 contracts and four projects. - **Union Island Pipeline**: A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K675/597675451.PDF?ref=calregulatory.com) dismissing without prejudice California Resources Production Corporation's application seeking a Certificate of Public Convenience and Necessity to operate the Union Island natural gas pipeline as a public utility. - **Crude Oil Transportation:** [Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673435.PDF?ref=calregulatory.com), which approves San Pablo Bay Pipeline Company and Crimson California Pipeline’s request for emergency, interim rate relief on the SPB-KLM intrastate crude oil pipeline system. And separately, [Resolution O-0099](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K079/595079380.PDF?ref=calregulatory.com) which approves Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations. More detail is available below. --- ### ENERGIZATION A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K684/597684025.PDF?ref=calregulatory.com) in [R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com) directs PG&E and SCE to establish a standardized, tariffed “Standard Offer” Flexible Service Connection to accelerate energization for customers facing distribution capacity constraints. SDG&E and small multi-jurisdictional utilities are not required to participate at this time. The decision formalizes existing utility practices (particularly PG&E’s Load Limiting Letter model) into a uniform option that allows customers to receive firm, limited capacity under predefined load profiles while awaiting upstream upgrades. PG&E and SCE must file: - A joint Tier 2 advice letter within 60 days implementing the standard offer; - A Tier 1 advice letter within 15 days updating tariff rules; and - A Tier 2 advice letter within 75 days formalizing preliminary capacity assessments. SCE must file a report on its Load Control Management Study pilot learnings by March 1, 2026\. Both utilities must collect detailed data to evaluate cost efficiency and file a report by January 15, 2029. The Flexible Service Connection is positioned strictly as a temporary bridging solution for individual customers, does not alter energization queue positions, and prioritizes speed, safety, and scalability through a "trust-and-verify" approach rather than prescriptive control systems. Load profiles must include a minimum of six values (three seasons with two daily capacity values each), and load behind [UL 3141](https://www.ampcontrol.io/post/ul-3141-power-control-systems-and-the-future-of-ev-charging-stations?ref=calregulatory.com)\-certified power control systems receives safe harbor treatment that excludes it from connected load calculations. "It’s considered a bridging solution," **President Alice Reynolds** said from the dais, "because the limits are temporary and may be removed after grid infrastructure is in place. In the case of flexible service connections, utilities can serve new customers with little or no near-term investment, and this approach can help manage and even lower costs for ratepayers." Below are some additional comments from the dais. - **Commissioner Darcie Houck**: "In the High DER proceeding, we are assessing longer-term feasibility of flexible service connections for non-firm capacity, including utility and customer-side equipment, technical standards, scalability, performance, and reliability. The flexible service connections established here will be foundational to that longer-term work." - **Commissioner John Reynolds**: "One of our high-level goals should be timely energization and electrification. To do this, we need to adjust our regulatory framework to encourage energization and load growth. This goal is fundamental and urgent. We cannot afford to wait for every distribution upgrade, especially when the distribution revenue requirement of IOUs has more than doubled since 2016\. We must maximize the value of existing assets—and do so safely. This decision should have a positive effect on affordability by facilitating energy sales sooner than would occur if we waited for upgrades. The revisions made to the decision have also been very helpful." - **Commissioner Karen Douglas**: "We have heard repeatedly from customers who are unhappy with rising bills. One way we manage affordability is by promoting efficient utility management. Another is promoting efficient use of the grid — which this decision does. In California, when a utility sells more energy, it does not make more money. More sales can lead to lower rates. Flexible service connections increase sales by allowing customers to purchase more energy on existing infrastructure. These connections are short- to medium-term solutions. Typically, they remain in place for about three years before infrastructure upgrades are built. During that window, sales increase before the flexible connection sunsets and upgrades proceed." **INSTANT ANALYSIS:** This decision moves Flexible Service Connections from pilots and one-off arrangements into a standard, tariffed option at PG&E and SCE for customers blocked by local grid limits. Instead of waiting years for upgrades, customers can take partial power sooner by agreeing to stay within defined load limits while the utility completes the required upgrade work. The Commission is favoring this practical stopgap over delay, particularly as electrification drives load growth that exceeds existing distribution capacity. For utilities and ratepayers, the goal is providing capacity faster through operational flexibility rather than waiting on infrastructure construction timelines. For customers, the tradeoff is responsibility: they must actively manage their load and stay within approved limits, or face curtailment and potential liability. The required tracking and reporting will inform future refinements to what is already a proven approach, with adjustments likely once broader deployment generates real-world data beyond PG&E's existing 100+ Load Limiting Letter customers. --- ### PG&E WILDFIRE COST RECOVERY A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K674/597674515.PDF?ref=calregulatory.com) grants partial approval of PG&E’s request to recover recorded costs related to wildfire mitigation, vegetation management, catastrophic events, and several customer- and policy-driven programs, primarily incurred in 2022\. The decision authorizes recovery of **$1.607 billion** in revenue requirement, largely reflecting wildfire mitigation activities, emergency storm response, and compliance with Commission-mandated programs, while denying **$172.5 million** in vegetation management costs after a reasonableness review. Most disputed costs (covering wildfire mitigation, catastrophic event response, climate adaptation, microgrids, customer protections, and related memorandum accounts) are resolved through an uncontested settlement among PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates, which the Commission finds reasonable and in the public interest. Under the decision, PG&E must file an advice letter to implement recovery, net of amounts already collected under prior interim rate relief, with remaining balances amortized beginning in 2026. **INSTANT ANALYSIS:** The decision approves PG&E’s 2022 wildfire and catastrophic-event cost recovery, with most disputed amounts resolved through an uncontested settlement. The decision authorizes recovery of about $1.6 billion, reflecting continued deference to wildfire mitigation, storm response, and customer-protection spending when costs are tied to authorized programs and supported by the record. The denial of $172.5 million in vegetation management costs shows that Vegetation Management Balancing Account spending is not automatically recoverable. The disallowance has two components: - **$10 million** for above-compliance work performed at customer request; and - **$162.45 million** for Enhanced Vegetation Management costs incurred from October through December 2022 (after PG&E knew the program was not cost-effective and would be replaced). Even work aligned with an approved Wildfire Mitigation Plan remains subject to detailed reasonableness review and potential disallowance. For ratepayers, the settlement reduces PG&E’s original request and brings procedural closure. For utilities, the takeaway is straightforward: settlements support recovery, while vegetation management continues to face the most scrutiny. --- ### SOCALGAS – DISTRIBUTION INTEGRITY MANAGEMENT A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K021/597021734.PDF?ref=calregulatory.com) partially grants SoCalGas interim recovery of costs recorded in its Distribution Integrity Management Program Balancing Account for the 2019–2023 period. The decision authorizes **$35.5 million**, equal to **60%** of a [$59.1 million request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com), to be recovered over a 12-month period through interim rates. All interim collections are subject to refund with interest, pending a final determination on the reasonableness of the costs. The decision finds interim recovery appropriate to reduce accumulated interest expense, support intergenerational equity, and preserve the utility’s financial condition following a recent credit downgrade. It concludes that delaying recovery would increase financing costs borne by ratepayers and prolong pressure on SoCalGas’ credit metrics. These factors support immediate but limited relief, the decision finds. The decision rejects SoCalGas’ request to recover 85% on an interim basis. It determines that a 60% authorization better balances ratepayer protection with utility needs, given recent rate increases and ongoing affordability concerns. **INSTANT ANALYSIS:** The decision shows that interim recovery remains available outside a General Rate Case when utilities show concrete ratepayer benefits. Interest savings, intergenerational alignment, and credit pressure carried weight here, especially after a downgrade. For stakeholders, the key takeaway is calibration, not capitulation. The Commission was willing to act quickly, but only at a level that smooths rates and constrains exposure. A final outcome will require a detailed reasonableness review of the underlying Distribution Integrity Management Program Balancing Account costs. --- ### SCE – CLEAN ENERGY CONTRACTS [Resolution E-5445](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673037.PDF?ref=calregulatory.com) approves SCE’s request to enter into 10 clean energy contracts resulting from its 2024 Clean Energy Request for Offers. The approved portfolio totals **2,093 MW** of nameplate capacity across 10 contracts and four projects: - Two co-located solar-plus-storage projects ([Aratina II](https://avantus.com/news/Avantus-Secures-Power-Purchase-Agreements-with-Southern-California-Edison?ref=calregulatory.com) and [Darden](https://www.rtoinsider.com/107945-cec-approves-darden-solar-storage-project/?ref=calregulatory.com)); and - Two solar-only projects ([Bonanza Peak](https://www.sifpd.org/files/aa1b0df72/Bonanza+Peak+Solar+Project+Letter.pdf?ref=calregulatory.com) and [Lockhart IV](https://terra-gen.com/lockhart-iv/?ref=calregulatory.com))... ...with deliveries beginning between 2027 and 2029 and contract terms of 15 to 20 years. The solar contracts are expected to generate approximately 4,008 GWh annually and are intended to support SCE's Integrated Resource Plan and Renewables Portfolio Standard obligations. Energy Division found the solicitation and least-cost, best-fit evaluation process to be fair and reasonable, with independent evaluator oversight and Procurement Review Group participation. The resolution: - Approves full cost recovery of contract and administrative costs through SCE’s Portfolio Allocation Balancing Account for applicable customers; - Allows limited flexibility to count the resources toward mid-term reliability requirements if needed; but - Rejects SCE's requests to pre-authorize cost treatment for future Integrated Resource Planning mandates and to recover costs related to a separate interconnection solicitation as out of scope and lacking sufficient information, though SCE may re-file separately. **INSTANT ANALYSIS**: This resolution advances SCE’s near-term Integrated Resource Planning execution by committing to a large tranche of late-2020s solar and paired storage using already-vetted offers, rather than reopening a new solicitation cycle. The Commission’s approval affirms the Clean Energy RFO as a workable bridge between mid-term reliability procurement and longer-horizon Integrated Resource Planning needs, while preserving flexibility to reclassify these resources if SCE later faces mid-term reliability shortfalls. At the same time, the resolution establishes very specific parameters for cost recovery: SCE receives full recovery for the clean-energy contracts themselves, but the resolution declines to pre-approve cost treatment tied to future Integrated Resource Planning mandates or to fold in unrelated interconnection-solicitation mechanics. For customers, this confirms that the cost exposure from these contracts is immediate, but with closer scrutiny of add-on procurement requests that attempt to travel alongside otherwise approvable clean-energy filings. --- ### UNION ISLAND PIPELINE A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K675/597675451.PDF?ref=calregulatory.com) dismisses without prejudice California Resources Production Corporation's [A.23-07-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) seeking a Certificate of Public Convenience and Necessity to operate the Union Island natural gas pipeline as a public utility. The decision concludes the application is not ripe for consideration because: - CRPC does not presently hold clear, undisputed rights to control, operate, or manage all segments of the pipeline (particularly within the Cities of Antioch and Brentwood); and - Parallel judicial and local administrative proceedings remain unresolved. The decision emphasizes that Sections [216](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-216/?ref=calregulatory.com) and [222](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-1/section-222/?ref=calregulatory.com) of the Public Utilities Code use present-tense language ("owning, controlling, operating, or managing") that does not permit expired or speculative future status to satisfy the statutory criteria. The outcome turns on two unresolved issues. - First, ownership of the Antioch pipeline segment remains disputed in ongoing Phase II litigation, where Antioch seeks a determination that CRPC abandoned the pipeline upon franchise termination, potentially vesting ownership in the City. - Second, CRPC lacks current franchise authority in both Antioch and Brentwood, with local franchise applications still pending or held in abeyance. The decision denies the Cities' request to hold the case in abeyance, finding dismissal cleaner. It also denies CRPC's motion to substitute its subsidiary (to which CRPC transferred pipeline ownership in October 2024) as applicant, concluding the subsidiary faces identical deficiencies. The dismissal is without prejudice, allowing CRPC or its successor to re-file once ownership and franchise rights are resolved. **INSTANT ANALYSIS:** This dismissal is procedural, but the message is substantive. CRPC filed its application hoping the Commission would grant public utility status conferring eminent domain authority (allowing the company to condemn municipal rights-of-way and bypass the Cities' franchise decisions entirely). The Commission refused. By insisting on present-tense statutory language, the decision directs CRPC to resolve its property and franchise disputes through courts and local processes first. The main message from the Commission is this: it will not serve as an alternative forum when those negotiations fail. The Phase II litigation now becomes dispositive: if Antioch prevails on its abandonment theory, the pipeline may be permanently foreclosed from private operation. --- ### CRUDE OIL TRANSPORTATION [Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K673/597673435.PDF?ref=calregulatory.com) approves San Pablo Bay Pipeline Company and Crimson California Pipeline’s request for emergency, interim rate relief on the SPB-KLM intrastate crude oil pipeline system. The resolution authorizes a 59.2% interim rate increase, raising the mainline tariff from **$2.3571** to **$3.7527 per barrel**, effective August 1, 2025, subject to refund, and applies the same percentage increase to the Station 36–San Joaquin Refinery segment. - The resolution finds that Crimson demonstrated sustained and severe throughput declines (including zero shipper nominations for December 2025) resulting in negative operating cash flow and an inability to continue operations absent immediate relief. - Chevron Products Company and Valero Marketing and Supply Company protested, and PBF Holding Company, LLC filed reply comments in opposition, arguing that increases above 10% are impermissible without hearings and disputing the existence of an emergency. The resolution asserts statutory authority to grant interim relief above 10% and finds that resolving the matter through the advice-letter process is appropriate. - The resolution emphasizes the public interest risks of a pipeline shutdown, including higher costs, increased trucking and marine transport, environmental and safety impacts, and reduced resilience in California's crude supply chain. - An accompanying [attachment](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K675/597675467.pdf?ref=calregulatory.com) notes that pipeline tariffs do not affect gasoline prices because California crude producers (not refiners) bear the transportation cost differential relative to competing southbound routes. To protect ratepayers, the interim increase is subject to refund pending resolution of the ongoing general rate case, and Crimson must secure a **$5.8 million** letter of credit to ensure refund availability in the event of insolvency. The accompanying [attachment](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M597/K675/597675467.pdf?ref=calregulatory.com) reinforces the factual basis for emergency relief, documenting: - Volume losses since early 2025; - The pipeline’s high fixed-cost structure; - The economic obsolescence risk posed by competing southbound pipelines; and - Crimson’s unsuccessful efforts to settle its 2024 and 2025 rate cases at deeply discounted levels to stabilize operations. **INSTANT ANALYSIS:** The Commission's approval of a 59.2% interim emergency rate increase for the San Pablo Bay Pipeline reflects how quickly collapsing crude volumes can destabilize fixed-cost energy infrastructure, even before a final rate determination. By authorizing relief above the customary 10% threshold through an advice letter resolution (a procedural vehicle not previously used for oil pipeline emergency relief of this magnitude), Resolution O-0098 shows a readiness to intervene when continued operation of a single-asset system is at risk and broader supply-chain impacts are plausible. At the same time, the resolution avoids prejudging Crimson's pending General Rate Cases: the increase is interim, subject to refund, and paired with a $5.8 million letter of credit to protect shippers if rates are later disallowed. For shippers and producers, the resolution increases near-term transportation costs but preserves optionality in a constrained crude logistics network. For other pipeline operators and regulated infrastructure owners, the resolution establishes that system continuity can outweigh procedural ceilings when volume collapse threatens withdrawal of service. --- Separately, [Resolution O-0099](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K079/595079380.PDF?ref=calregulatory.com) approves Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations and concluding an uncontested Tier 3 advice-letter process. The resolution finds that, following the closure of the Santa Maria Refinery and the conversion of the Rodeo Refinery to a renewable fuels facility, the pipeline system no longer serves a useful purpose, and all former producers have secured alternative transportation. Safety oversight remains exclusively with the Office of the State Fire Marshal, which has granted Phillips 66 a deferment of certain maintenance, inspection, and testing requirements. Phillips 66 must still comply with all applicable state and federal regulations for idled lines. The resolution does not authorize or address cost recovery, noting there are no ratepayers using the lines and that any remaining maintenance costs will be borne entirely by Phillips 66. **INSTANT ANALYSIS:** Resolution O-0099 formalizes the end of Phillips 66's crude pipeline utility operations in California – not a partial system withdrawal, but a complete exit from the business. The resolution reflects demand loss rather than a safety or cost dispute, tying directly to the Santa Maria refinery closure and the Rodeo conversion to renewable fuels. There is no rate exposure, no cost allocation, and no downstream precedent risk for other pipeline utilities, as the draft resolution explicitly avoids approving any costs and leaves all residual obligations with Phillips 66\. From a market perspective, the resolution closes the book on a legacy crude transport corridor and reinforces the direction of travel for refinery-linked infrastructure in California: once refining demand disappears, utility status follows. ### WEDNESDAY AGGREGATE: CPUC Orders PG&E to Fortify Claim that Increased Data Center Load Will Reduce Bills URL: https://www.calregulatory.com/wednesday-aggregate-10/ Last updated: 2026-02-04T21:08:58.000Z Today's roundup includes: - A scoping memo for the CPUC's Climate Credit rulemaking, i.e., the docket where the Commission is considering ways to improve the California Climate Credit; - Activity in PG&E's 2027 General Rate Case, where a February 3 ruling orders PG&E to provide granular explanations and workpapers on a slew of topics e.g., deferred and imputed wildfire-related inspections and transformer replacement assumptions; - An amended scoping memo in the ERRA/PCIA reform docket, which formally launches Track Two to focus on how pre-2019 banked RECs should be valued for PCIA purposes; and - A scoping memo establishing the procedural framework for the CPUC’s review of SoCalGas's proposal to implement a woody biomass pilot project with [West Biofuels LLC](https://www.westbiofuels.com/?ref=calregulatory.com). ### CALIFORNIA CLIMATE CREDIT **President Alice Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166396.PDF?ref=calregulatory.com) in [R.25-07-013](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K655/574655670.PDF?ref=calregulatory.com), which is the proceeding that considers ways to improve the effectiveness of the [California Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) as an affordability tool. The rulemaking responds to recent statutory changes under [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com), which: - Extended and renamed the state’s cap-and-trade program as Cap-and-Invest; - Revised how Climate Credit revenues may be distributed; and - Directed the Commission to maximize bill affordability by aligning credits with high-bill months. Phase 1 of the proceeding will focus exclusively on the residential Climate Credit and is split into two sub-phases. Phase 1A will address near-term actions for 2026, including whether to: - Pause distribution of the 2026 residential electric Climate Credit for large utilities (PG&E, SCE, SDG&E) pending a decision on timing (the small and multi-jurisdictional utilities are excluded because they are winter-peaking, and gas utilities are excluded because their next residential credit won't occur until 2027); - Shift credits into summer high-usage months; - Implement new outreach requirements attributing credits to Cap-and-Invest at the top of customer bills; and - Establish procedures to transfer 5% of electric allowance revenues to the State Treasury for the [California Transmission Accelerator Revolving Fund](https://autl.assembly.ca.gov/system/files/2026-01/01.15%5Ftx-accelerator-oversight-hearing-background.pdf?ref=calregulatory.com) starting July 2026\. Phase 1B, to be scheduled later in 2026, will consider more comprehensive reforms to the residential Climate Credit, including eligibility, timing, number of distributions, calculation methods, cost impacts, and environmental/social considerations. **INSTANT ANALYSIS:** This ruling sets up a fast-track reset of the California Climate Credit with a clear legislative push toward bill affordability rather than seasonal visibility. The near-term risk for customers is that the Commission is openly contemplating pausing the 2026 residential electric credit for large utilities and redeploying it into summer peak months, a move that could significantly change when relief shows up on bills. For utilities and large stakeholders, the key procedural takeaway is the compressed Phase 1A schedule, which forces decisions on 2026 credits before ERRA forecasts are set in October, while also operationalizing new AB 1207 mandates on bill messaging and the 5% revenue transfer to the California Transmission Accelerator Revolving Fund. Longer term, Phase 1B suggests that the residential Climate Credit will no longer be treated as a fixed entitlement but as a policy lever subject to redesign around timing, eligibility, and distribution rules. --- ### PG&E GENERAL RATE CASE 2027 In a pair of closely related rulings in [PG&E’s 2027 General Rate Case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com), the assigned Administrative Law Judges substantially expand the evidentiary record required from PG&E while also clarifying the procedural boundaries for post-2027 undergrounding plans. In a [February 3 joint ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K705/597705019.PDF?ref=calregulatory.com), the ALJs identify areas where PG&E's filing may be incomplete (or where additional evidence would provide a better record across a range of cost, forecasting, and policy areas) and order extensive supplemental filings. The ruling demands granular explanations and workpapers on issues including: - The capitalization of pole reinforcement and pole test-and-treat work; - Deferred and imputed wildfire-related inspections; - Vegetation management and targeted tree-inspection programs; - Customer-driven “new business” construction costs; - Transformer replacement assumptions; - Gas safety work that exceeds minimum code requirements; - Clean-energy transition strategy; and - The rapidly growing data-center interconnection queue and its claimed rate impacts. The judges also require reconciled historical and forecast demand data, clearer treatment of post-test-year cost reductions, and explicit cross-referencing to PG&E’s Wildfire Mitigation Plan wherever relied upon, indicating heightened scrutiny of both cost causation and compliance rationales. This info is due **February 13**. - Separately, an [email ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K053/597053781.PDF?ref=calregulatory.com) addresses a narrower but important issue: the scope of testimony and cross-examination related to PG&E's proposed "Bridge Program" for electrical undergrounding in the 2028–2030 attrition years. - Under the Bridge Program, PG&E would seek authorization of up to approximately **$3.6 billion** for up to 1,200 miles of undergrounding via an advice-letter mechanism, contingent on the timing of the Commission's decision on PG&E's 10-year Electric Undergrounding Plan under [Senate Bill 884](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220SB884&ref=calregulatory.com). The ruling clarifies that schedule extensions previously granted for intervenor and rebuttal testimony on post-2027 undergrounding do not expand the substantive scope set by the earlier scoping memo. Additionally, the ALJs indicate that post-2027 undergrounding discussion is limited to contingency planning tied to potential delays or outcomes in PG&E's SB 884 Electric Undergrounding Plan proceeding, preserving ratepayer protections over 2027 approved funds while avoiding procedural spillover into the core 2027 GRC record. **INSTANT ANALYSIS**: These rulings raise the bar for PG&E's 2027 GRC showing. The ALJs are showing skepticism toward high-level forecasts and forcing PG&E to fully substantiate cost shifts, deferred wildfire work, emerging-load assumptions, and post-test-year savings with detailed workpapers and clear links to requirements. - The stakes are substantial: the ruling covers approximately **$8.7 billion** in Overhead Maintenance and Poles capital alone (2027-2030), plus over **$1 billion** annually in vegetation management. That increases disallowance risk if PG&E cannot reconcile inconsistencies or demonstrate cost causation. - Notably, the ALJs are demanding workpapers behind PG&E's public claim that every gigawatt of data center load could reduce customer bills 1-2%. If PG&E cannot substantiate that assertion, it undermines not just the GRC forecast but the broader emerging-load narrative that has become central to PG&E's strategic messaging. At the same time, the Commission is containing the undergrounding debate. Post-2027 undergrounding is permitted only as contingency planning tied to the SB 884 process, not as a backdoor authorization of future spending. The focus stays on whether 2027 dollars are justified and controllable, not on speculative attrition-year buildouts. --- ### ELECTRICITY RATES – ERRA/PCIA REFORM **Commissioner John Reynolds** issued an [amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K166/597166403.PDF?ref=calregulatory.com) in [R.25-02-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com) to revise the scope and schedule of the proceeding addressing Energy Resource Recovery Account and Power Charge Indifference Adjustment policies. The amendment formally launches Track Two, narrowing the focus to how pre-2019 banked RECs should be valued for PCIA purposes after questions arose in the 2026 ERRA Forecast proceedings. Specifically, the Commission will examine: - Whether assigning a value other than zero to these pre-2019 RECs is consistent with statutory indifference principles, prior Commission decisions, and cost-shift protections for bundled and departing customers; and - If so, how that value should be calculated and allocated in future ratemaking. Opening testimony is due **March 2**. **INSTANT ANALYSIS:** This amended scoping memo sets up a financially sensitive PCIA dispute by isolating pre-2019 banked RECs as a standalone Track Two issue rather than letting it diffuse across ERRA forecasts. - The Commission is implicitly acknowledging that earlier REC valuation rules created temporal mismatches that now sit awkwardly with indifference doctrine. - By serving this ruling on the [R.17-06-026](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M191/K426/191426539.PDF?ref=calregulatory.com) service list, the CPUC is indicating that it may need to modify a 2018 decision ([D.18-10-019](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M232/K687/232687030.PDF?ref=calregulatory.com), which modified the PCIA methodology) and a 2019 decision ([D.19-10-001](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M318/K167/318167258.PDF?ref=calregulatory.com), which refined the method for developing and truing-up Market Price Benchmarks). - Additionally, by framing the key question as whether a non-zero valuation is even lawful, the ruling puts utilities and departing-load advocates on opposite sides of first principles rather than mechanics, which raises settlement pressure early. In short, this fight has real dollar consequences, but the CPUC's preference appears to be closure rather than sprawling litigation. --- ### BIOMETHANE The assigned commissioner’s [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K902/596902616.PDF?ref=calregulatory.com) in [A.25-10-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K959/583959234.PDF?ref=calregulatory.com) establishes the procedural framework for the CPUC’s review of SoCalGas’s proposal to implement a woody biomass pilot project with [West Biofuels LLC](https://www.westbiofuels.com/?ref=calregulatory.com). SoCalGas filed the application last October, following withdrawal of an earlier version, and the filing drew protests from [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K334/588334619.PDF?ref=calregulatory.com), the Small Business Utility Advocates, and the Sierra Club, and also a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K309/588309782.PDF?ref=calregulatory.com) from the Bioenergy Association of California (*CRI's coverage is available* [*here*](https://www.calregulatory.com/monday-aggregate-pg-es-card-filing-erra-pds-for-pg-e-and-sce-ious-hydrogen-blending-demo-projects/)). [Declining Natural Gas Throughput Forcing Cost ReallocationThe CPUC issued respective PDs for the 2026 ERRA Forecast filings of PG&E and SCE.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-17.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Thu-Nov-20-2025--7-.png)](https://www.calregulatory.com/monday-aggregate-pg-es-card-filing-erra-pds-for-pg-e-and-sce-ious-hydrogen-blending-demo-projects/) After meet-and-confer efforts and a prehearing conference, the CPUC determined that the main question is whether the proposed project qualifies as a legitimate pilot and complies with prior Commission decisions, including: - Funding restrictions under a 2022 decision ([D.22-02-025](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M454/K335/454335009.PDF?ref=calregulatory.com)), including whether SoCalGas's proposed use of allowance proceeds for specific project "lanes" comports with the requirement that funding offset pipeline build-out costs; - Requirements set out in a 2024 decision ([D.24-12-032](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K015/551015356.PDF?ref=calregulatory.com)); - Applicable [California Air Resources Board](https://ww2.arb.ca.gov/?ref=calregulatory.com) regulations; and - Whether precedents from [Senate Bill 1383](https://www.wm.com/us/en/sb1383?ref=calregulatory.com) dairy biomethane programs (covering project readiness, emissions reporting, and incentive structures) should apply. The scope also covers: - The ratemaking treatment of project costs (including whether certain pipeline investments may be capitalized); - How ongoing operations and maintenance should be funded; - Transparency and confidentiality of methane emissions data; and - Potential environmental and social impacts. Intervenor testimony is due **March 13**, with rebuttal testimony due **April 10**. **INSTANT ANALYSIS:** This scoping memo provides for a narrowly framed, compliance-heavy review of SoCalGas’s woody biomass pilot and shows that the CPUC remains skeptical about stretching Cap-and-Trade–funded “pilot” authority beyond what was explicitly authorized in prior decisions. The ruling puts particular pressure on SoCalGas to justify both the project’s pilot status and its proposed use of allowance proceeds for pipeline infrastructure, including whether any such assets can be capitalized or must be treated as expense-only. The absence of evidentiary hearings at the outset favors a paper-driven outcome, but the explicit invitation to seek hearings if factual disputes emerge leaves open a path for intervenors to challenge cost recovery, emissions accounting, and environmental impacts. Overall, the memo suggests that any approval will come with heightened scrutiny on funding mechanics, emissions transparency, and alignment with existing biomethane precedent and will not be a green light for broader infrastructure expansion. ### MID-WEEK NEWS CODEX: Senate Bill 254; Reducing Electric Rates; CARB Amendments URL: https://www.calregulatory.com/mid-week-news-codex-senate-bill-254-reducing-electric-rates-carb-amendments/ Last updated: 2026-02-04T17:31:16.000Z - **California's $200 Million EV Incentive Program to Require Matching Funds from Automakers:** "The proposal would allow incentives to defray the upfront purchase costs for new or used EVs but the incentive amounts have not yet been announced. Eligible vehicles will face price caps adopted by Congress in 2022." [**REUTERS**](https://www.reuters.com/business/autos-transportation/californias-200-million-ev-incentive-program-will-require-matching-funds-2026-02-02/?ref=calregulatory.com) - **California's High-Wire Act to Save Money on Power Lines:** "One of the energy policy “planes” that landed in the final days of last year’s legislative session had in its cargo hold a rough draft of a plan that aims to save billions of dollars on new power lines. The proposal in [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=cleanpowercalifornia.org) seeks to save money on transmission financing costs, which over decades can exceed the actual costs of designing and building new high-voltage lines because of return-on-equity requirements under the prevailing utility-based model. It’s a novel approach to containing costs as California builds out its grid to meet growing electricity demand and its clean energy goals. But there are risks, and lawmakers and the administration should prioritize protecting competition among private developers as the proposal takes shape." [**THE CURRENT**](https://www.cleanpowercalifornia.org/californias-high-wire-act-to-save-money-on-power-lines/?ref=calregulatory.com) - **California Can Reduce Electric Rates by Easing State Mandates**: "One sacred cow that the state should re-examine is its renewable energy mandates. California’s [Renewable Portfolio Standard](https://www.ncsl.org/energy/state-renewable-portfolio-standards-and-goals?ref=calregulatory.com) requires that electric utilities procure 52% of their energy from renewable sources by 2027, with the required amount rising to 60% by 2030\. California’s RPS is one of the most stringent in the nation and these requirements are and will push electric rates higher. Research suggests that solar and wind power do not drive up electricity prices, but this is only true when their deployment is due to market forces. Where renewable deployment is driven by a RPS, it is associated with [increasing power prices.](https://www.sciencedirect.com/science/article/pii/S1040619025000612?ref=calregulatory.com)" [**DAILY BULLETIN**](https://www.dailybulletin.com/2026/02/02/california-can-reduce-electric-rates-by-easing-state-mandates/?ref=calregulatory.com) - **California is Lagging on Wind Development – Why?** "For starters, solar got cheap. Renewable energy procurement in California has largely been driven by [renewable portfolio standard](https://www.cpuc.ca.gov/rps/?ref=calregulatory.com) requirements, which don’t distinguish between solar and wind. So when solar prices dropped sharply, California electricity providers went all-in on solar and procured much less wind." [**UNION OF CONCERNED SCIENTISTS**](https://blog.ucs.org/mark-specht/california-is-lagging-on-wind-development-why/?ref=calregulatory.com) - **California Sues Trump Administration Over Sable Pipeline Approval:** "California is [suing](https://oag.ca.gov/system/files/attachments/press-docs/PFR%20with%20Exhibits%20and%20Certificate%20of%20Service.pdf?ref=calregulatory.com) the federal government for taking [regulatory authority](https://www.californiaenergytransition.com/p/federal-regulators-to-oversee-pipeline?ref=calregulatory.com) over Sable Offshore Corp.’s Las Flores Pipeline System. The pipeline, which was shut down following the 2015 Refugio oil spill, is critical to restarting oil production in the Santa Ynez Unit." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/california-sues-trump-administration?ref=calregulatory.com) - **CARB Proposes Amendments to California's Cap-and-Trade Rules:** "CARB’s proposal would significantly tighten the supply of emissions allowances in future years. Staff estimates indicate that the revised cap trajectory would remove roughly 118 million allowances from circulation during the 2027–2030 period, reflecting a more aggressive emissions-reduction pathway consistent with state climate policy." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/carb-proposes-amendments-to-californias?ref=calregulatory.com) - **CPUC Draft Decision Examines 2022-2023 Gas Price Spikes:** "...SoCalGas customers saw an average 147-percent increase in their January 2023 gas bills compared with January 2022 bills, and PG&E’s customers saw, on average, a 30-percent increase in their gas bills over the same period." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regulation%5Fstatus/cpuc-draft-decision-examines-2022-2023-gas-price-spikes/article%5Feeee0113-6bb2-4917-bed6-10a9b751bc13.html?ref=calregulatory.com) - **EPA Blocks California's Out-of-State Truck Inspection Rule:** "The U.S. Environmental Protection Agency [issued](https://www.epa.gov/newsreleases/epa-stops-another-california-scheme-impose-its-costly-vehicle-policies-entire-country?ref=calregulatory.com) a final rule January 27, 2026 disapproving of California’s inspection and maintenance requirements on out-of-state trucks passing through the state. The EPA approved California’s Heavy-Duty Inspection and Maintenance Regulation only as it applies to in-state registered vehicles. The EPA [proposed](https://www.californiaenergytransition.com/p/epa-proposes-to-prevent-california?ref=calregulatory.com) its disapproval of the so-called Clean Truck Check rule on out-of-state vehicles in August 2025." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/epa-blocks-californias-out-of-state?ref=calregulatory.com) - **Evaluating the Drivers of PG&E Electricity Rate Growth:** "Despite existing legislative requirements, the CPUC does not regularly audit IOU spending to verify that expenditures approved in each GRC were spent as authorized. Absent such oversight, ratepayers face the risk of funding the same activities multiple times, approved activities not happening, and funds being redirected for activities never authorized in the GRC. The CPUC should increase its audit capacity to systematically conduct retrospective reviews when evaluating new IOU revenue requests in each GRC cycle." [**AVA COMMUNITY ENERGY**](https://avaenergy.org/wp-content/uploads/2026/02/Evaluating-the-Drivers-of-PGE-Electricity-Rate-Growth.pdf?ref=calregulatory.com) - **Federal Review Opens Path to New Drilling Off the Coast of California:** "The Bureau of Ocean Energy Management on January 26, 2026 [issued](https://www.boem.gov/newsroom/press-releases/boem-invites-public-input-potential-offshore-oil-and-gas-leasing-areas?ref=calregulatory.com) two Calls for Information and Nominations covering previously protected federal waters off Southern and Central California. The notices begin a preliminary review under the Outer Continental Shelf Lands Act and invite public and industry input on environmental conditions, potential commercial interest, and socioeconomic impacts. The 'calls' formally initiate a process that could lead to the first new offshore lease sales in the region since 1984." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/federal-review-opens-path-to-new?ref=calregulatory.com) - **The Case for Consumer-Regulated Electricity – Private Electricity Grids Offer a Parallel Path to Energy Abundance:** "New customers who value speed to power, exemplified by large data centers, are less concerned about the cost of electricity and more focused on the far greater business opportunity ahead of them. Put differently, the opportunity cost of not being able to run their facilities dwarfs the cost of electricity. Today’s power sector is holding those customers back, and it’s not merely a problem of insufficient generation or transmission. It is a problem of poor institutional design." [**CATO INSTITUTE**](https://www.cato.org/briefing-paper/case-consumer-regulated-electricity-private-electricity-grids-offer-parallel-path?utm%5Fcampaign=rates-hold-nerc-demand-rise-nuclear-scale-challenges&utm%5Fmedium=referral&utm%5Fsource=www.gridbrief.com#electricity-crunch-new-era-demand-growth) - **The Radical Grid Idea Gaining Traction on the Right – and the Left:** "California already has [some degree of retail choice](https://www.rstreet.org/wp-content/uploads/2025/05/Final-Study-No.-324-1.pdf?ref=calregulatory.com), although a more expansive version of a retail competition model infamously collapsed during the 2001 rolling blackouts." [**HEATMAP**](https://heatmap.news/energy/consumer-regulated-electricity?ref=calregulatory.com) - **Tom Steyer Vows to Cut Electricity Bills by 25% but Experts Say the Details Fall Short:** "Steyer says there are some ways to force the major investor-owned utilities to lower rates: by giving customers more options of who to buy power from; hooking up new renewable generation sources to the grid faster; and, with the advent of better solar and battery technology, allowing more power to be bought and sold at the neighborhood level. 'We have a lot of flat roofs in this state and those flat roofs can do solar,' he said at a press conference this month." [**CAL MATTERS**](https://calmatters.org/politics/2026/01/governor-steyer-electricity-rates/?ref=calregulatory.com) - **Valero Shut Down Benicia Refinery January 31st – CA Gas Prices Already Climbing:** "California today produces less than 23% of its own in-state petroleum needs and imports over 65% of its crude oil from foreign sources, yet the oil and gas industry in California account for nearly 8% of the state’s GDP, even in its diminished capacity." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fl/valero-shut-down-benicia-refinery-jan-31st-ca-gas-prices-already-climbing/?ref=calregulatory.com) - **Western Natural Gas Providers Watching Post-Fern Pricing:** "...Constellation analysts found that more gas-fired generation in northern California was moved south, 'explaining why SP15 day ahead prices have cleared over NP15 despite abundant sunshine and solar production.' The analysts called this 'welcome news for gas storage operators who were looking for the opportunity to pull gas out of storage in order to clear space for the upcoming refill season.' They also noted SoCalGas’ filing to maintain or increase Aliso Canyon storage inventory levels." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regional%5Froundup/western-natural-gas-providers-watching-post-fern-pricing/article%5F4959b7b5-5599-45f9-9ffb-804654affbee.html?ref=calregulatory.com) ### DEEP DIVE: SDG&E's $11.3 Million Demand Flexibility Filing - Compliance, with Reservations URL: https://www.calregulatory.com/deep-dive-sdg-es-11-3-million-demand-flexibility-filing-compliance-with-reservations/ Last updated: 2026-02-03T21:46:28.000Z ## **TL;DR** - **What happened:** SDG&E filed a compulsory demand flexibility rate application, requesting $11.3 million in cost recovery through 2036. - **The subtext:** The utility is building a defensive record. SDG&E cites $2.4 million spent on an export pilot with zero enrollment, notes 80% of its customers take Community Choice Aggregator generation service (meaning most can't access full demand flexibility benefits), and repeatedly cites affordability concerns. - **Rate design:** Opt-in only. Day-ahead CAISO pricing with price caps/floors. Location-based distribution adders across 10 circuit clusters. One-year minimum enrollment. Net Energy Metering, Net Billing Tariff, and conjunctive billing customers are excluded. - **The buried data point:** Negative wholesale pricing hours jumped from 43 (2022) to 989 (2024), a 23 x increase suggesting California's solar surplus problem is intensifying faster than rate design can accommodate. - **Bottom line:** This is demand flexibility designed not to scale. SDG&E has complied appropriately with CPUC guidance while constructing a paper trail that could justify minimal deployment for years. Protests/responses are due **March 5**. --- ## Application Summary SDG&E filed a [new application](https://www.sdge.com/sites/default/files/regulatory/2026-02/A2602XXX%5FSDGE%202026%20Demand%20Flex%20Rate%20Application.pdf?ref=calregulatory.com) seeking CPUC approval for opt-in demand flexibility rates in compliance with a 2025 decision ([D.25-08-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K182/578182496.PDF?ref=calregulatory.com)). The proposal would introduce rates that provide participating customers with day-ahead hourly price signals, Time-of-Use transmission charges, and location-based distribution pricing. In theory, this offering would allow customers to shift electricity usage in response to granular price signals. SDG&E states that potential benefits include more efficient load shifting, opportunities for bill savings, and improved grid reliability. But it also expresses reservations about pursuing a complex new rate design at this time given affordability concerns, limited demonstrated customer interest, and the fact that about **80%** of customers take generation service from Community Choice Aggregators that are not planning to offer complementary demand-flexible commodity rates. SDG&E requests authorization to recover approximately **$11.3 million** in revenue requirements associated with planning, design, billing system modifications, customer protections, marketing, and implementation of the demand flexibility rates. Cost recovery will be phased in beginning as early as 2028 through 2031, with any post-2031 recovery addressed in future General Rate Cases. SDG&E emphasizes that its prior export pilot saw no customer enrollment despite $2.4 million in spending, and that similar pilots at PG&E and SCE have not yet been fully evaluated, reinforcing the utility’s view that a cautious, affordability-focused approach is warranted. ## Accompanying Testimony Below are brief summaries of SDG&E's accompanying testimony. ### [POLICY](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%201%5FDemand%20Flex%20Rates%5FPolicy%5FV2.pdf?ref=calregulatory.com) SDG&E explains that the demand flexibility rate application is filed to comply with D.25-08-049, but the utility is explicit that it does not view broad demand flexibility deployment as cost-effective or prudent under current affordability conditions. The utility emphasizes that most customers in its service territory receive generation service from CCAs that are not planning to offer demand flexibility commodity rates, meaning fewer than 20% of customers would see full demand flexibility benefits. SDG&E also cites the lack of enrollment in its existing [Dynamic Export Rate Pilot](https://www.sdge.com/dynamic-export-rate-pilot-program?ref=calregulatory.com) and the incomplete evaluation of PG&E and SCE demand flexibility pilots as reasons for caution. Nonetheless, the application proposes demand flexibility rates designed to meet [Load Management Standards](https://www.energy.ca.gov/programs-and-topics/topics/load-flexibility/load-management-standards?ref=calregulatory.com), provide hourly day-ahead price signals, and preserve customer protections while balancing implementation complexity, equity considerations, and revenue stability. ### [COMMODITY/GENERATION](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%202%5FDemand%20Flex%20Rates%5FCommodity%20Generation.pdf?ref=calregulatory.com) This chapter describes the generation commodity components of the demand flexibility rates, which consist of **Marginal Energy Costs** and **Marginal Generation Capacity Costs**. - Marginal Energy Costs are based on CAISO day-ahead Default Load Aggregation Point prices and incorporate distribution and transmission loss factors to reflect meter-level delivery costs. - Marginal Generation Capacity Costs are calculated using a cost-of-new-entry framework based on four-hour lithium-ion battery storage, with values derived from the most recent Integrated Resource Plan inputs. Flexible capacity is valued at **$0.00**, reflecting SDG&E’s determination that existing resources are sufficient to meet ramping needs. The Marginal Generation Capacity Cost is applied using a Top 150-hour approach based on system load, intended to preserve price responsiveness while maintaining revenue stability. Non-marginal generation costs would be recovered through an **Equal Percent of Marginal Cost** factor applied to the Marginal Energy Cost component, embedding them in the hourly price signal. SDG&E evaluated three approaches for applying the MGCC; the two Loss of Load Probability-based methods would have collected more than the entire $595 million commodity revenue requirement: | Approach | Revenue | % of Hours | On-Peak | Off-Peak | Super Off-Peak | | ----------------------------- | ------- | ---------- | ------- | -------- | -------------- | | LOLP Function, Summer On-Peak | $864M | 2.69% | 100% | 0% | 0% | | LOLP Function, All Hours | $1.31B | 4.77% | 65.84% | 28.73% | 5.43% | | Top 150 | $115M | 1.78% | 64.74% | 29.80% | 5.46% | ### [DISTRIBUTION & TRANSMISSION](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%203%5FDemand%20Flex%20Rates%5FDistribution%20and%20Transmission.pdf?ref=calregulatory.com) SDG&E proposes location-based distribution pricing through circuit-level distribution capacity hourly adders that apply during forecasted top-200 circuit peak hours on a day-ahead basis. - To simplify implementation, SDG&E clusters its 1,030 circuits into 10 groups based on residential/non-residential load mix, balancing locational pricing with billing system constraints. These adders are designed to recover peak-related distribution costs estimated at **6.2%** of marginal distribution demand costs. Other distribution components, including monthly service fees and non-coincident demand charges, remain unchanged from existing default tariffs. The following table illustrates how these adders vary by customer class and circuit cluster: | Customer Class | Cluster 1 (Most Residential) | Cluster 8 (Peak) | Cluster 10 (Most Commercial) | | ---------------- | ---------------------------- | ---------------- | ---------------------------- | | Residential | $0.136 | $0.189 | $0.187 | | Small Commercial | $0.104 | $0.145 | $0.143 | | M/L C&I | $0.093 | $0.129 | $0.128 | | Agricultural | $0.077 | $0.106 | $0.105 | *Adders apply during forecasted top-200 circuit peak hours. Rates vary up to 37% based on circuit cluster assignment. Source: SDG&E A.26-02-XXX, Attachment C.* - On the transmission side, SDG&E acknowledges it cannot yet implement the hourly transmission rates contemplated by the Guidance Decision due to billing system limitations. As an interim measure, it proposes time-varying base transmission TOU energy rates for residential, small commercial, and agricultural customers, with plans to implement hourly rates later. M/L C&I customers will continue paying existing non-coincident and on-peak demand charges, updated to reflect the utility's 2025 Transmission Cost Study finding that 8.1% of transmission costs are peak-related. The combined design aims to promote efficient utilization of SDG&E's distribution and transmission systems by sending time-differentiated and location-based price signals. ### [CUSTOMER PROTECTION](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%204%5FDemand%20Flex%20Rates%5FCustomer%20Protection.pdf?ref=calregulatory.com) This chapter outlines SDG&E’s proposed customer protection framework, focused on price limits rather than bill credits or after-the-fact bill protections. The utility proposes ceilings and floors on marginal energy prices, along with inherent limits on generation and distribution capacity charges, to reduce exposure to sustained high prices while maintaining incentives to shift load. SDG&E argues that price limits are simpler to implement, easier for customers to understand, and less likely to create cost shifting between participants and non-participants. The chapter also includes analysis of estimated bill impacts and revenue effects to demonstrate compliance with CPUC requirements for stability and fairness. SDG&E's own analysis of historical CAISO prices shows the $0 floor would be triggered far more often than the $750 ceiling, and that negative pricing is accelerating rapidly: | Year | Hours > $750/MWh | Hours < $0/MWh | | ---- | ---------------- | -------------- | | 2022 | 16 | 43 | | 2023 | 3 | 263 | | 2024 | 0 | 989 | Source: SDG&E testimony, Table JDT-4 (CAISO prices, SDG&E area) ### [IMPLEMENTATION](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%205%5FDemand%20Flex%20Rates%5FImplementation.pdf?ref=calregulatory.com) SDG&E describes how the demand flexibility rates would be implemented across all customer classes except streetlighting, with participation offered on an opt-in basis. Eligibility exclusions include customers on Net Energy Metering, Net Billing Tariff, and conjunctive billing (which SDG&E deemed overly complex and cost-prohibitive with limited incremental customer benefit) as well as grandfathered TOU rates. SDG&E details enrollment and unenrollment rules designed to limit rate arbitrage, including a minimum one-year stay consistent with Electric Rule 12\. Hourly prices would be posted day-ahead on SDG&E’s website and the MIDAS platform, and customers would have access to hourly usage data through existing portals. Total implementation costs are estimated at **$9.5 million**, which SDG&E proposes to recover through the Public Purpose Program rate component. The resulting rate impact is minimal. | Customer Class | Current Rate(¢/kWh) | Change(¢/kWh) | Change(%) | | ---------------- | ------------------- | ------------- | --------- | | Residential | 17.53 | 0.02 | 0.04% | | Small Commercial | 15.39 | 0.02 | 0.04% | | M/L C&I | 19.28 | 0.02 | 0.04% | | Agriculture | 13.04 | 0.02 | 0.07% | | Lighting | 11.99 | 0.02 | 0.05% | | System Total | 17.68 | 0.02 | 0.05% | ### [MARKETING, EDUCATION, & OUTREACH](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%206%5FDemand%20Flex%20Rates%5FMarketing.pdf?ref=calregulatory.com) This chapter presents a phased Marketing, Education, and Outreach strategy aimed at building awareness and supporting customer understanding of demand flexibility rates while avoiding direct outreach to ineligible customers (those on Net Energy Metering, Net Billing Tariff, conjunctive billing, or grandfathered rates) and deferring targeted outreach to equity and access customers until pilot results confirm they would benefit. SDG&E proposes research-based messaging, customer segmentation, and multi-channel outreach, with particular attention to affordability, accessibility, and coordination with CCAs. The Marketing, Education, and Outreach plan emphasizes clear explanations of demand flexibility concepts, behavioral guidance for enrolled customers, and flexibility to adjust messaging based on Demand Flexibility Pilot results, the [2025 Low Income Needs Assessment](https://www.calmac.org/publications/2025%5FLINA%5FFinal%5FReport%5F103025.pdf?ref=calregulatory.com), and SDG&E's Measurement and Evaluation findings. ### [MEASUREMENT & EVALUATION](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20PUBLIC%20VERSION%5FChapter%207%5FDemand%20Flex%20Rates%5FMeasurement%20and%20Evaluation.pdf?ref=calregulatory.com) SDG&E proposes a two-year Evaluation, Measurement, and Verification plan to assess customer response to demand flexibility price signals, enrollment trends, load impacts, and bill effects. The evaluation will rely on interval usage data, customer surveys, and comparisons between demand flexibility participants and non-participants across customer classes. An external evaluator will be retained through a Request for Proposals process to conduct evaluation activities and administer customer surveys. Results from the Evaluation, Measurement, and Verification process are intended to inform future refinements to demand flexibility rate design. ### [COST RECOVERY](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%208%5FDemand%20Flex%20Rates%5FCost%20Recovery.pdf?ref=calregulatory.com) SDG&E requests authorization to establish a Demand Flexibility Balancing Account to track incremental capital and O&M costs associated with implementing the demand flexibility rates. The Demand Flexibility Balancing Account would be a two-way, interest-bearing account recorded on SDG&E's financial statements that would record authorized revenue requirements and actual costs, ensuring that over- or under-collections are returned to or recovered from ratepayers in a timely manner. Annual reconciliation of the Demand Flexibility Balancing Account balance would occur through SDG&E's Annual Regulatory Account Balance Update. SDG&E proposes to use the account until demand flexibility costs are incorporated into base rates in a future General Rate Case, at which point SDG&E may propose to close the Demand Flexibility Balancing Account and roll ongoing revenues and expenses into the appropriate account. ### [REVENUE REQUIREMENT](https://www.sdge.com/sites/default/files/regulatory/A.2602XXX%20Chapter%209%5FDemand%20Flex%20Rates%5FRevenue%20Requirement.pdf?ref=calregulatory.com) SDG&E presents a forecasted incremental revenue requirement of approximately $11.5 million over the 2027–2036 period to support demand flexibility rate implementation (though Table DS-3 totals to **$11.3 million**, creating an unexplained **$200,000** discrepancy with the narrative). The revenue requirement includes: - Capital costs for computer software; - Ongoing O&M; - Overhead allocations; - Escalation; - AFUDC (Allowance for Funds Used During Construction i.e., interest capitalized on capital spending while assets remain in construction work in progress); - Working cash; - Taxes; - Franchise fees and uncollectibles; and - Authorized return. All costs are identified as incremental to amounts authorized in SDG&E's most recent General Rate Case and would be recovered in accordance with the proposed cost recovery mechanism. | | 2027 | 2028 | 2029 | 2030 | 2031 | 2032–36 | Total | | ------------------- | ------ | ---- | ---- | ---- | ---- | ------- | ----- | | CPUC | ($0.7) | $2.9 | $3.4 | $2.3 | $1.5 | $0.9 | $10.3 | | FERC | (0.3) | 0.3 | 0.3 | 0.3 | 0.2 | 0.2 | 1.0 | | Revenue Requirement | ($1.0) | $3.2 | $3.7 | $2.6 | $1.7 | $1.1 | $11.3 | SDG&E Demand Flexibility Rates: Forecasted Revenue Requirement, 2027–2036 ($ millions). Source: SDG&E-09, Table DS-3\. Capital investment concentrated in 2027 produces a negative first-year revenue requirement before flipping positive as depreciation and return on rate base flow through subsequent years. CPUC-jurisdictional costs account for approximately 91% of the $11.3 million total. ### INSTANT ANALYSIS This filing is a compliance-driven proposal rather than an affirmative push for widespread demand-flex adoption. SDG&E repeatedly voices skepticism about customer uptake, cost-effectiveness, and timing, and builds a record that prioritizes affordability caution over experimentation. The utility appears to be positioning demand flexibility rates as a narrow, optional tool for sophisticated customers, not a mass-market reform. The biggest constraint: with about 80% of customers taking generation service from CCAs that do not plan to offer demand flexibility commodity rates, the practical impact of the proposal is inherently limited. SDG&E leans on this fact to justify a restrained design, modest expectations for enrollment, and a heavy emphasis on customer protections and revenue stability. From a policy perspective, the application is loyal to the CPUC's design parameters: day-ahead CAISO pricing, marginal cost recovery, and location-based signals, while minimizing exposure to downside risk. Price caps, opt-in enrollment, one-year lock-ins, and a balancing account all work to contain volatility and prevent cost shifting. ### MONDAY AGGREGATE: Water District Petition Suggests Crack in SGIP Program Logic; CAISO Documents Multi-State Market Options URL: https://www.calregulatory.com/monday-aggregate-water-district-petition-suggests-crack-in-sgip-program-logic-caiso-documents-multi-state-market-options/ Last updated: 2026-02-02T20:51:31.000Z Today's roundup includes summaries of the following items. - A new petition for modification of a 2011 CPUC decision governing the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) that exposes a mismatch between SGIP’s site-based sizing rules and the portfolio-based self-generation model explicitly authorized for local governments under the [Renewable Energy Self-Generation Bill Credit Transfer](https://sdcommunitypower.org/wp-content/uploads/2022/04/SDCP-RESBCT-Terms-and-Conditions-of-Service.pdf?ref=calregulatory.com) framework. - The CAISO's Assembly Bill 825 Report, a document that preserves optionality for a potential expansion of voluntary, multi-state wholesale electricity markets governed by an independent regional organization. - A ruling in PG&E's [2024 ERRA Compliance filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K607/557607577.PDF?ref=calregulatory.com) that addresses a narrow vintaging issue affecting a small subset of Community Choice Aggregator customers. - A 2025 Demand Response audit detailing compliance with CPUC rules prohibiting the use of certain fossil-fueled distributed generation resources to produce DR load reductions. - An SDG&E informational filing that confirms the Department of Energy's rescission of the ARCHES hydrogen hub award and issuance of a termination directive. ### SELF-GENERATION INCENTIVE PROGRAM [Moulton Niguel Water District](https://www.mnwd.com/?ref=calregulatory.com) filed a [petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K305/597305738.PDF?ref=calregulatory.com) seeking to modify a 2011 decision ([D.11-09-015](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/143459.PDF?ref=calregulatory.com)) governing the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) (SGIP). The petition argues that current SGIP sizing rules conflict with the [Renewable Energy Self-Generation Bill Credit Transfer (RES-BCT)](https://sdcommunitypower.org/wp-content/uploads/2022/04/SDCP-RESBCT-Terms-and-Conditions-of-Service.pdf?ref=calregulatory.com) framework available to local governments. The District plans to install a 224-kW in-conduit micro-hydropower system at its Bridlewood Flow Control Facility that would generate roughly 820 MWh annually (far more than the facility’s onsite load) and apply the excess generation as bill credits across its broader portfolio of SDG&E accounts under RES-BCT. While RES-BCT explicitly allows this portfolio-wide self-generation model, the SGIP Handbook limits incentives to generation sized to the load at the physical site, effectively disqualifying much of the project’s capacity. The District asks the Commission to clarify that a local government participating in RES-BCT is still “offsetting onsite load” within the meaning of [Public Utilities Code section 379.6(e)(1)](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-379-6/?ref=calregulatory.com), and therefore eligible for SGIP incentives for the full system capacity. The petition asks the CPUC to direct program administrators to update the SGIP Handbook accordingly. The petition emphasizes that aligning SGIP with RES-BCT would remove an internal policy inconsistency and unlock stranded SGIP Generation budget funds. **ADDED CONTEXT:** This petition arrives under a procedural cloud. Nine days before Moulton Niguel re-filed, **Commissioner Karen Douglas** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495666.PDF?ref=calregulatory.com) denying Bloom Energy's petition to increase the SGIP export cap from 25% to 50% (*see CRI's coverage* [*here*](https://www.calregulatory.com/fuel-cell-and-biogas-interests-hit-procedural-wall-in-push-to-double-sgip-export-cap/)). [Proposed Decision Denies Doubling of SGIP Export CapFuel Cell and Biogas Interests Hit Procedural Wall in Push to Double SGIP Export Cap![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-16.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/fuel.png)](https://www.calregulatory.com/fuel-cell-and-biogas-interests-hit-procedural-wall-in-push-to-double-sgip-export-cap/) The PD rejects Bloom's justification that technology evolution excused a 13-year delay, finding that routine technological or policy change cannot justify reopening settled decisions. Moulton Niguel's petition faces the same timeliness hurdle but may present a stronger case. Unlike Bloom's export-cap request (which the PD characterizes as inconsistent with SGIP's load-serving purpose), Moulton Niguel's request reinforces rather than undermines that purpose: it seeks to count portfolio-wide load for RES-BCT participants, not to enable greater grid exports. **INSTANT ANALYSIS:** This petition exposes a consequential mismatch between SGIP’s site-based sizing rules and the portfolio-based self-generation model explicitly authorized for local governments under RES-BCT. Moulton Niguel’s project is baseload, conduit hydropower that converts otherwise wasted pressure into continuous clean generation, with clear grid, emissions, and resiliency benefits. - The policy issue is narrow: whether “onsite load” under SGIP can be interpreted at the local-government portfolio level when RES-BCT is used. Energy Division staff previously endorsed that interpretation, and the administering program administrator supports it, suggesting limited institutional resistance. - Denial risks stranding remaining SGIP Generation funds while discouraging a class of infrastructure-adjacent distributed resources that perform well during peak and emergency conditions. --- ### CAISO NEWS/ASSEMBLY BILL 825 The CAISO submitted its[ 2026 Assembly Bill 825 Report](https://www.caiso.com/documents/ab-825-report-feb-02-2026.pdf?ref=calregulatory.com) to the Legislature, which provides a comprehensive accounting of CAISO activities in 2025 as required under [Assembly Bill 825](https://www.jonesday.com/en/insights/2025/12/californias-new-regional-power-market-law-a-catalyst-for-renewable-energy-growth?ref=calregulatory.com). Recall that this legislation was enacted to support the potential expansion of voluntary, multi-state wholesale electricity markets governed by an independent regional organization. The report explains that, beginning no earlier than 2028, the CAISO could pursue FERC-approved tariff changes to enable such a transition, but only if statutory conditions are met, the CAISO Board affirms compliance, and the CPUC authorizes IOU participation. For 2025, the report is limited to CAISO-only activities, as the regional governance entity contemplated by AB 825 remains in formation. - The report documents extensive federal tariff activity during 2025, including compliance filings, market-design amendments, interconnection agreements, [EDAM](https://www.westernenergymarkets.com/extended-day-ahead-market-edam?ref=calregulatory.com)\-related changes, and settlements, most of which were approved by FERC. These filings span transmission service priorities, interconnection process reforms, billing and credit rules, market enhancements for storage, congestion revenue allocation, capacity procurement mechanisms, and agreements enabling broader Western market participation through the EDAM and [Western Energy Imbalance Market](https://www.westernenergymarkets.com/?ref=calregulatory.com). - The report also outlines the status of the CAISO’s major policy initiatives and recurring processes, emphasizing a structured, stakeholder-driven roadmap for market evolution. Active initiatives in 2025 included congestion revenue rights enhancements, day-ahead and extended day-ahead market development, demand and distributed energy integration, storage market design, gas resource management, greenhouse gas coordination, price formation reforms, and Resource Adequacy modeling updates. Additionally, the CAISO continued its transmission planning cycles and independent release process to coordinate implementation timing and system needs. - The report further catalogs actions taken by the CAISO Board of Governors throughout 2025, including approvals of market design changes, interconnection reforms, EDAM congestion revenue allocation, Resource Adequacy modeling updates, transmission planning decisions, budget adoption, and governance matters. These actions reflect ongoing oversight of both grid reliability and evolving wholesale market frameworks. - The report summarizes assessments by the [CAISO’s Department of Market Monitoring](https://www.caiso.com/market-operations/market-monitoring?ref=calregulatory.com), which serves as the independent market monitor for both CAISO markets and the Western Energy Imbalance Market. It references annual and quarterly market performance reports, resource sufficiency evaluations, special studies on Demand Response and battery storage, and formal comments submitted to FERC and within CAISO stakeholder processes. The report concludes with a description of transmission planning activities, highlighting how CAISO evaluates reliability, public-policy, and economic needs through its annual transmission planning process in coordination with state agencies and stakeholders. The ISO Board approved the 2024-2025 Transmission Plan [in May 2025](https://www.caiso.com/about/news/news-releases/iso-board-of-governors-approves-2024-2025-transmission-plan?ref=calregulatory.com), recommending 31 transmission upgrades totaling an estimated **$4.8 billion** in infrastructure investment. The plan enables over **30 GW** of solar, **7 GW** of onshore wind, **2 GW** of geothermal, **9 GW** of out-of-state wind imports, and **4.5 GW** of offshore wind capacity (reflecting accelerated load growth, including a Greater Bay Area peak demand forecast increase of over 2,000 MW compared to the prior cycle). This coordinated approach follows a December 2022 Memorandum of Understanding among the CAISO, CPUC, and California Energy Commission to better align linkages between resource planning, transmission development, interconnection queuing, and procurement. The report also notes that the CAISO filed for compliance with [FERC Order No. 1920 ](https://www.ferc.gov/news-events/news/ferc-strengthens-order-no-1920-expanded-state-provisions?ref=calregulatory.com)in December 2025, which will require a transition from annual to biennial comprehensive transmission planning beginning in 2028, with a new 20-year planning horizon for regional facilities. **INSTANT ANALYSIS:** This report is a compliance and informational document, not a decision memo. It confirms that the CAISO spent 2025 laying procedural track (tariff hygiene, EDAM expansion, interconnection reform, and governance choreography) while keeping the statutory bar for any future regionalization deliberately high. Nothing here commits California to a multi-state market shift; instead, it preserves optionality by documenting readiness, process discipline, and federal alignment. The key takeaway is timing: the earliest legal pivot point remains 2028, and only if the CPUC, the CAISO Board, and FERC all independently concur. Until then, AB 825 functions as a guardrail, allowing exploration without surrendering state control. On the transmission side, the $4.8 billion in approved projects and the pivot to longer-horizon planning under Order 1920 indicate that California is building the physical infrastructure for decarbonization at scale, independent of whether regionalization ultimately proceeds. --- ### ENERGY RESOURCE RECOVERY ACCOUNT/UTILITY-OWNED GENERATION COMPLIANCE **ALJ Goldberg** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M597/K288/597288872.PDF?ref=calregulatory.com) in PG&E's [2024 ERRA Compliance filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M557/K607/557607577.PDF?ref=calregulatory.com) modifying the schedule and scope of PG&E’s 2024 Utility-Owned Generation compliance review. The ruling follows a finding that PG&E’s request for a six-month delay would push the case past the statutory 18-month deadline. The ruling focuses on a narrow vintaging issue affecting a small subset of Community Choice Aggregator customers (those who opted out, opted back in, and then moved within a CCA territory) where PG&E reports that only 163 customers fall into this category and that just eight may have been incorrectly vintaged. The ALJ: - Denies PG&E’s extension request; - Directs PG&E to file supplemental testimony by **March 11** (with workpapers included at CalCCA's request, to which PG&E did not object); - Reopens discovery on a limited and expedited basis through **April 10**; and - Sets an accelerated briefing schedule aimed at final resolution by August, the statutory deadline. The supplemental testimony must quantify the scope of any vintaging errors, propose customer remedies for 2024 billing impacts without reworking the entire Portfolio Allocation Balancing Account, and explain whether system programming changes are needed and how they would be funded. **INSTANT ANALYSIS:** This ruling rejects PG&E’s request for a lengthy extension, making clear that a potential error affecting a handful of CCA customers does not justify pushing the case past the August 2026 deadline. The ruling treats the vintaging issue as a limited accounting correction rather than a basis to reopen PG&E’s broader PABA framework. The ruling suggests that any misallocations should be resolved through customer-level remedies, not a recalculation of systemwide balances. This constrains both financial exposure and precedential spillover, while still giving CCAs a defined opportunity to examine PG&E’s vintaging logic and controls before the case moves to briefing and submission. --- ### DEMAND RESPONSE The electric investor-owned utilities (PG&E, SCE, and SDG&E) jointly filed a [2025 Verification Administrator’s Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K752/596752118.PDF?ref=calregulatory.com) detailing the annual audit of compliance with CPUC rules prohibiting the use of certain fossil-fueled distributed generation resources to produce Demand Response load reductions. Conducted by [Resource Innovations](https://www.resource-innovations.com/?ref=calregulatory.com) under [Resolution E-4906](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M216/K841/216841517.PDF?ref=calregulatory.com) and subsequent decisions, the audit examined 206 randomly selected non-residential participants across multiple Demand Response programs, including RA-eligible resources. The review combined attestation validation, cross-checks with IOU records and air quality permits, and (most notably for Scenario 2 customers) the installation and analysis of data loggers on prohibited resources during the 2025 event season. The audit found a high overall compliance rate of 93%, with no instances where prohibited resources were used during Demand Response event hours and no evidence of fuel switching from renewable to non-renewable sources. Identified issues were limited to administrative discrepancies, such as incorrect attestations or non-responses, with nine of 14 violations already cured and the remainder subject to cure windows through late January before escalation. The report concludes that the verification framework is functioning as intended (both reinforcing compliance through regular oversight and providing statistically reliable compliance estimates) while recommending clearer guidance for handling sites with multiple small, portable generators that rotate across locations. **INSTANT ANALYSIS:** The 2025 DR Prohibited Resources audit shows the compliance regime is mostly working as designed. Across 206 audited accounts, there were no cases where fossil-fueled generators were used during DR event hours, even among Scenario 2 sites monitored with continuous data loggers. Issues identified were administrative rather than behavioral (misclassified attestations, minor nameplate discrepancies, or non-responses) most of which are already curing within the allowed window. The one soft spot remains Local Capacity Requirements, where compliance rates are behind other programs, but even there the shortfall reflects paperwork and responsiveness, not improper generator dispatch. --- ### CLEAN ENERGY FUNDING SDG&E filed Advice Letter 4796-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to comply with Resolution E-5254’s requirement for quarterly reporting on federal clean-energy funding activity under the [Infrastructure Investment and Jobs Act](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com), [Inflation Reduction Act](https://en.wikipedia.org/wiki/Inflation%5FReduction%5FAct?ref=calregulatory.com), and [CHIPS Act](https://en.wikipedia.org/wiki/CHIPS%5Fand%5FScience%5FAct?ref=calregulatory.com). The filing provides SDG&E’s fourth-quarter 2025 update, covering seven active or pending projects and noting routine administrative updates across multiple entries. Most notably, SDG&E reports that the U.S. Department of Energy formally rescinded up to **$1.2 billion** in previously awarded funding for California’s [ARCHES hydrogen hub](https://archesh2.org/arches-officially-launches/?ref=calregulatory.com) in October 2025, issuing a termination directive instructing ARCHES to immediately cease all project activities. This was part of a broader federal review that terminated 223 clean-energy projects totaling $7.56 billion nationwide. Separately, DOE also cancelled SDGE-001, SDG&E's inverter-based resources grid protection demonstration project with Quanta/V&R Energy. While ARCHES leadership has indicated an intent to continue pursuing hydrogen development through state and private avenues, SDG&E states it is awaiting further direction. **INSTANT ANALYSIS:** This procedural filing confirms a significant reversal in federal clean-energy funding: DOE’s rescission of the ARCHES hydrogen hub award and issuance of a termination directive. That development highlights the fragility of large, federally sponsored hydrogen initiatives and introduces renewed uncertainty around California’s hydrogen roadmap. For ratepayers, the immediate impact is muted (no cost recovery is triggered and no rates are affected) but the longer-term implication is that projects once assumed to be federally backstopped may now re-emerge in state proceedings seeking alternative funding or recovery mechanisms. The ARCHES outcome is an early warning that federal clean-energy grants should be treated as contingent rather than settled when evaluating future utility investment strategies and risk allocation. ### FRIDAY AGGREGATE: Update on $190 Million THUMS Oil Islands Cable Replacement; Slow SCE Movement in Microgrid Incentive Program URL: https://www.calregulatory.com/friday-aggregate-update-on-190-million-thums-oil-islands-cable-replacement-slow-sce-movement-in-microgrid-incentive-program/ Last updated: 2026-01-30T21:48:19.000Z Today's roundup touches on SCE's role in the Microgrid Incentive Program, an agreement serving the [THUMS artificial oil islands](https://www.calregulatory.com/r/f8f7b1c7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6), the Low Carbon Fuel Standard, and PG&E's Risk Assessment and Mitigation Phase ("RAMP") submission. --- ### MICROGRIDS SCE filed Advice Letter 5737-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)), which contains its Q4 2025 quarterly status report for the [Microgrid Incentive Program](https://www.sce.com/partners/3rd-party-energy-providers/microgrid-incentive-program?ref=calregulatory.com), as required by a 2023 decision ([D.23-04-034](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M505/K732/505732868.PDF?ref=calregulatory.com)). The report shows that program activity remains limited and largely administrative. No new outreach occurred in Q4 due to the closure of initial consultation windows and uncertainty around future funding rounds. During Round 2, SCE completed four technical consultations and received five applications before the December 31, 2025 deadline, bringing the cumulative total to six applications across Rounds 1 and 2\. - Only one project has been awarded to date (from Round 1), and it has not yet entered interconnection or special facilities studies; execution of its performance agreement is expected in early 2026\. - No microgrids are operational, and no incentive, interconnection, or special facilities payments have been made beyond a single **$25,000** application development grant. - Financially, the program remains mostly unspent: of the **$91.3 million** authorized budget, about **$559,000** (0.6%) has been paid, almost entirely for administration, while **$17.8 million** (about 20% of the total budget) is committed but not yet disbursed. SCE reports no unintended outcomes, no active operating agreements, and no accruals beyond administrative costs, with meaningful expenditures deferred until projects advance out of early contracting and study phases. **INSTANT ANALYSIS**: SCE’s filing demonstrates how slowly the program is translating authorization into steel in the ground. Nearly three years after implementation rules were adopted, only one project has been awarded, no interconnection or special facilities studies have begun, and no microgrids are operating. Spending remains overwhelmingly administrative, with less than 1% of the $91.3 million authorized budget actually paid out, even as roughly one-fifth of total funds are now nominally committed. The bottleneck is no longer policy design but execution: applications have closed, Round 2 applications will undergo eligibility checks and evaluation starting in Q1 2026, and all material costs are pushed into future years. For stakeholders tracking resiliency delivery rather than paper progress, the report highlights a widening gap between program intent and on-the-ground outcomes, with meaningful deployment unlikely until contracting and study work finally clears in 2026 --- ### ARTIFICIAL OIL ISLANDS/ADDED FACILITIES In a joint mediation statement SCE, THUMS Long Beach Company, and the City of Long Beach [report continued progress toward a negotiated sale of the THUMS “Added Facilities” to THUMS in A.24-12-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K296/596296905.PDF?ref=calregulatory.com). **Background** - In 2024, SCE filed an [application](https://www.calregulatory.com/r/31b38cef?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) (A.24-12-001) to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the [THUMS artificial oil islands](https://www.calregulatory.com/r/f8f7b1c7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) must be replaced under a new, customer-financed Added Facilities Agreement, with THUMS or any successor customer providing all upfront capital and assuming all removal-cost risk. - SCE argued that [Rule 2](https://www.calregulatory.com/r/f9dc838d?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) and the 1965 Added Facilities Agreement require the customer (not general ratepayers) to fund these special, oil-field-specific facilities. Rule 2 only added customer-financed Added Facilities Agreements as an option in 1983, and replacement coverage only became available for SCE-financed Added Facilities Agreements in 1996 (not retroactively). The 1965 THUMS Added Facilities Agreements predates both provisions and contains no replacement coverage. - With replacement estimated at **$190 million** \+ and likely to take a decade amid declining oil production, [Senate Bill 1137](https://www.calregulatory.com/r/75e6c314?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) buffer-zone restrictions, and State/City plans to retire offshore drilling, SCE warned that utility financing could strand nine-figure assets and violate longstanding policy that added-facility costs cannot shift to the broader rate base. - SCE proposed that any new agreement follow Commission-approved Form 16-309, the standard template for customer-financed Added Facilities Agreements that includes removal cost provisions. - Last fall – in response to an ALJ request – the City of Long Beach and THUMS [submitted a joint filing](https://www.calregulatory.com/r/e8ad068b?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6) clarifying that the Long Beach Unit (the eastern [Wilmington Oil Field](https://www.calregulatory.com/r/2c008ff7?m=6f7cf2d6-b170-4e49-afbf-e774eb5bbef6), including the four THUMS islands, is owned by the State, held in trust by the City, and operated with THUMS as the field-contractor’s agent). They reported that the State Lands Commission provides oversight but has declined to participate directly in this proceeding, instead deferring to the City in its trustee role. **Mediation Statement** The new statement from SCE, THUMS Long Beach Company, and the City of Long Beach describes a full-day mediation in July 2025 followed by ongoing confidential negotiations, including site visits to the [Pico Substation](https://ia.cpuc.ca.gov/environment/info/pico.htm?ref=calregulatory.com), exchanges of draft sale terms, and continued discussions through mid-January 2026, with plans to update the Commission again in late February. - The mediating parties state they were prepared to discuss the confidential negotiations at a status conference (held yesterday), though they did not anticipate being able to provide additional detail beyond what appears in the filing. - Cal Advocates is not joining this portion of the statement and instead submits a separate position arguing that, as a matter of law, SCE's request to recover replacement facility costs from ratepayers must be dismissed with prejudice. - Cal Advocates requested coordination on January 14, proposing a schedule for joint drafting, but the mediating parties did not provide a draft statement until January 21 and never contacted Cal Advocates to discuss the mediation itself. - Cal Advocates cites D.70659, which approved the original facilities arrangement only on the condition that ratepayers bear none of the costs, and contends that SCE’s own application acknowledges this prohibition. - Cal Advocates further argues that allowing mediation to proceed without resolving the ratepayer issue risks obscuring future cost exposure, undermines intervenor rights, and delays efficient resolution. Consequently, Cal Advocates urges the CPUC to dispose of the ratepayer recovery request now rather than await the outcome of private settlement talks. THUMS and the City of Long Beach have also filed their own motion to dismiss SCE's application on separate grounds (ripeness and jurisdictional deficiencies), distinct from Cal Advocates' ratepayer protection argument. **INSTANT ANALYSIS**: This mediation update shows the case moving on two tracks: - Progress toward a negotiated sale of the THUMS facilities; and - An unresolved dispute over whether ratepayers can ever be exposed to replacement costs. The latter remains the controlling issue. Cal Advocates’ position narrows the CPUC’s options. Decision 70659 approved these oil-specific added facilities only on the condition that ratepayers bear none of the costs, a premise SCE itself acknowledges. A settlement cannot bypass that constraint if it relies on utility financing or abandonment protection. The case has implications for how the CPUC will treat aging, single-customer oil infrastructure in a phase-down environment. How the CPUC resolves the ratepayer question here may carry ripple effects for other legacy Added Facilities Agreements facing end-of-life replacement decisions. --- ### LOW CARBON FUEL STANDARD SDG&E filed coordinated advice letters (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) in which it seeks approval of updated [Low Carbon Fuel Standard](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification/charging-infrastructure-deployment-and-incentives/low-carbon-fuel-standard?ref=calregulatory.com) (LCFS) holdback revenue implementation plans and corresponding exemptions from Public Utilities Code Section 851, as required by a 2020 CPUC decision ([D.20-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M356/K223/356223853.PDF?ref=calregulatory.com)). The filings outline how SDG&E proposes to deploy its share of LCFS residential “holdback” credits (after the required **25%** contribution to the statewide [California Clean Fuel Reward](https://cleanfuelreward.com/?ref=calregulatory.com)) across a set of transportation electrification programs aimed at lowering adoption barriers. **Advice Letter 4794-E** - This filing focuses on the residential side of the portfolio. SDG&E proposes a new Residential Charging Rebate Program that would provide one-time rebates for the purchase and installation of Level 2 electric-vehicle chargers, with additional support for panel upgrades or panel-upgrade avoidance technologies. The filing also seeks approval to extend SDG&E’s existing [Pre-Owned Electric Vehicle rebate program](https://evrebates.sdge.com/?ref=calregulatory.com), which launched in 2024, through 2027\. - SDG&E frames these programs as addressing persistent cost and infrastructure barriers to EV adoption, particularly for income-qualified and underserved customers, and emphasizes that LCFS proceeds allow these benefits to be delivered without relying on ratepayer funding. - SDG&E proposes to track revenues and expenditures through its existing LCFS balancing account and requests an effective date of **March 1**. **Advice Letter 4795-E** - This filing addresses a complementary but distinct use of LCFS holdback revenues: the [Electric Vehicle High Power (EV-HP) Rate Incentive Program](https://www.sdge.com/business/electric-vehicles/power-your-drive-for-fleets/ev-hp?ref=calregulatory.com). Under this proposal, SDG&E would offer annual on-bill credits to customers taking service on the EV-HP rate to encourage off-peak and super-off-peak charging behavior. Customers would receive quarterly notifications showing their progress toward maximizing the annual credit. - Incentives would be tiered by customer load size, subject to quarterly caps, and include enhanced benefits for customers in disadvantaged communities. SDG&E positions the program as both bill relief and a load-management tool that aligns EV charging with grid conditions, thereby advancing electrification while mitigating peak impacts. **INSTANT ANALYSIS:** These paired advice letters show SDG&E drawing a clearer connection between LCFS revenues and grid outcomes. Instead of using LCFS holdback as a generic EV subsidy, SDG&E splits it between upfront help for residential charging constraints and ongoing bill credits that reward off-peak charging behavior. One lowers the entry cost; the other shapes how new load behaves once it arrives. If the filings are approved, the Commission would be reinforcing the idea that LCFS revenues are meant to influence load behavior and system outcomes, not just increase EV adoption totals. --- ### RISK ASSESSMENT & MITIGATION PHASE The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K902/596902581.PDF?ref=calregulatory.com) closing PG&E's 2024 Risk Assessment and Mitigation Phase (RAMP) proceeding, which serves as the front-end risk analysis for PG&E’s 2027 Test Year General Rate Case. The PD finds that PG&E’s RAMP filing, which uses a new cost-benefit framework to monetize safety and reliability risks, complies with Commission requirements despite multiple identified deficiencies. While the CPUC's [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) identified multiple methodological concerns (particularly around risk monetization, reliability valuation, alternative mitigation comparisons, and transparency) the PD determines none rose to a level warranting rejection. An April 2025 ruling required PG&E to address four specific deficiencies, including providing parallel risk-neutral analyses and disaggregated reliability cost calculations, which PG&E subsequently did using the newly-released ICE 2.0 calculator rather than the ICE 1.0 version used in its original RAMP filing, with remaining disputes explicitly folded into the GRC record. The PD declines to resolve broader framework disputes here, deferring them to the ongoing GRC or future rulemakings. Comments are due **February 19**. The earliest the Commission will consider this item is **March 19**. **INSTANT ANALYSIS:** This PD closes PG&E’s 2024 RAMP on a narrow finding of procedural sufficiency, while leaving substantive disputes to be examined in the 2027 GRC. The PD accepts that PG&E satisfied prior RAMP directives, including follow-on responses ordered in April 2025, but makes clear that unresolved questions about risk modeling, reliability valuation, mitigation alternatives, and rate impacts remain live issues. By channeling those disputes into the GRC, the PD ensures they will be tested in the context where capital spending, cost allocation, and customer rates are actually determined. The outcome should not be read as validation of PG&E’s preferred risk framework or mitigation portfolio. Expect scrutiny in the GRC to center on cost-benefit credibility, treatment of legacy controls with low cost-benefit ratios, justification of proposed mitigations versus realistic alternatives, and whether PG&E's mitigation strategy can be justified under escalating affordability concerns. ### IOUs Submit Final Electrification Impacts Study (Part 2): PG&E Claims Electrification Could Cut Rates 25% Despite Billions in Upgrades URL: https://www.calregulatory.com/ious-submit-final-electrification-impacts-study-part-2-pg-e-claims-electrification-could-cut-rates-25-despite-billions-in-upgrades/ Last updated: 2026-01-30T01:15:52.000Z The three large electric utilities have filed their final "Electrification Impacts Study Part 2" reports in the [High DER proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com), collectively outlining how electrification, policy, and demand flexibility could reshape distribution system investment through 2040\. (*See CRI's coverage of the draft studies,* [*here*](https://www.calregulatory.com/wednesday-aggregate-transmission-planning-sce-rates-biomethane-costs/) *and* [*here*](https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/)*.*) All three studies respond to a 2024 CPUC decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)) and evaluate multiple futures built on the California Energy Commission's [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) load forecasts, comparing a base planning case against equity-focused adoption patterns and varying levels of demand flexibility. ### **San Diego Gas & Electric** [SDG&E's filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K903/596903988.PDF?ref=calregulatory.com) frames electrification primarily as a distribution-level cost and capacity challenge under three scenarios: - Base Case; - Equity Scenario, and - Demand Flexibility Scenario. Under the Base Case, SDG&E projects peak load growth from approximately **6.2 GW** in the late 2020s to about **7.0 GW** by 2040, requiring more than **$3.2 billion** in primary and secondary distribution upgrades. Per SDG&E, concentrating Distributed Energy Resource adoption in disadvantaged communities raises both peak demand and infrastructure needs modestly, pushing total costs closer to **$3.6 billion** by 2040\. By contrast, the Demand Flexibility Scenario reduces projected peak load and materially lowers required upgrades, cutting total distribution costs to about $2.5 billion. SDG&E emphasizes that while demand flexibility shows clear planning value, its study does not commit to specific programs and cautions against mandates that would constrain utility planning discretion. --- ### **Southern California Edison** [SCE’s Electrification Impacts Study Part 2](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K907/596907811.PDF?ref=calregulatory.com) applies a similar scenario framework but at a much larger system scale, evaluating four cases: - Base case aligned with its current Distribution Planning Process; - Equity-driven DER dispersion case; and - Two demand flexibility cases with increasing levels of participation. SCE estimates total distribution investment of approximately **$13.1 billion** under the base scenario through 2040, with the equity scenario adding only marginal incremental cost. The demand flexibility cases, however, show potential savings ranging from a few hundred million dollars to more than **$1 billion**, depending on how aggressively flexible loads (especially electric-vehicle charging, storage, and HVAC) are managed at the circuit level. SCE highlights that these scenarios are analytical constructs rather than forecasts, but notes that the tools and automated solutioning methods developed in Electrification Impacts Study Part 2 will inform future distribution planning cycles. --- ### Pacific Gas & Electric [PG&E’s report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K907/596907812.PDF?ref=calregulatory.com) presents the most expansive analysis, positioning electrification as both a capital-intensive undertaking and a potential source of long-term customer benefit. PG&E estimates that meeting electrification demand will require between **$23 billion** and **$31 billion** in distribution investment through 2040 across its scenarios. Unlike Electrification Impacts Study Part 1, PG&E says that all Part 2 scenarios are “mitigated,” incorporating engineering best practices, load transfers, and existing forms of load management. PG&E finds that these mitigations already reduce primary system costs by several billion dollars relative to earlier studies, and that enhanced, orchestrated demand flexibility could further lower infrastructure needs by about **$1.8 billion**. Uniquely, PG&E also concludes that electrification growth could place downward pressure on distribution rates (potentially as much as 25% by 2040) as increased load spreads fixed costs over more kilowatt-hours. PG&E holds that equity-driven adoption raises total investment needs but remains consistent with higher load and utilization assumptions, rather than representing inefficiency in planning. ### **INSTANT ANALYSIS** The three IOUs’ final Electrification Impacts Study Part 2 filings feature a shared conclusion: electrification drives substantial distribution investment through 2040, but outcomes are governed less by aggregate load growth and more by load shape. - Across SDG&E, SCE, and PG&E, equity-focused adoption patterns increase costs only incrementally, while demand flexibility produces the largest divergence by deferring circuits, transformers, and substation upgrades. Timing and location of load remain the dominant variables. - At the same time, the utilities establish limits on how demand flexibility is treated in planning. Flexibility is modeled as a sensitivity, not as a guaranteed substitute for infrastructure. None of the studies commit to specific programs, participation rates, or performance obligations, and all emphasize that distribution planning must continue to assume physical upgrades unless flexible load proves persistent, locationally reliable, and measurable at the circuit level. The filings also normalize very large capital requirements over multi-decade horizons. SCE and PG&E present distribution investment in the tens of billions of dollars as operationally manageable, with PG&E arguing that higher utilization from electrification can offset costs over time through improved rate base economics. The debate no longer seems to be whether electrification will reshape the grid, but how much discretion planners retain over the pace and scale of upgrades as policy, customer behavior, and load management practices evolve. ### WEDNESDAY AGGREGATE: Resolution SPD-37 Disputes; Zonal Electrification Lessons; Responses to PG&E/Stanpac Filing URL: https://www.calregulatory.com/wednesday-aggregate-9/ Last updated: 2026-01-28T21:28:30.000Z Today's roundup includes the following items. - A summary of parties' responses to a recent joint application for rehearing challenging [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com), which revised the CPUC’s [Senate Bill 884 undergrounding framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). - PG&E's "Lessons Learned" report summarizing its experience with the proposed zonal electrification project at California State University Monterey Bay, which was ultimately withdrawn after extensive litigation and delay. - An amended scoping memo in PG&E’s 2027 General Rate Case that incorporates implementation questions arising from [Senate Bill 254](https://www.cawildfirefund.com/sb-254-natural-catastrophe-resilience-study?ref=calregulatory.com), which changed how wildfire mitigation memorandum accounts may be used and reviewed. - A summary of parties' responses to PG&E and Standard Pacific Gas Line Incorporated's recent joint [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com), which seeks approval for a multi-part transaction that would transfer substantially all of Stanpac’s remaining gas transmission pipeline assets to PG&E. - Responses of PG&E and SCE to [parallel](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085005.PDF?ref=calregulatory.com) [applications](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K402/594402144.PDF?ref=calregulatory.com) for rehearing submitted by CalCCA that challenge the CPUC’s December approval of 2026 ERRA Forecast decisions for PG&E and SCE ([D.25-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K312/592312564.PDF?ref=calregulatory.com) and [D.25-12-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K808/591808611.PDF?ref=calregulatory.com), respectively). A common theme is that intervenors are forcing the Commission to define the evidentiary and procedural standards required before utilities book significant costs, whether for wildfire, undergrounding, decarbonization, or legacy asset restructuring. More detail is provided below. --- ### UNDERGROUNDING/RESOLUTION SPD-37 As reported by CRI [here](https://www.calregulatory.com/january-14-2026-cpuc-briefing-socalgas-ami-cost-tracking-sce-low-income-program-budgets-a-challenge-to-the-cpucs-undergrounding-resolution-spd-37/?ref=california-regulatory-intelligence-newsletter), Cal Advocates, TURN, and the Mussey Grade Road Alliance recently filed a joint [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K402/594402099.PDF?ref=calregulatory.com) challenging [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com), which revised the CPUC’s [Senate Bill 884 undergrounding framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). These parties argue that the Commission committed legal error by creating an expedited “Phase 1 Application” process without defining party status, shortening response timelines to 15 days, and eliminating meaningful discovery and hearings. They contend these procedural defects violate the CPUC’s own rules and deny due process in decisions that will shape future undergrounding cost recovery. On January 26, the Commission received two responses to the application for rehearing. In a [joint response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K296/596296875.PDF?ref=calregulatory.com), PG&E, SCE, and SDG&E urge the Commission to deny rehearing, arguing that the challenged aspects of SPD-37 fall squarely within the CPUC’s procedural discretion. They contend that the Resolution’s requirement for a joint Phase 1 application (addressing benefit-cost ratio methodology, audit design, and other cost-recovery conditions on an expedited schedule) does not constitute legal error or a denial of due process. The utilities emphasize that: - SB 884 expressly contemplates expedited action to address wildfire and reliability risk; and - Stakeholders have already participated extensively over several years in workshops and guideline development at both the CPUC and Energy Safety. By contrast, the Energy Producers and Users Coalition (EPUC) [supports the rehearing application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K752/596752075.PDF?ref=calregulatory.com) and argues that SPD-37's process risks producing an incomplete evidentiary record on decisions that will govern billions of dollars in future undergrounding costs. - EPUC frames the Phase 1 determinations as foundational decisions, and contends that resolving them through a compressed 15-day response period, without clearly defined party status, discovery rights, or hearings, compromises the Commission's ability to ensure future costs are just and reasonable. - According to EPUC, these procedural constraints conflict with the Commission’s own rules and constitutional due-process principles, increasing the risk that future cost recovery will be approved without adequate scrutiny or protection for ratepayers. Consequently, EPUC urges the Commission to grant rehearing and modify SPD-37 to require a more conventional application process, including longer response timelines, formal discovery, and a hearing framework. **INSTANT ANALYSIS:** The rehearing dispute over SPD-37 is premised on a procedural disagreement rather than the merits of undergrounding itself. The utilities argue the CPUC acted within its discretion by forcing unresolved SB 884 methodology issues into a fast, front-loaded Phase 1 application, pointing to years of prior stakeholder process and the public-safety mandate to move quickly. EPUC and other intervenors counter that the Phase 1 determinations will govern billions in downstream cost recovery and therefore require a fuller record, longer response windows, and clearer participation rights before the Commission locks in benefit-cost and audit frameworks. What matters for observers is that the Commission is being asked to decide how much procedural rigor is required *before* utilities begin booking large undergrounding costs into balancing accounts. Denial of rehearing would reinforce the CPUC’s latitude to compress process when wildfire risk is invoked and push contested design questions into later, plan-specific reviews. Granting rehearing would slow near-term implementation but raise the bar on upfront guardrails, tightening scrutiny over how SB 884 compliance is measured and audited. Either outcome shapes not just undergrounding, but how aggressively the Commission can streamline future safety-driven infrastructure programs. --- ### PG&E – MONTEREY ZONAL ELECTRIFICATION PG&E filed a “[Lessons Learned](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K752/596752064.PDF?ref=calregulatory.com)” report in [R.19-01-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M264/K629/264629773.PDF?ref=calregulatory.com) (Building Decarbonization) and [R.24-09-012](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K040/542040675.PDF?ref=calregulatory.com) (Long-Term Gas Planning) summarizing its experience with the proposed zonal electrification project at California State University Monterey Bay, which was ultimately withdrawn after extensive litigation and delay. PG&E concludes that the project revealed three core challenges: - Planning and execution for large-scale behind-the-meter electrification took far longer than anticipated due to tenant resistance, individualized construction logistics, and misalignment with the safety-driven schedule for required gas pipeline replacement; - The expedited procedural schedule PG&E initially sought proved unrealistic given prolonged negotiations over scope, cost sharing, cost recovery, and cost-effectiveness, resulting in years of litigation that conflicted with pipeline safety obligations; and - PG&E was overly optimistic about reaching settlement on contested issues and should instead assume litigation when designing future schedule-dependent decarbonization projects. The Indicated Shippers’ incorporated comments emphasize deeper lessons, arguing that: - PG&E’s economic analyses were flawed and non-transparent; - Relied on cash-flow metrics rather than full lifecycle revenue requirements; - Failed to account for lost gas revenues, overhead costs, and long-term ratepayer impacts; and - After correcting for these flaws, the electrification alternative yielded a benefit-cost ratio below 1.0, meaning it was not cost-effective for remaining gas customers. The Indicated Shippers further objected to regulatory asset treatment for behind-the-meter appliances and to allocating electrification costs to gas ratepayers who did not benefit from the project, urging future proposals to rely first on non-ratepayer funding and strict cost caps. The Shippers also highlighted a procedural lesson: confidential data responses supporting PG&E's economic analyses were excluded from the evidentiary record due to inadequate confidentiality declarations, leaving the record without detailed cost data directly relevant to evaluating PG&E's claims. - TURN largely agreed with the need for more realistic timelines but criticized PG&E’s draft for underemphasizing policy, cost, and ratepayer impacts. TURN recommended that future lessons-learned reports more clearly document disputed assumptions, cost inputs, and methodological choices, and that the Commission adopt uniform cost-recovery policies to avoid re-litigating the same issues project by project. - TURN also stressed that safety-driven pipeline risk information should be disclosed early in future proceedings to avoid late-stage project collapse and unnecessary delay. For future Senate Bill 1221 projects specifically, TURN suggested that local entities beyond the utility should be involved in conversations with property owners and tenants to promote acceptance by all affected parties. **INSTANT ANALYSIS**: PG&E’s “Lessons Learned” filing reads as a retreat from project-by-project electrification as a substitute for safety-driven gas infrastructure work. The record shows that zonal electrification, when layered onto an active pipeline replacement schedule, creates timing conflicts, prolonged litigation risk, and unresolved cost allocation disputes that can overwhelm any near-term policy upside. Intervenor contributions expose a deeper problem: electrification alternatives were evaluated using incomplete economic frameworks that understated long-term gas ratepayer exposure, omitted lost fixed-cost recovery, and relied on optimistic assumptions about behind-the-meter assets the utility would not own. In sum, the main takeaway is that, without upfront resolution of cost recovery rules, ownership treatment, and full lifecycle revenue impacts, electrification proposals will continue to stall or collapse when tested against safety obligations and affordability constraints. For the CPUC, this filing strengthens the case for setting uniform cost-recovery and evaluation standards before advancing additional non-pipeline alternatives, rather than litigating those questions one project at a time. --- ### PG&E – GENERAL RATE CASE **Commissioner John Reynolds** issued [an amended scoping ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K143/596143006.PDF?ref=calregulatory.com) in PG&E’s 2027 General Rate Case to incorporate implementation questions arising from [Senate Bill 254](https://www.cawildfirefund.com/sb-254-natural-catastrophe-resilience-study?ref=calregulatory.com), which changed how wildfire mitigation memorandum accounts may be used and reviewed. (SB 254 took effect September 19, 2025 as an urgency statute.) SB 254 shifts prior statutory requirements by giving the CPUC discretion (rather than a mandate) to allow memorandum accounts, and limits eligible costs to those that are both unforeseen and incremental to amounts already authorized in a utility’s revenue requirement. In response, the ruling expands the scope of the proceeding to consider whether: - PG&E may continue recording wildfire mitigation costs to its existing Wildfire Mitigation Plan Memorandum Account (WMPMA) and Fire Risk Mitigation Memorandum Account (FRMMA); - Additional guidance is needed on what qualifies as “unforeseen” and “incremental"; and - New or revised administrative processes should govern future cost tracking and recovery. PG&E and other parties are directed to address select questions on these issues by **February 6** while all other elements of the July 31, 2025 scoping memo remain unchanged. **INSTANT ANALYSIS:** This ruling formally pulls SB 254 implementation into PG&E’s 2027 GRC and puts wildfire memorandum accounts on notice. By reframing WMPMA and FRMMA eligibility around costs that are both unforeseen and incremental, the Commission is testing whether legacy wildfire tracking mechanisms remain appropriate inside a forward-looking revenue requirement. The key issue is discretion: memorandum accounts are no longer assumed, and continued use may require explicit approval and stricter process guardrails. Practically, this affects wildfire cost recovery pathways. If the Commission directs PG&E to close or freeze existing memorandum accounts, utilities may be pushed to front-load wildfire mitigation costs into base rates or seek pre-authorization through advice letters or applications. The outcome will shape how wildfire risk is priced, monitored, and litigated in future GRCs and suggests a broader shift away from open-ended, after-the-fact wildfire cost booking toward more disciplined up-front ratemaking. --- ### PG&E – NATURAL GAS TRANSMISSION As summarized [here](https://www.calregulatory.com/monday-aggregate-capital-recovery-attrition-design-decarbonization-cost-allocation-gas-system-continuity-w-o-new-assets/?ref=california-regulatory-intelligence-newsletter) at CRI last month, PG&E and Standard Pacific Gas Line Incorporated (Stanpac) recently filed a joint [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com) seeking approval for a multi-part transaction that would: - Transfer substantially all of Stanpac’s remaining gas transmission pipeline assets to PG&E; - Restructure how Chevron receives gas transportation service; and - Ultimately wind down the nearly century-old Stanpac joint venture. Chevron, which owns a 1/7 non-controlling interest in Stanpac, [supports the transaction](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K320/595320936.PDF?ref=calregulatory.com), arguing it is a practical solution to avoid more than **$100 million** in system upgrades otherwise required to meet Chevron’s historic 30.7 MMcf/d entitlement, and asserting that the transaction would yield net savings to PG&E ratepayers while maintaining Chevron’s gas delivery through a 20-year transportation agreement largely implemented via PG&E facilities On the other hand, Cal Advocates [protested the application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083754.PDF?ref=calregulatory.com), raising concerns about: - The valuation of StanPac and Chevron’s interest; - The fairness of PG&E paying the full asset value despite already owning 6/7 of the utility; - The proposed ratemaking treatment and affiliate-transaction compliance; and - The reasonableness of allowing StanPac to persist for 20 years after its assets and operations are effectively absorbed by PG&E, with Chevron’s remaining stock transferred only at the end of that term for a nominal price. **INSTANT ANALYSIS:** This filing presents a clear policy divide. Chevron characterizes the transaction as a cost-avoidance measure that replaces an open-ended legacy structure with a defined, contract-based arrangement anchored in PG&E’s newer infrastructure, with claimed net savings to ratepayers. Cal Advocates does not dispute the operational rationale, but is positioning the case around valuation, ratemaking, and governance, questioning: - Why PG&E should pay full asset value for an entity it already largely owns; - Why StanPac should persist for two decades after its assets and operations are absorbed by PG&E; and - Whether the affiliate mechanics comply with all pertinent rules. This proceeding is shaping up as a fairness and precedent case, not a reliability case. --- ### PG&E and SCE – ENERGY RESOURCE RECOVERY ACCOUNT FORECAST DECISIONS As reported at CRI [here](https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/), CalCCA recently filed [parallel](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085005.PDF?ref=calregulatory.com) [applications](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K402/594402144.PDF?ref=calregulatory.com) for rehearing that challenge the CPUC’s December approval of 2026 ERRA Forecast decisions for PG&E and SCE ([D.25-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K312/592312564.PDF?ref=calregulatory.com) and [D.25-12-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K808/591808611.PDF?ref=calregulatory.com), respectively). [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K907/596907800.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K902/596902542.PDF?ref=calregulatory.com) have since responded to the applications. SCE's response is pointed, calling CalCCA's challenge "frivolous" and suggesting the Commission should "consider the troubling lack of restraint" in CalCCA's argumentation. In response, both utilities stress that a June 2025 decision ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)) revised the Resource Adequacy Market Price Benchmark and directed its immediate use for the 2025 true-up and 2026 forecasts. That decision is final and operative absent a judicial stay, the utilities hold, and the Commission was required to implement it in the ERRA forecast decisions. - The utilities also reject claims of retroactive ratemaking, explaining that ERRA and [Power Charge Indifference Adjustment ](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com)rates are pass-through, balancing-account mechanisms. They do not set general rates or utility profit and therefore do not implicate the retroactive ratemaking doctrine. - Additionally, PG&E and SCE argue that CalCCA’s challenges amount to an impermissible collateral attack barred by [Public Utilities Code §1709](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-9/article-1/section-1709/?ref=calregulatory.com). Disagreement with D.25-06-049, they contend, must be resolved on appeal, not re-argued in annual ERRA proceedings. On the matter of pre-2019 banked Renewable Energy Credits, both utilities defend the Commission's adoption of a zero valuation for 2026 rates. They argue those attributes were fully paid for in prior years' rates and that customer indifference does not require new compensation to departing load. PG&E cites a [2018 joint working group report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M309/K592/309592367.PDF?ref=calregulatory.com) co-led by CalCCA itself, in which CalCCA agreed that a [D.19-10-001](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M318/K167/318167258.PDF?ref=calregulatory.com) REC methodology would apply only to RECs "generated commencing January 1, 2019 and going forward" because earlier RECs had already been bought and paid for. Both responses note that broader REC policy questions are being examined in a separate rulemaking. On this basis, they urge denial of rehearing and rejection of CalCCA’s request for oral argument. **INSTANT ANALYSIS:** This rehearing dispute focuses on whether the Commission made new policy in the 2026 ERRA decisions. PG&E and SCE argue it did not, and that the decisions simply applied rules set in the 2025 PCIA proceeding. On RA pricing, the utilities say D.25-06-049 required the revised benchmark to be used for the 2025 true-up and 2026 forecast. They argue the Commission was bound to apply that directive because no court has stayed it. CalCCA's position is that this treatment is unlawful retroactive ratemaking. The IOUs counter that the issue was already litigated and is not properly revisited through ERRA rehearing. On pre-2019 RECs, the Commission accepted a zero valuation for 2026 rates. The utilities argue those credits were fully recovered in prior rates and do not create new departing-load value. The 2018 working group citation is particularly damaging to CalCCA's position, as it suggests the organization previously endorsed the very interpretation it now challenges. ### February 5, 2026 CPUC Voting Meeting Preview: Flexible Service Connections; PG&E Wildfire Recovery Costs; SoCalGas Distribution Integrity URL: https://www.calregulatory.com/february-5-2026-cpuc-voting-meeting-preview-flexible-service-connections-pg-e-wildfire-recovery-costs-socalgas-distribution-integrity/ Last updated: 2026-01-28T21:32:53.000Z The CPUC will convene on **February 5** for its [second voting meeting of the year](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K789/596789520.pdf?ref=calregulatory.com). Items currently scheduled for consideration include: - A proposed decision in the Commission's Timely Energization rulemaking that directs PG&E and SCE to establish a standardized, tariffed Standard Offer "Flexible Service Connection" to accelerate customer energization when distribution-level capacity constraints would otherwise delay service. - A PD authorizing PG&E to recover a **$1.416 billion** revenue requirement, which includes costs incurred primarily in 2022 related to wildfire mitigation, vegetation management, catastrophic events, and a set of customer-protection and policy-driven memorandum accounts. - A PD granting SoCalGas partial interim rate recovery for costs recorded in its Distribution Integrity Management Program Balancing Account between 2019 and 2023\. The PD authorizes SoCalGas to recover **$35.5 million** on an interim basis, representing **60%** of the $59.1 million requested, for a 12-month period, subject to refund with interest pending a final reasonableness determination. - A draft resolution approving SCE's request to enter into 10 clean energy resource contracts resulting from its 2024 Clean Energy Request for Offers. This portfolio totals **2,093 MW** of nameplate capacity across four projects, including large single-axis solar PV facilities and paired, co-located four-hour lithium-ion battery storage systems in California and Nevada. - A PD which has been bounced repeatedly from consideration at recent CPUC voting meetings, denying a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. - A draft resolution approving emergency interim rate relief for Crimson Pipeline's SPB-KLM system. The draft resolution approves an interim rate increase effective August 1, 2025, with authority to allow retroactive collection subject to refund. - A draft resolution approving Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations and concluding an uncontested Tier 3 advice letter process. Additional details are available below. --- ### ENERGIZATION A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699367.PDF?ref=calregulatory.com) in the CPUC's Timely Energization docket ([R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com)) that directs PG&E and SCE to establish a standardized, tariffed Standard Offer "Flexible Service Connection" to accelerate customer energization when distribution-level capacity constraints would otherwise delay service. The PD formalizes a bridging mechanism (modeled largely on PG&E’s existing "Load Limiting Letter" practice) that allows customers to receive firm, near-term electrical service by adhering to a utility-defined Limited Load Profile until upstream upgrades are completed. If the PD is ultimately adopted by the Commission, PG&E and SCE would be required to file a joint advice letter within 30 days. The filing would: - Implement the standard offer; - Update tariff rules; - Add customer disclosure and opt-in mechanisms to service application materials; and - Begin collecting detailed cost, performance, and curtailment data to support future refinement. Additional implementation requirements include: - A separate Tier 2 advice letter within **30-45** days formalizing preliminary capacity assessment processes; - SCE must file a Load Control Management Study pilot learnings report by **March 1, 2026**; and - Both utilities must submit a comprehensive cost-efficiency and revenue requirement impact report by **January 15, 2029**. The PD applies only to PG&E and SCE and declines to impose requirements on SDG&E or small multi-jurisdictional utilities at this time. The PD emphasizes speed, safety, and scalability by relying on static load limits, existing engineering practices, and Advanced Metering Infrastructure-based compliance rather than real-time communications or [DERMS](https://www.nrel.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com) integration. The Standard Offer establishes minimum profile granularity (three seasons, two daily capacity values per season) and creates a "safe harbor" for loads controlled by UL 3141-certified Power Control Systems, exempting such controlled loads from connected load calculations. The PD keeps the proceeding open to address additional Phase II energization issues, including dynamic Flexible Service Connections and broader process reforms. **INSTANT ANALYSIS:** This PD formalizes a standardized/tariffed pathway for PG&E and SCE to serve customers facing distribution constraints by allowing interim service under predefined load limits. In essence, the Commission is turning an informal engineering workaround into a repeatable energization tool, and prioritizing speed and certainty over waiting for upstream upgrades. For large or fast-moving loads, this creates a clearer, earlier option to take service but it does not add physical capacity or resolve underlying distribution shortfalls. --- ### WILDFIRE MITIGATION A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K179/592179722.PDF?ref=calregulatory.com) in [A.23-12-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M521/K134/521134366.PDF?ref=calregulatory.com) authorizes PG&E to recover a **$1.416 billion** revenue requirement. This amount includes costs incurred primarily in 2022 related to wildfire mitigation, vegetation management, catastrophic events, and a set of customer-protection and policy-driven memorandum accounts. - The PD approves a broad, largely uncontested settlement resolving all cost categories except vegetation management, and directs PG&E to true-up recovery via the advice-letter process, with offsets for amounts already collected under interim rate relief granted in a 2024 decision ([D.24-09-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K476/540476678.PDF?ref=calregulatory.com)). (Because approximately $943.9 million was already collected through interim rates, only **$2.2 million** in new collections will begin in **March 2026**.) - Most notably, the PD denies recovery of **$363.4 million** in vegetation management costs, finding that PG&E failed to meet the prudent manager standard for that portion of its 2022 spending recorded in the Vegetation Management Balancing Account. - The largest disallowance (**$353.4 million** for Enhanced Vegetation Management) rests on the PD's finding that PG&E knew by February 2022 that the program delivered minimal risk reduction (2.5 risk-spend efficiency versus 3,501.4 for routine vegetation management) yet spent **$715 million** more from March through December without reconsidering the program or its costs. - By contrast, the PD approves recovery (via [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K340/592340331.PDF?ref=calregulatory.com)) of: - Wildfire mitigation costs in the Wildfire Mitigation Balancing Account; - Catastrophic event costs associated largely with the 2022 heat events and 2022–2023 winter storms; and - Costs recorded in multiple memorandum accounts covering COVID-era customer protections, disconnections, privacy compliance, climate vulnerability assessments, microgrids, and low-income affordability pilots. The settlement reflects significant reductions from PG&E’s original request, incorporates Cal Advocates’ concerns about customer affordability, and preserves interim collections already underway. The PD also rejects PG&E's claim that threshold-triggered balancing accounts are exempt from incrementality analysis, clarifying that utilities must prove costs exceeding GRC authorizations were not already funded elsewhere. For future applications, the Commission orders PG&E to provide enhanced comparative data linking GRC-authorized unit costs to actual recorded costs, with specific breakdowns by activity type. **INSTANT ANALYSIS:** The main takeaway for market participants is twofold: - Catastrophic-event and policy-driven memorandum accounts continue to receive favorable treatment when linked to declared emergencies and explicit CPUC mandates; but - Vegetation management remains a high-risk category for recovery, even where spending aligns with approved Wildfire Mitigation Plans, with no presumption that plan compliance alone establishes reasonableness. The PD explicitly applies the prudent manager standard based on what PG&E knew or should have known at the time (not in hindsight) finding that contemporaneous evidence of program ineffectiveness triggered an obligation to reevaluate spending that PG&E failed to satisfy. In short, the Commission appears more willing to approve costs incurred after system stress or failure than costs incurred to prevent it, where preventive spending is subjected to intensive, retrospective review. For utilities, the message is straightforward: future wildfire-related recovery will be evaluated based on execution quality, documentation, and cost discipline, not program scale or urgency. --- ### SOCALGAS DISTRIBUTION INTEGRITY MANAGEMENT A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230826.PDF?ref=calregulatory.com) in [A.25-08-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com) grants SoCalGas partial interim rate recovery for costs recorded in its Distribution Integrity Management Program Balancing Account between 2019 and 2023. The PD authorizes SoCalGas to recover **$35.5 million** on an interim basis, representing **60%** of the $59.1 million requested, for a 12-month period, subject to refund with interest pending a final reasonableness determination. The PD finds that interim recovery is warranted because it: - Produces direct interest savings for ratepayers (approximately $918,000); - Promotes intergenerational equity by aligning cost recovery more closely with when costs were incurred; and - Helps preserve SoCalGas’ financial integrity following a recent credit-rating downgrade, which can indirectly reduce future capital costs. At the same time, the PD rejects SoCalGas’ request for 85% interim recovery, concluding that a lower percentage better balances ratepayer affordability concerns (particularly in light of recent gas rate increases) while still achieving the public-interest benefits of interim relief. Recovery would be implemented through a Tier 1 advice letter using the **Equal Percent of Authorized Margin** cost-allocation methodology. For illustrative rates related to SoCalGas's work, see our summary [here](https://www.calregulatory.com/monday-aggregate-interim-rate-relief-physical-risk-and-the-costs-of-system-continuity/). [Interim Rate Relief; Physical RiskInterim ratemaking, operational outages, and long-dated infrastructure commitments are reshaping cost exposure across California![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-10.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Sat-Jan-03-2026--3-.png)](https://www.calregulatory.com/monday-aggregate-interim-rate-relief-physical-risk-and-the-costs-of-system-continuity/) **INSTANT ANALYSIS:** This PD reflects a Commission approach that permits limited interim recovery when doing so lowers financing costs and supports utility credit metrics, while declining to grant the full amount requested. By authorizing 60% of SoCalGas’ request, the PD emphasizes rate moderation and affordability in light of recent General Rate Case increases, particularly for disadvantaged customers, even as it accepts that deferring recovery would raise interest costs ultimately borne by ratepayers. The PD also clarifies that the Sempra Utilities' 2024 GRC decision ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)) does not foreclose interim recovery for earlier DIMP costs, maintaining a path for utilities to seek near-term relief outside a GRC when costs were not ripe at filing. For large gas customers, the practical takeaway is procedural: interim recovery remains available but will be sized conservatively, tied to refund protections, and constrained by explicit affordability considerations. --- ### CLEAN ENERGY/SOUTHERN CALIFORNIA EDISON [Draft Resolution E-5445](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K463/595463071.PDF?ref=calregulatory.com) approves SCE's request to enter into ten clean energy resource contracts resulting from its 2024 Clean Energy Request for Offers. The draft resolution authorizes a portfolio totaling 2,093 MW of nameplate capacity across four projects, including large single-axis solar PV facilities and paired, co-located four-hour lithium-ion battery storage systems in California and Nevada. The contracts are intended to help SCE meet its Integrated Resource Planning obligations under a 2024 decision ([D.24-02-047](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M525/K918/525918033.PDF?ref=calregulatory.com)) and its Renewables Portfolio Standard requirements, with solar deliveries beginning between 2027 and 2029 and contract terms ranging from 15 to 20 years. Energy Division found that SCE’s solicitation and least-cost, best-fit evaluation process was fair and reasonable, relied on independent evaluator oversight, and produced contracts that are consistent with SCE’s 2024 RPS Procurement Plan and long-term greenhouse gas reduction targets. The draft resolution authorizes full cost recovery of contract and administrative costs through SCE’s Portfolio Allocation Balancing Account. It allows limited flexibility to count the resources toward mid-term reliability requirements if needed, but rejects SCE’s request to pre-authorize cost recovery related to separate interconnection process enhancement solicitations. **INSTANT ANALYSIS**: This draft resolution continues the Commission’s steady pattern of approving large, utility-led solar and paired storage portfolios to backfill long-term IRP needs identified in D.24-02-047, with little controversy and no protests. The scale is significant: over 2,000 MW of nameplate capacity approved in a single advice letter, reinforcing SCE’s reliance on utility-scale solar plus four-hour storage as the default compliance pathway for both IRP and RPS obligations. For ratepayers, the near-term cost exposure is opaque because contract prices remain confidential, but the Commission’s approval of full PABA cost recovery and vintage allocation confirms these resources will flow through bundled and departing-load customer charges beginning in the late-2020s. The draft resolution also draws a clear boundary around cost recovery authority, approving recovery for the clean energy contracts themselves while rejecting SCE’s attempt to roll unrelated interconnection-process costs into the same resolution. This conveys that procurement approvals will not automatically open the door to adjacent administrative cost mechanisms. --- ### UNION ISLAND PIPELINE A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com), which has been bounced repeatedly from consideration at recent CPUC voting meetings, denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD concludes that the company no longer holds valid franchise rights in Antioch and Brentwood and ceased transporting gas in 2023. - The PD concludes further that ongoing litigation over alleged pipeline abandonment means CRPC cannot demonstrate clear ownership or operational control of the full line, preventing it from dedicating the system to public use. - The PD rejects CRPC’s attempt to substitute a subsidiary and denies the cities’ request for a procedural pause, though it grants CRPC’s motion to keep financial records sealed for three years. **INSTANT ANALYSIS:** This PD resolves the application on threshold jurisdictional grounds and avoids reaching broader policy questions about the role of statewide regulation where local franchise authority has lapsed or been denied. By grounding the denial in present-tense statutory requirements under the Public Utilities Code, the PD treats the absence of current operating rights as dispositive and declines to evaluate system value or public-interest considerations. The PD also clarifies that CPCN authority does not operate as a mechanism to cure unresolved local franchise disputes. In practice, this approach places primary weight on settled legal control of facilities before public-utility status can attach, reinforcing a sequence in which municipal authorization precedes Commission oversight. The result is a narrower, process-oriented interpretation of the Commission’s role that limits its involvement in infrastructure assets facing active local and judicial uncertainty. --- ### CRUDE OIL TRANSPORTATION [Draft Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M593/K611/593611368.PDF?ref=calregulatory.com) approves emergency interim rate relief for Crimson Pipeline's SPB-KLM system. The resolution approves an interim rate increase effective August 1, 2025, with authority to allow retroactive collection subject to refund. The draft resolution: - Finds that sustained volume declines (from approximately 100 kbpd in 2021 to under 30 kbpd by late 2025, including zero nominations for December 2025) justify interim action to prevent suspension of pipeline operations. Crimson stated it "lacks sufficient cash on hand, does not have access to debt financing, and cannot secure additional capital from its owner to sustain operations." - Rejects an argument advanced by Chevron and Valero that the Public Utilities Code limits CPUC authority to approve increases above 10%. The draft resolution clarifies that the statutory cap constrains only what utilities may implement unilaterally, not what the CPUC may authorize. As a condition of approval, Crimson must secure a letter of credit to protect shipper refunds. Final rate determinations remain with the pending General Rate Case ([A.25-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M555/K961/555961198.PDF?ref=calregulatory.com)). **INSTANT ANALYSIS:** Draft Resolution O-0098 reflects the Commission's willingness to use interim ratemaking to preserve critical infrastructure when volume collapse threatens operational continuity. The SPB-KLM system is the primary pipeline connecting crude oil from the Central Valley to Northern California refineries, giving the system strategic importance beyond its current throughput, and one of only a limited number of pipelines capable of moving Central Valley crude out of basin. The draft resolution prioritizes near-term system availability over rate stability, while deferring cost scrutiny and final rate reasonableness to the pending GRC (treating emergency relief as a temporary bridge rather than a final judgment). --- Separately, [Draft Resolution O-0099](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K079/595079380.PDF?ref=calregulatory.com) approves Phillips 66 Pipeline LLC's request to withdraw utility service on crude oil pipeline Lines 100, 200, 300, and 400 and to cancel its tariff, marking Phillips 66's complete exit from California crude pipeline utility operations and concluding an uncontested Tier 3 advice letter process. The draft resolution finds that, following the closure of the Santa Maria Refinery and the conversion of the Rodeo Refinery to a renewable fuels facility, the pipeline system no longer serves a useful purpose, and all former producers have secured alternative transportation. Safety oversight remains exclusively with the Office of the State Fire Marshal, which has granted Phillips 66 a deferment of certain maintenance, inspection, and testing requirements. Phillips 66 must still comply with all applicable state and federal regulations for idled lines. The draft resolution does not authorize or address cost recovery, noting there are no ratepayers using the lines and that any remaining maintenance costs will be borne entirely by Phillips 66. **INSTANT ANALYSIS:** Draft Resolution O-0099 formalizes the end of Phillips 66's crude pipeline utility operations in California – not a partial system withdrawal, but a complete exit from the business. The draft resolution reflects demand loss rather than a safety or cost dispute, tying directly to the Santa Maria refinery closure and the Rodeo conversion to renewable fuels. There is no rate exposure, no cost allocation, and no downstream precedent risk for other pipeline utilities, as the draft resolution explicitly avoids approving any costs and leaves all residual obligations with Phillips 66\. From a market perspective, the draft resolution closes the book on a legacy crude transport corridor and reinforces the direction of travel for refinery-linked infrastructure in California: once refining demand disappears, utility status follows. ### MONDAY AGGREGATE: RA Proposals; Energization Replies; NG Curtailment Watch for SoCalGas/SDG&E Territories URL: https://www.calregulatory.com/monday-aggregate-ra-proposals-energization-replies-ng-curtailment-watch-for-socalgas-sdg-e-territories/ Last updated: 2026-01-28T21:35:08.000Z Today's roundup looks at: - Party proposals in the CPUC's [Resource Adequacy docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K934/583934825.PDF?ref=calregulatory.com) that seek to correct growing misalignments between the CPUC’s Slice-of-Day Resource Adequacy framework, CAISO deliverability rules, and the resource mix needed for a decarbonized grid facing tighter reliability margins. - Reply comments in the Commission's [Energization rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com), where a pending proposed decision, if adopted, would establish a Standard Offer for Flexible Service Connections as part of the Commission’s broader effort to set and enforce energization timelines. - SoCalGas's systemwide natural-gas curtailment watch covering both the SoCalGas and SDG&E service territories. ### RESOURCE ADEQUACY On January 23, parties in Track 1 of R.25-10-003 advanced a coordinated set of proposals aimed at correcting growing misalignments between the CPUC’s Slice-of-Day Resource Adequacy framework, CAISO deliverability rules, and the resource mix needed for a decarbonized, reliability-constrained grid. - Sonoma Clean Power Authority [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K279/596279531.PDF?ref=calregulatory.com) that the Slice-of-Day framework undervalues energy-only and long-lead-time clean firm resources by tying RA accreditation to summer peak deliverability tests that do not reflect hour-by-hour, multi-season reliability needs, and urges the Commission to allow greater RA compliance value for energy-only resources (particularly in non-summer months) to unlock procurement of geothermal and other clean firm generation constrained by interconnection limits. - American Clean Power-California [similarly seeks to integrate energy-only resources into the RA construct](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K142/596142996.PDF?ref=calregulatory.com), proposing that they be allowed to satisfy storage charging sufficiency requirements (without counting toward capacity obligations), paired regionally with storage and subject to must-bid and visibility requirements, while also revising solar and wind accreditation to better reflect actual reliability contributions. - Cal Advocates [focuses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K142/596142987.PDF?ref=calregulatory.com) on long-duration storage, proposing a multi-day energy sufficiency requirement that expands Slice-of-Day accounting beyond a single 24-hour “worst day” so that multi-day storage can be credited for consecutive-day discharge while requiring load-serving entities to demonstrate sufficient forward charging energy. - Vistra and Calpine both address capacity over- and mis-accreditation risks: Vistra [proposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K270/596270155.PDF?ref=calregulatory.com) refined qualifying-capacity calculations for short- and long-duration storage based on commercially available energy and contracted duration, paired with an unforced capacity framework that calculates resource-specific Equivalent Forced Outage Rate on Demand values for up to three operating parameters (maximum operating limit, maximum continuous energy limit, and minimum continuous energy limit) to avoid overstating deliverable RA value, while Calpine [proposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K155/596155117.PDF?ref=calregulatory.com) facility-level unforced capacity treatment for interdependent geothermal units so that integrated resources like The Geysers are accredited based on reliable aggregate output rather than unit-by-unit constraints that understate true reliability. - MN8 Energy [targets](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K227/595227202.PDF?ref=calregulatory.com) variable renewable accreditation, arguing that current monthly solar QC factors are anchored to peak load hours rather than hours of highest reliability risk, and should instead be recalibrated using risk-weighted methods aligned with loss-of-load analysis to avoid distorted deliverability outcomes and investment signals **INSTANT ANALYSIS:** These proposals converge on a single pressure point: the Slice-of-Day RA framework is no longer aligned with how reliability risk actually manifests on a decarbonizing grid. Multiple parties argue that peak-hour, summer-centric accreditation rules are overstating some resources (notably solar and short-duration storage) while suppressing others that provide real reliability value across seasons and days, including energy-only generation, geothermal, and long-duration storage. Collectively, the proposals push the Commission toward three shifts: - Separating energy sufficiency from capacity deliverability so energy-only resources can support storage charging and reliability without conflicting with CAISO tariff rules; - Reforming storage and geothermal accreditation to reflect aggregate, multi-day, and facility-level performance rather than unit-specific or single-day snapshots; and - Recalibrating solar and wind QC to hours of highest reliability risk rather than peak load. If adopted in whole or in part, these changes would significantly reshape RA procurement signals, reduce artificial deliverability bottlenecks, and accelerate contracting for clean firm and long-duration resources that are currently stranded under existing rules. --- ### ENERGIZATION Parties filed reply comments in response to opening comments on a December 24 [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699367.PDF?ref=calregulatory.com) in [R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com), which would establish a Standard Offer for Flexible Service Connections as part of the Commission’s broader effort to set and enforce energization timelines. The PD directs PG&E and SCE to file Tier 2 Implementation Advice Letters establishing the Standard Offer tariff. [Energization PD; SoCalGas AFR of Electrification PilotUtilities get potential energization pathways via tariff but connecting customers face interim load restrictions until upgrades arrive![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-5.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-22-2025--15-.png)](https://www.calregulatory.com/monday-aggregate-energization-pd-socalgas-afr-of-electrification-pilot-wildfire-mitigation-pd/) A portion of reply comments address disputes raised in opening comments regarding the scope, structure, and implementation of the proposed standard offer, including the role of preliminary capacity assessments, eligibility and applicability across utility service territories, cost and ratepayer-benefit considerations, compliance monitoring approaches, reporting and compliance timelines, and the appropriate balance between standardized Commission requirements and utility operational discretion. Parties remain divided over how prescriptive the Commission should be in implementing a Standard Offer for Flexible Service Connections, particularly around preliminary capacity assessments, eligibility scope, cost accountability, and timing. Here's a look at select parties' remarks. - [CALSTART](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481245.PDF?ref=calregulatory.com), the [Environmental Defense Fund](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481244.PDF?ref=calregulatory.com), and [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K142/596142999.PDF?ref=calregulatory.com) generally support the PD's direction, arguing that early, standardized preliminary capacity assessments (Step 0/PCAs) are essential to informed customer investment decisions, that Flexible Service Connections should scale quickly without delay, and that utilities already possess the tools and experience to implement these requirements without undue burden. These parties also press for broader applicability (including extending requirements to SDG&E and, in some cases, single-phase customers) and caution against allowing utilities to defer compliance or narrow eligibility in ways that would slow electrification. EDF specifically defends the PD's "trust-and-verify" compliance model using existing Advanced Metering Infrastructure data, arguing it imposes minimal costs while avoiding expensive telemetry requirements. - [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K270/596270159.PDF?ref=calregulatory.com), [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K155/596155123.PDF?ref=calregulatory.com), and [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K270/596270158.PDF?ref=calregulatory.com) emphasize operational flexibility, cost uncertainty, and safety, warning that tariff-based or overly rigid requirements could add administrative complexity, duplicate existing intake processes, strain resources, or encroach on issues better addressed in other proceedings such as High DER or General Rate Cases. The utilities consistently argue for discretion in defining upstream capacity, limiting Flexible Service Connections to true bridging use cases tied to primary-side constraints, preserving power-based load limits, and avoiding mandates related to telemetry, emergency ratings reform, secondary infrastructure, or behind-the-meter resources. - SDG&E contests the need to prepare Flexible Service Connections offerings, claiming capacity constraints are unlikely in its territory (a position TURN challenges by noting SDG&E requested over **$300 million** for distribution capacity projects in its 2025 [Senate Bill 410](https://calmatters.digitaldemocracy.org/bills/ca%5F202320240sb410?ref=calregulatory.com) application due to "significant forecast uncertainty" and underperformance in five energization target categories). - [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M596/K142/596142999.PDF?ref=calregulatory.com) supports Flexible Service Connections while insisting on explicit ratepayer benefit criteria, stronger reporting, and Commission oversight through Tier 3 advice letters. TURN endorses [Cal Advocates' opening comment recommendation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K320/595320884.PDF?ref=calregulatory.com) requiring utilities to describe in their Implementation Advice Letters the specific criteria and process they will use for ratepayer cost-benefit determinations, applying a "net benefit" standard under which ratepayer value exceeds incremental implementation costs. TURN rejects arguments from CALSTART and EDF that ratepayer benefit standards would create unnecessary barriers, arguing the Commission can resolve feasibility concerns by requiring utilities to propose streamlined benefit-cost assessment criteria in their advice letters. **INSTANT ANALYSIS:** The reply comments expose a clear divide over the future role of Flexible Service Connections in California's energization framework. - Load-serving utilities argue for preserving discretion, limiting Flexible Service Connections to narrowly defined bridging scenarios, and deferring unresolved cost, safety, and technical questions to other proceedings. - In contrast, freight, clean-energy, and consumer advocates contend that early power visibility, standardized offers, and firm implementation timelines are now essential to keep electrification projects viable and prevent avoidable project attrition. - A separate but related dispute involves whether Flexible Service Connections should remain strictly temporary bridging solutions until upstream capacity upgrades are completed, or expand to encompass permanent load management applications such as avoiding upgrades entirely, supporting microgrids, or enabling demand response participation. (SDG&E and SCE argue that this question is out of scope here and belongs in the High DER proceeding, while TURN contends longer-term Flexible Service Connections frameworks warrant development now). A final decision will hinge on whether Flexible Service Connections remain an operational workaround applied case-by-case, or evolve into a more durable and potentially permanent tool for managing constrained grid capacity while accelerating new load additions. --- ### NATURAL GAS CURTAILMENTS **ENVOY NOTICE:** Effective at 7:00 a.m. PST on January 26, and until further notice, SoCalGas has issued a systemwide curtailment watch covering both the SoCalGas and SDG&E service territories. The notice cites extremely cold weather across large portions of the United States outside California, which has driven up national natural gas demand and raised the risk of upstream supply disruptions, including potential well freeze-offs in supply basins serving Southern California. In response, storage facilities are operating at elevated utilization levels, and the combination of higher demand and reduced on-system supplies could lead to increasingly constrained system conditions. Noncore customers may be required to curtail or cease gas usage under SoCalGas Rule 23 ("Continuity of Service and Interruption of Delivery") and SDG&E [Rule 14](https://www.sdge.com/sites/default/files/SDGE%2520Rule%252014%5F0.pdf?ref=calregulatory.com) ("Shortage of Gas Supply, Interruption of Delivery, and Priority of Service"). Customers are urged to balance usage with deliveries and to monitor Envoy for further updates. **INSTANT ANALYSIS:** This curtailment watch serves as an early warning of growing constraints on the Southern California gas system driven by national weather, not in-state demand. The risk is concentrated on noncore customers, who should be prepared for curtailment if upstream disruptions persist or storage draw flexibility narrows further. Large-load customers with exposure to spot gas, imbalance penalties, or limited operational flexibility should review delivery alignment and contingency plans, particularly if cold weather in the Rockies and eastern U.S. continues to pressure production and interstate flows. **UPDATE:* Effective 7:00 AM PST January 28, the systemwide curtailment watch is no longer in effect.* ### FRIDAY AGGREGATE: PG&E Electric Rates; Slice-of-Day Impacts; Vehicle-to-Everything URL: https://www.calregulatory.com/friday-aggregate-pg-e-electric-rates-slice-of-day-impacts-vehicle-to-everything/ Last updated: 2026-01-28T21:35:36.000Z Today's roundup covers: - A PG&E [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7819-E.pdf?ref=calregulatory.com) executing a CPUC-approved unwind of a sizable 2025 ERRA overcollection, as routed through the [2026 Annual Electric True-Up](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7797-E.pdf?ref=calregulatory.com) to avoid mid-year rate volatility. This is an informational-only compliance filing, but it is useful for tracking PG&E's rate architecture. - A PG&E Slice-of-Day [compliance filing](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7820-E.pdf?ref=calregulatory.com) demonstrating how storage-backed Resource Adequacy value is translated into [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) charges in 2026. - The CPUC's December 2025 Resource Tracking Data. The data demonstrates that storage has moved from a supplemental resource to the central pillar of incremental capacity value, while solar’s contribution falls when viewed through a Net Qualifying Capacity lens. - A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495688.PDF?ref=calregulatory.com) setting the framework for the [Electric Program Investment Charge Program](https://www.energy.ca.gov/programs-and-topics/programs/electric-program-investment-charge-epic-program?ref=calregulatory.com)’s next investment cycle. - [Draft Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K288/596288531.PDF?ref=calregulatory.com), which approves PG&E’s requests to extend and restructure Pilot #3 of its [Vehicle-to-Everything](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com) (V2X) Microgrid Pilot at the [Redwood Coast Airport Microgrid](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com). *Note: There is no paywall for this Friday Aggregate, but if you are finding our reports useful, please consider becoming a* [*paid subscriber*](https://www.calregulatory.com/pricing/) *or* [*inquiring*](https://www.calregulatory.com/contact-us/) *about embedded and personalized intelligence for your firm.* --- ### PG&E ELECTRIC RATES PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7819-E.pdf?ref=calregulatory.com) to comply with a [December 2025 CPUC decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K312/592312564.PDF?ref=calregulatory.com) approving its consolidated 2026 ERRA forecast and related trigger application. The decision required PG&E to show how the amortization of its 2025 ERRA trigger balance affected rates effective January 1, 2026\. PG&E explains that after its ERRA balancing account became significantly over-collected in mid-2025 (exceeding the Commission’s trigger thresholds) it proposed, and the CPUC approved, returning that overcollection through the [2026 Annual Electric True-Up](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7797-E.pdf?ref=calregulatory.com) rather than via a separate mid-year adjustment. Consistent with the decision, PG&E transferred the forecasted 2025 ERRA overcollection into the Portfolio Allocation Balancing Account vintage-2025 subaccount. This produced a net reduction in [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates for 2025-vintage customers, partially offset by their share of other PABA balances. | IMPACT OF AMORTIZATION OF THE ERRA TRIGGER BALANCE ON 2025 CUSTOMER VINTAGE PCIA RATES(Dollars per kilowatt-hour) | | | ----------------------------------------------------------------------------------------------------------------- | ---------- | | 2025 Customer Vintage Average PCIA Rate Resulting from Transfer of ERRA Overcollection to PABA | ($0.05944) | | Vintage 2025 Average PCIA Rate Resulting from Bundled Share of PABA Undercollections | $0.04196 | | Net Vintage 2025 PCIA Rate Associated with the ERRA Trigger Balance | ($0.01748) | The advice letter provides updated rate tables showing the resulting PCIA rates by customer class and vintage (see table below). | Line No. | Customer Class | 2009 Vintage | 2010 Vintage | 2011 Vintage | 2012 Vintage | 2013 Vintage | 2014 Vintage | 2015 Vintage | 2016 Vintage | 2017 Vintage | 2018 Vintage | 2019 Vintage | 2020 Vintage | 2021 Vintage | 2022 Vintage | 2023 Vintage | 2024 Vintage | 2025 Vintage | 2026 Vintage | | -------- | ----------------------------------- | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | ------------ | | 1 | Residential | $0.02973 | $0.03366 | $0.03492 | $0.03676 | $0.03708 | $0.03686 | $0.03680 | $0.03687 | $0.03661 | $0.03679 | $0.03725 | $0.03632 | $0.05264 | $0.05272 | $0.05380 | $0.05066 | ($0.01011) | ($0.01011) | | 2 | Small L&P | $0.02910 | $0.03294 | $0.03417 | $0.03597 | $0.03628 | $0.03607 | $0.03602 | $0.03608 | $0.03582 | $0.03600 | $0.03646 | $0.03554 | $0.05151 | $0.05159 | $0.05265 | $0.04957 | ($0.00990) | ($0.00990) | | 3 | Medium L&P | $0.03071 | $0.03476 | $0.03606 | $0.03796 | $0.03829 | $0.03807 | $0.03801 | $0.03807 | $0.03780 | $0.03799 | $0.03847 | $0.03751 | $0.05436 | $0.05444 | $0.05557 | $0.05232 | ($0.01045) | ($0.01045) | | 4 | E19 | $0.02903 | $0.03286 | $0.03410 | $0.03589 | $0.03620 | $0.03599 | $0.03593 | $0.03600 | $0.03574 | $0.03592 | $0.03637 | $0.03546 | $0.05140 | $0.05147 | $0.05253 | $0.04946 | ($0.00987) | ($0.00987) | | 5 | Streetlights | $0.02427 | $0.02747 | $0.02850 | $0.03000 | $0.03026 | $0.03009 | $0.03004 | $0.03009 | $0.02988 | $0.03003 | $0.03041 | $0.02965 | $0.04296 | $0.04302 | $0.04391 | $0.04134 | ($0.00824) | ($0.00824) | | 6 | Standby | $0.02046 | $0.02316 | $0.02402 | $0.02529 | $0.02551 | $0.02536 | $0.02532 | $0.02536 | $0.02518 | $0.02531 | $0.02563 | $0.02499 | $0.03621 | $0.03626 | $0.03701 | $0.03484 | ($0.00694) | ($0.00694) | | 7 | Agriculture | $0.02750 | $0.03113 | $0.03230 | $0.03400 | $0.03430 | $0.03410 | $0.03404 | $0.03410 | $0.03386 | $0.03403 | $0.03446 | $0.03360 | $0.04869 | $0.04876 | $0.04977 | $0.04686 | ($0.00935) | ($0.00935) | | 8 | B20/E20 T (Excluding FPP) | $0.02637 | $0.02985 | $0.03097 | $0.03260 | $0.03288 | $0.03269 | $0.03264 | $0.03270 | $0.03247 | $0.03263 | $0.03304 | $0.03221 | $0.04668 | $0.04675 | $0.04772 | $0.04493 | ($0.00896) | ($0.00896) | | 9 | B20/E20 P (Excluding FPP) | $0.02617 | $0.02962 | $0.03074 | $0.03235 | $0.03263 | $0.03245 | $0.03239 | $0.03245 | $0.03222 | $0.03238 | $0.03279 | $0.03197 | $0.04633 | $0.04640 | $0.04735 | $0.04459 | ($0.00889) | ($0.00889) | | 10 | B20/E20 S (Excluding FPP) | $0.02717 | $0.03075 | $0.03190 | $0.03358 | $0.03387 | $0.03368 | $0.03362 | $0.03368 | $0.03344 | $0.03361 | $0.03403 | $0.03318 | $0.04809 | $0.04816 | $0.04915 | $0.04628 | ($0.00923) | ($0.00923) | | 11 | BEV1 | $0.02417 | $0.02736 | $0.02839 | $0.02988 | $0.03014 | $0.02997 | $0.02992 | $0.02997 | $0.02976 | $0.02991 | $0.03029 | $0.02953 | $0.04280 | $0.04286 | $0.04374 | $0.04119 | ($0.00822) | ($0.00822) | | 12 | BEV2 | $0.02751 | $0.03114 | $0.03231 | $0.03401 | $0.03430 | $0.03411 | $0.03405 | $0.03411 | $0.03387 | $0.03404 | $0.03447 | $0.03361 | $0.04870 | $0.04878 | $0.04978 | $0.04687 | ($0.00936) | ($0.00936) | | 13 | System Average PCIA Rate by Vintage | $0.02749 | $0.03093 | $0.03398 | $0.03507 | $0.03623 | $0.03639 | $0.03625 | $0.03624 | $0.03549 | $0.03632 | $0.03527 | $0.03551 | $0.05110 | $0.05064 | $0.05098 | $0.04767 | ($0.00991) | ($0.00991) | The filing also includes updated average generation and public-policy procurement charges, reflecting the rates implemented January 1, 2026 after inclusion of year-end balancing account data. Since this is an informational advice letter, there is no protest period. **INSTANT ANALYSIS:** This filing is a mechanical compliance exercise, not a new policy move. PG&E is executing a CPUC-approved unwind of a sizable 2025 ERRA overcollection and routing it through the [2026 Annual Electric True-Up](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7797-E.pdf?ref=calregulatory.com) to avoid mid-year rate volatility. The practical effect is a temporary reduction in 2025-vintage PCIA rates, driven by the transfer of the ERRA overcollection into the PABA vintage-2025 subaccount, with that benefit partially offset by other PABA balances. No new cost recovery is authorized, no utility conduct is revisited, and no additional rate discretion is exercised. For most customers, this shows up as a modest PCIA adjustment embedded in January 1, 2026 rates rather than a visible refund, reinforcing the CPUC’s preference for smoothing commodity account corrections through annual true-ups instead of sharper, event-driven rate changes. --- ### **SLICE OF DAY/RESOURCE ADEQUACY** Separately, PG&E submitted [Advice Letter 7820-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7820-E.pdf?ref=calregulatory.com) to comply with a December 2025 decision (D.25-12-027), demonstrating how it implemented the approved interim Slice-of-Day methodology in rates that took effect January 1, 2026\. The filing explains that, following a contested issue in PG&E’s consolidated 2026 ERRA proceeding, the Commission authorized PG&E to apply SCE's interim Slice-of-Day methodology for four-hour battery storage resources only, adjusting Net Qualifying Capacity to reflect that storage cannot deliver its full capacity across a 24-hour day. PG&E states that it: - Applied the adopted formula to all Power Charge Indifference Adjustment-eligible battery storage resources expected to be operational in 2026; and - Incorporated the resulting retained RA values into its PCIA calculations, and reflected those adjustments in January 1, 2026 rates through its Annual Electric True-Up ([*AL 7797-E*](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7797-E.pdf?ref=calregulatory.com)*, summarized by CRI* [*here*](https://www.calregulatory.com/pg-e-electric-rates-for-january-1-2026/)). [PG&E Electric Rates for January 1, 2026PG&E submitted AL 7797-E to implement consolidated electric rate and tariff updates effective January 1, 2026.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3-4.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Fri-Dec-05-2025.png)](https://www.calregulatory.com/pg-e-electric-rates-for-january-1-2026/) AL 7820-E includes confidential workpapers detailing resource-level capacity, round-trip efficiency, and resulting adjustments. Protests are due **February 11**. **INSTANT ANALYSIS:** This advice letter is procedural, but it matters for how storage-backed Resource Adequacy value is translated into PCIA charges in 2026\. By applying SCE’s interim Slice-of-Day discount to battery storage NQC, PG&E reduces the amount of retained RA credited to storage resources, which in turn affects the indifference calculation borne by departing load customers. The Commission already resolved the policy question in D.25-12-027, so the real risk here is not approval but scrutiny over implementation fidelity. Stakeholders focused on PCIA cost allocation, storage valuation, or RA accounting should view this filing as confirmation that the CPUC’s interim treatment of storage is now embedded in 2026 rates (and likely a preview of continued pressure to refine how multi-hour storage is valued relative to conventional capacity going forward). --- ### INTEGRATED RESOURCE PLANNING The CPUC distributed its December 2025 Resource Tracking Data, which provides a consolidated snapshot of how California’s resource mix has evolved since 2020 and what is contractually lined up through the end of the decade. Between January 2020 and December 2025, about **31,000 MW** of new reliability resources came online when imports are included, with about 28,700 MW located within the CAISO. The bulk of these additions are [Senate Bill 100](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb100?ref=calregulatory.com)\-eligible resources, dominated by battery storage, solar, and hybrid projects, while new natural gas capacity came predominantly from legacy projects in early 2020 (1,448 of 1,551 MW), with only 103 MW added across all subsequent years. The data highlight a distinction between nameplate capacity and September Net Qualifying Capacity, particularly for solar, reinforcing that storage now provides a disproportionate share of incremental reliability value. As of year-end 2025, nearly 16,000 MW of storage is already online, and more than 20,000 MW of additional resources (primarily storage and solar) are under contract and expected to come online between 2026 and 2029\. CPUC staff emphasize that these figures are derived from CAISO and CPUC lists, reflect only resources under contract to jurisdictional load-serving entities, and do not map one-to-one with IRP compliance. However, they nonetheless serve as the Commission’s baseline view of recent buildout and near-term procurement commitments. **INSTANT ANALYSIS:** This dataset shows how far California’s reliability strategy has already committed itself. Storage has moved from a supplemental resource to the central pillar of incremental capacity value, while solar’s contribution falls when viewed through an NQC lens. At the same time, the near-absence of post-2020 gas additions means future reliability debates will be fought almost entirely within a storage-heavy, transmission-constrained system. For CRI readers, the takeaway is that many upcoming Resource Adequacy, IRP, and reliability disputes are no longer about whether resources exist on paper, but about whether this mix performs as assumed during stress hours, and how much ratepayers are exposed if those assumptions fall short. --- ### ELECTRIC PROGRAM INVESTMENT CHARGE The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495688.PDF?ref=calregulatory.com) in R.19-10-005 setting the framework for the Electric Program Investment Charge (EPIC) Program’s next investment cycle. The PD adopts 13 measurable Strategic Objectives that will guide "EPIC 5" investments from 2026 through 2030, translating previously adopted high-level goals into concrete, near-term targets. - The PD authorizes PG&E, SCE, and SDG&E to continue serving as EPIC administrators for EPIC 5\. The PD finds that the utilities have made sufficient progress on earlier administrative shortcomings, particularly in portfolio optimization, stakeholder engagement, and benefits quantification. The utilities are authorized to continue collecting rates to fund EPIC, with total annual funding of **$185 million**, largely administered by the California Energy Commission. - The PD also refines EPIC intellectual-property rules. It allows waivers where EPIC-funded work is intentionally open-sourced, clarifies the treatment of pre-existing IP, and denies requests to waive state march-in or direct licensing rights for projects involving federal entities. The PD finds that SCE provided insufficient details to support a general waiver, though it acknowledges the issue exists and that CEC has addressed similar challenges with DOE recipients through entity-specific terms. - In response to data gaps identified in the 2024 program evaluation, the PD orders a more comprehensive evaluation in 2028\. That review is intended to strengthen accountability and inform whether EPIC should continue beyond its current 2030 sunset. Finally, the PD extends the EPIC 5 investment plan application deadline to **June 26, 2026**. The extension reflects the added requirements associated with the new Strategic Objectives and program refinements. Comments are due **February 12**. The earliest the CPUC will consider this item is **February 26**. **INSTANT ANALYSIS**: This PD narrows EPIC’s focus rather than expanding its scope. By adopting 13 measurable Strategic Objectives, the Commission sets outcome-based expectations for EPIC 5, rather than emphasizing activity or spend. - The decision to retain the IOUs as EPIC administrators is consequential. The PD accepts incremental improvement after earlier deficiencies, while shifting leverage to clearer objectives and a required 2028 evaluation. - The intellectual property clarifications favor execution over theory. Open-source waivers reduce friction for software and data projects, while the denial of march-in and direct licensing waivers preserves a strong state backstop, though this may frustrate IOUs' efforts to partner with national laboratories on projects the PD acknowledges as potentially valuable. Taken together, the PD positions EPIC as an implementation vehicle for affordability, electrification, and resilience. The real test will be whether the new objectives are used to shape, narrow, or reject EPIC 5 project proposals. --- ### PG&E/ELECTRIC VEHICLES The CPUC issued [Draft Resolution E-5434](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M596/K288/596288531.PDF?ref=calregulatory.com), which approves (with modifications) PG&E’s requests to extend and restructure Pilot #3 of its [Vehicle-to-Everything](https://www.pge.com/en/clean-energy/electric-vehicles/getting-started-with-electric-vehicles/vehicle-to-everything-v2x-pilot-programs.html?ref=calregulatory.com) (V2X) Microgrid Pilot at the [Redwood Coast Airport Microgrid](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com). The draft resolution grants PG&E additional time to complete Phase I testing and data collection, extending the deadline to **June 30, 2026**, after documented delays tied to Federal Aviation Administration funding, vendor instability, firmware issues, and charger damage during testing. While Energy Division finds that Phase I has demonstrated meaningful technical progress (particularly in validating frequency-based controls for bidirectional EV charging) it also directs PG&E to explain how it intends to meet the original success metric of demonstrating five to 10 bidirectional EVs, given that only two vehicles are currently participating. For Phase II, the draft resolution approves PG&E’s proposal to abandon the original customer-enrollment and incentive structure and instead adopt a Hybrid Support Model, under which PG&E will close enrollment, return approximately **$750,000** in unspent incentive funds to ratepayers, and provide V2X technical consulting to Microgrid Incentive Program projects using non-pilot resources. Energy Division concludes that this approach reasonably adapts the pilot to current market and technology constraints while preserving lessons learned and protecting ratepayers from further costs. The earliest the Commission will consider this item is **February 26**. **INSTANT ANALYSIS**: This draft resolution marks a retreat from scale rather than a failure of the underlying technology. It allows PG&E to complete Phase I because the operational data remains valuable, but it refuses to extend a customer-facing incentive program that lacked viable sites, equipment, and timelines. By approving a pivot to a hybrid support model and requiring unused funds to be returned to ratepayers, the draft resolution reinforces a clear principle: experimental pilots must either produce usable evidence or wind down cleanly. For stakeholders, the message is that V2X and community microgrids remain conceptually supported, but the CPUC is no longer willing to finance prolonged demonstrations ahead of real-world readiness. ### Proposed Decision Lands in CPUC's Natural Gas Price Spike Investigation URL: https://www.calregulatory.com/proposed-decision-lands-in-cpucs-natural-gas-price-spike-investigation/ Last updated: 2026-01-23T23:00:10.000Z **Commissioner Karen Douglas** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K227/595227206.PDF?ref=calregulatory.com) in [I.23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) finding that the winter 2022–2023 natural gas price spike resulted from a convergence of adverse market conditions, not misconduct by regulated utilities or storage providers. The PD concludes that sustained cold and high precipitation significantly increased gas demand, while interstate pipeline outages and maintenance (particularly on the El Paso system) restricted supply into California at critical moments. These constraints were compounded by reduced inflows from Western Canada, the Rockies, and the Permian Basin, low regional storage inventories, and bid-week pricing that captured peak spot prices during [Winter Storm Elliott.](https://en.wikipedia.org/wiki/December%5F2022%5FNorth%5FAmerican%5Fblizzard?ref=calregulatory.com) After reviewing extensive record evidence, the PD finds no improper or imprudent conduct by PG&E, SoCalGas, SDG&E, their core procurement departments, or independent storage providers. The PD emphasizes application of the Prudent Manager Standard, rejecting hindsight-based critiques of procurement, contracting, or storage decisions. It also finds no evidence of prohibited affiliate transactions, intentional withholding of supply, or manipulation of storage withdrawals. Rather than attempting to regulate gas commodity prices, the PD adopts a bill-shock mitigation and transparency framework for future events. It defines a “gas price spike event” as a 150% increase in the monthly core procurement charge relative to the 10-year monthly average, which would trigger a temporary cap on core procurement charges and amortization of any resulting undercollection. Under this framework, utilities would also be required to provide earlier, clearer customer notifications and information about assistance options. The PD further orders reforms to PG&E’s Core Procurement Incentive Mechanism and SoCalGas’s Gas Cost Incentive Mechanism. Any shareholder rewards would require approval through an application rather than an advice letter, and utilities must document procurement performance and risk management more clearly. In addition, the PD directs utilities to incorporate the specific constraints observed in 2022–2023 into future procurement and hedging strategies, to expand public reporting of storage inventories, and to improve transparency for both core and noncore customers. Comments are due **February 12**. The earliest the CPUC will consider this item is **February 26**. ### **INSTANT ANALYSIS** The PD treats the 2022–2023 gas price spike as a system-level stress event rather than a failure of utility conduct, concluding that extreme weather, pipeline outages, reduced regional inflows, low storage inventories, and bid-week timing combined to overwhelm California’s gas supply chain. Applying the Prudent Manager Standard, the PD clears PG&E, SoCalGas, SDG&E, their core procurement departments, and independent storage providers of wrongdoing, rejecting hindsight critiques of contracting, storage use, or affiliate activity. Rather than pursuing commodity price intervention, the PD pivots toward future bill-shock mitigation by defining a “gas price spike event” as a 150% increase relative to the ten-year monthly average, triggering a temporary cap on core procurement charges, amortization of undercollections, and enhanced customer notice requirements. The PD also tightens oversight of procurement incentive mechanisms by requiring formal applications for any shareholder rewards and expands transparency through standardized monthly storage inventory reporting. ### Fuel Cell and Biogas Interests Hit Procedural Wall in Push to Double SGIP Export Cap URL: https://www.calregulatory.com/fuel-cell-and-biogas-interests-hit-procedural-wall-in-push-to-double-sgip-export-cap/ Last updated: 2026-01-23T19:03:06.000Z **Commissioner Karen Douglas** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495666.PDF?ref=calregulatory.com) in [R.10-05-004](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/117826.PDF?ref=calregulatory.com) that denies a [petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M539/K203/539203565.PDF?ref=calregulatory.com) filed by [Bloom Energy Corp](https://www.bloomenergy.com/?utm%5Fterm=bloom%20energy%20corp&utm%5Fcampaign=be%5Fgg%5Fppc%5Fbr%5Fbrand-core&utm%5Fsource=google&utm%5Fmedium=cpc&hsa%5Facc=9429233231&hsa%5Fcam=22688023156&hsa%5Fgrp=179839685886&hsa%5Fad=758760772746&hsa%5Fsrc=g&hsa%5Ftgt=kwd-352728153804&hsa%5Fkw=bloom%20energy%20corp&hsa%5Fmt=e&hsa%5Fnet=adwords&hsa%5Fver=3&gad%5Fsource=1&gad%5Fcampaignid=22688023156&gbraid=0AAAAAC2AeZbfxgy-dhd8u0CTXHy70CvNy&gclid=CjwKCAiAssfLBhBDEiwAcLpwfjJuZ3uEptparFJitFG35irRH6YLfKhrKUG53p3Z2DByDKD23lTpcRoCA8cQAvD%5FBwE). to modify a long-standing export limitation under the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) (SGIP). The underlying 2011 decision ([D.11-09-015](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/143459.PDF?ref=calregulatory.com)) capped exports from SGIP-funded projects at **25%** of annual net generation, reflecting the program’s core purpose of supporting on-site self-generation rather than wholesale power production. Bloom’s August 2024 petition (filed nearly 13 years after the decision) requested that the export cap be increased to **50%**, arguing that advances in fuel-cell and biogas technology, along with changes in SGIP program rules, now allow greater exports to provide resiliency and emissions benefits without undermining cost-effectiveness. - The petition [was supported](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493283.PDF?ref=calregulatory.com) by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) and by SoCalGas ([jointly](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493284.PDF?ref=calregulatory.com) with the [Center for Sustainable Energy](https://energycenter.org/?ref=calregulatory.com)), who contended that a higher export cap would not conflict with tariffs or laws, would not increase program costs, and would remain consistent with SGIP’s objectives. - Cal Advocates [opposed](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M542/K867/542867049.PDF?ref=calregulatory.com) the petition, arguing both that it was procedurally defective and that it conflicted with SGIP’s policy intent. Cal Advocates emphasized that Rule 16.4(d) (available [here](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/rules-of-practice-and-procedure-may-2021.pdf?ref=calregulatory.com)) requires petitions for modification to be filed within one year of the effective date of a decision, absent a compelling explanation for delay. - Additionally Cal Advocates argued that Bloom’s reliance on technological maturation and evolving policy priorities did not meet that standard. The PD agrees, finding that the petition failed to justify why it could not have been filed within the required one-year window and concludes that routine technological or policy evolution cannot serve as a basis for reopening settled decisions more than a decade later. The PD further notes that the original export cap was grounded in SGIP’s programmatic focus on load-serving self-generation, not on technological limitations related to export capability. The earliest the PD will be considered is **February 26**. Comments are due **February 10**. ### **INSTANT ANALYSIS** This PD reflects the Commission’s emphasis on procedural finality and preservation of the original policy architecture of the Self-Generation Incentive Program. By denying Bloom Energy’s petition on Rule 16.4(d) grounds, the CPUC reinforces that SGIP design choices (particularly those that would shift the program toward increased grid exports) are not subject to reconsideration through late-filed petitions, even where technology or market conditions have evolved. The PD reaffirms SGIP’s role as a load-serving, on-site generation program and indicates that significant changes to export limits must be pursued through forward-looking rulemakings rather than retroactive modification. For developers and gas-aligned stakeholders, the PD highlights the Commission’s limited tolerance for reopening long-settled constraints absent a clear legislative directive or comprehensive program redesign. If adopted: - The PD would have a limited but clarifying effect on a defined subset of market participants. The primary impact would fall on Bloom Energy and other SGIP-funded project developers that use fuel cells or biogas-enabled generation and might seek to export a greater share of output to the grid, as those projects would remain subject to the existing 25% annual export cap. - The PD would affect future SGIP applicants by reinforcing that export flexibility is not an assumed feature of the program and that long-settled design constraints cannot be revisited through late-filed petitions. By contrast, the PD would not significantly affect retail ratepayers, utility revenue requirements, or SGIP funding levels, nor would it alter interconnection rules, utility tariffs, or non-SGIP distributed generation programs. Utilities and program administrators largely benefit from added regulatory certainty, as the existing SGIP framework remains intact without new compliance or cost-effectiveness implications. ### MID-WEEK NEWS CODEX: ZEV Sales; 100-Hour Carbon-Oxygen Battery; Farm-Based Grid Flexibility URL: https://www.calregulatory.com/midweek-news-codex-zev-sales-100-hour-carbon-oxygen-battery-farm-based-grid-flexibility/ Last updated: 2026-01-22T03:14:31.000Z - **BLM Says Increased Oil Drilling in California will Have Minimal Environmental Impact**: "The Bureau of Land Management [released](https://eplanning.blm.gov/public%5Fprojects/?doc=2037500%2F200654270%2F20149249%2F251049229%2F2025912%5FBakersfield%20Draft%20SEIS%20for%20Oil%20and%20Gas%20Leasing%202025%5F508%5F.pdf&ref=calregulatory.com) a draft environmental impact statement that concludes that new drilling in central and coastal California would not significantly harm public health or the environment. The environmental review is part of the Trump administration’s plans to open 1.2 million acres of federal mineral lands in California to oil and gas drilling." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/federal-government-plans-to-opens?ref=calregulatory.com) - **California Bills Would Cut Red Tape for Balcony Solar and Heat Pumps:** "Heat pumps — air conditioners that also provide all-electric heat — are about [two to five times](https://rmi.org/now-is-the-time-to-go-all-in-on-heat-pumps/?ref=calregulatory.com) as efficient as gas furnaces without those appliances’ planet-warming and [health-harming pollution](https://www.canarymedia.com/articles/fossil-fuels/just-how-bad-are-gas-appliances-for-your-health?ref=calregulatory.com). Even in California, where gas is [relatively inexpensive](https://causewaygt.com/2024/10/where-and-why-do-geothermal-heat-pumps-make-most-economic-sense-in-the-united-states/?ref=calregulatory.com) compared with electricity, a heat pump’s high efficiency can enable households [to save](https://www.nytimes.com/interactive/2025/07/16/upshot/heat-pumps.html?ref=calregulatory.com) on their energy bills, especially when tapping the sun for cheap, abundant power." [**CANARY MEDIA**](https://www.canarymedia.com/articles/solar/california-bills-balcony-solar-heat-pumps?ref=calregulatory.com) - **California is Getting Grid Planning Right – Now We Actually Need to Build It:** "In October 2025, Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric [released](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820156.PDF?ref=calregulatory.com) [draft](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834115.PDF?ref=calregulatory.com) [studies](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486686.PDF?ref=calregulatory.com) examining how electrification will affect the electric grid – and how much electric demand flexibility can change the outcome. While this work will continue into 2026, the early results are striking. PG&E’s analysis finds that while enabling electrification will require tens of billions of dollars in distribution investments through 2040, that same electrification could also save customers up to 25% by putting downward pressure on electric rates by improving system utilization. The takeaway is clear: electrification does not have to result in runaway costs to the customer’s electric bill. When electric utilities actively plan for flexible demand – including managed EV charging, building electrification paired with demand response, and distributed energy resources – the grid can be used more efficiently, spreading the fixed costs of grid investments over more kilowatt-hours, and lowering costs for all ratepayers." [**ENVIRONMENTAL DEFENSE FUND**](https://blogs.edf.org/energyexchange/2026/01/20/california-is-getting-grid-planning-right-now-we-actually-need-to-build-it/?ref=calregulatory.com) - **California Surpasses 2.5 Million ZEV Sales:** "During the fourth quarter of 2025, Californians purchased 79,066 new ZEVs, representing 18.9% of new car sales. These sales figures came in the shadow of federal ZEV incentives that ended on September 30, 2025, which resulted in a nationwide decline in ZEV sales. National sales for the fourth quarter dropped to 5.8%, compared with 10.5% in the third quarter, according to [Cox Automotive](https://www.coxautoinc.com/insights-hub/q4-2025-ev-sales-report-commentary/?ref=calregulatory.com)." [**CALIFORNIA ENERGY COMMISSION**](https://www.energy.ca.gov/news/2026-01/california-surpasses-25-million-zev-sales?ref=calregulatory.com) - **How Much Progress Has California Made to Reduce Wildfire Risk Since the LA Fires?** "Overall, it seems California is headed in the right direction on hazard mitigation, even if it could be headed there much faster. But even if the state were executing flawlessly—modeling fire risk, targeting treatments, coordinating burn windows—you can never eliminate hazard entirely. There will always be natural variability in weather and there will always be human error. That’s why it’s just as important that the state focuses on reducing exposure and vulnerability—something which it seems to have only just started taking seriously." [ **ECOMODERNIST**](https://www.breakthroughjournal.org/p/how-much-progress-has-california?ref=calregulatory.com) - **Noon Energy Successfully Demos its 100-Hour Carbon-Oxygen Battery:** "The news comes as Noon Energy, which was founded in 2018 and is based in Palo Alto, California, is fundraising for its next round and prepares to kickstart manufacturing. The company raised a $28 million Series A, led by Clean Energy Ventures, in late 2022." [**LATITUDE MEDIA**](https://www.latitudemedia.com/news/noon-energy-successfully-demos-its-100-hour-carbon-oxygen-battery/?ref=calregulatory.com) - **Proposed California Budget Includes New SAF Tax Credit:** "According to the committee, the new tax credit would offset diesel excise tax liability to incentivize in-state production." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/proposed-california-budget-includes-new-saf-tax-credit?ref=calregulatory.com) - **Reviving Industrial Relics – the Redondo Beach AES Power Plant $100M Unlock Demand Strategy:** "The 'Meter Rebellion' has begun. We are no longer waiting for centralized utilities to grant us permission to build. By leveraging these relics, we are creating a decentralized, resilient power layer that can support the AI-driven infrastructure of 2026 and beyond. BTM behind the meter is the only solution." [**CLINT'S SUBSTACK**](https://clintsmith.substack.com/p/reviving-industrial-relics-the-redondo) - **SCE Shares Progress on Wildfire Recovery:** "One year after the Eaton Fire started on Jan. 7, 2025, Southern California Edison is implementing a Wildfire Recovery Compensation Program to help the community recover and rebuild faster. As part of SCE’s commitment to long-term recovery following the wildfires, the company is also investing in infrastructure improvements that will help protect against future wildfires and support growth in Southern California. This includes plans to underground about 153 distribution circuit miles in and around Altadena and Malibu, California, and upgrade critical infrastructure to meet increasing customer demand." [**TRANSMISSION & DISTRIBUTION WORLD**](https://www.tdworld.com/wildfire/article/55343223/sce-shares-progress-on-wildfire-recovery?ref=calregulatory.com) - **The Biggest US Solar-Storage Project Yet Takes Shape in California:** "In December, the board of directors of the Westlands Water District, the agency that manages water delivery to more than 600,000 acres in California’s agricultural heartland, [approved](https://wwd.ca.gov/wwd-media/press-release-12-16-2025/?ref=calregulatory.com) the [Valley Clean Infrastructure Plan](https://goldenstatecleanenergy.com/projects/?ref=calregulatory.com). VCIP calls for building up to 21 gigawatts of solar energy and an equivalent amount of battery storage across up to 136,000 acres, along with a series of high-voltage transmission lines to connect the electricity generated to the state’s grid." [**CANARY MEDIA**](https://www.canarymedia.com/articles/solar/biggest-us-solar-storage-project-california?ref=calregulatory.com) - **Trump Administration Sues to Overturn California Oil Setback, Citing Federal Preemption:** "The Trump administration is [suing California](https://www.justice.gov/opa/pr/justice-department-files-complaint-against-california-over-unconstitutional-state-regulation?ref=calregulatory.com) to pause and overturn the state’s 2022 oil drilling setback law, known as SB 1137\. The administration is arguing that the Mineral Leasing Act and the Federal Land and Policy Management Act preempts the law. The administration notes that the law would 'knock out about one-third of all federally authorized oil and gas leases in California.' The lawsuit asks the court to declare SB 1137 unconstitutional and seeks an injunction against its enforcement." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/trump-administration-sues-to-overturn?ref=calregulatory.com) - **What it's Like to Build Grid-Scale Batteries in Texas Versus California**: "California may disadvantage small and midsize developers 'due to challenges such as high capital requirements, long timelines and regulatory complexity,' while Texas instead tests their ability to manage merchant risk and revenue volatility." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/21/what-its-like-to-build-grid-scale-batteries-in-texas-versus-california/?ref=calregulatory.com) - **Yield Energy Launches Farm-Based Grid Flexibility Platform:** "Agricultural energy flexibility provider Yield Energy has launched Yield Edge, a distributed energy resource management system, to improve grid-ready flexibility from farms. The platform is backed by US$3 million in funding from the California Energy Commission. It will initially focus on irrigation pumps, with plans to expand to other on-farm DERs including cold storage, EV and equipment chargers, solar arrays, batteries and on-site generation..." [**PV TECH**](https://www.pv-tech.org/yield-energy-launches-farm-based-grid-flexibility-platform/?ref=calregulatory.com) ### IN-FOCUS: Flex Alert Funding URL: https://www.calregulatory.com/in-focus-flex-alert-funding/ Last updated: 2026-01-21T23:27:30.000Z On January 20, parties responded to a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699379.PDF?ref=calregulatory.com) in the CPUC's Demand Response docket ([R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com)) regarding a [staff proposal ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827656.PDF?ref=calregulatory.com)to extend funding for California’s [Flex Alert ](https://www.flexalert.org/?ref=calregulatory.com)marketing campaign through 2026. ### Background Flex Alerts are voluntary conservation appeals designed to reduce electricity demand during peak periods, particularly heat events, and have been funded by the Commission since 2021 as part of its broader grid reliability response following the outages of 2020. - The staff proposal recommends maintaining the existing statewide paid media Flex Alert campaign for 2026 at the current annual budget of **$22 million**, funded by PG&E, SCE, and SDG&E, and administered by SCE under its existing contract with [Doyle Dane Bernbach Communications Group](https://en.wikipedia.org/wiki/DDB%5FWorldwide?ref=calregulatory.com). - The proposal emphasizes rising electricity demand pressures from electrification and data center growth. Staff cites evaluation results that show near-universal public awareness of Flex Alerts and widespread voluntary load reductions during alert days, including significant reductions in air conditioning and appliance use. - The proposal contains specific questions for parties on whether the program should continue in 2026, whether SCE should extend or renew the existing contract, what the appropriate 2026 budget should be, and whether additional conditions or program elements are needed for continued administration. ### Parties' Positions Across parties, there is broad agreement that Flex Alert has become a well-known statewide reliability tool, but disagreement over whether its current structure, funding mechanism, and scale remain justified absent the now-expired [Power Saver Rewards](https://help.pge.com/s/article/What-is-Power-Saver-Rewards?language=en%5FUS&ref=calregulatory.com) program. - [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085044.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481191.PDF?ref=calregulatory.com) support continuing Flex Alert in 2026, emphasizing its role as a low-cost, voluntary reliability resource during periods of grid stress and pointing to high public awareness levels and self-reported conservation behavior. PG&E and SCE argue that the program should evolve from broad awareness toward more targeted, action-oriented messaging, with an emphasis on real-time engagement, notification sign-ups, and measurable behavioral response. They support a one-year extension of the existing marketing contract to avoid disruption ahead of summer 2026, while recommending refinements to improve cost discipline, targeting, and performance measurement. PG&E specifically recommends reducing the budget from $22 million to **$12 million**, arguing the higher figure was justified by Power Saver Rewards marketing that is no longer needed. - SDG&E [takes a different position](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K345/595345031.PDF?ref=calregulatory.com) from the other investor-owned utilities, arguing that the program should have funding from taxpayers or a broader group of utilities beyond the three large IOUs. SDG&E also questions whether a marketing campaign can meaningfully address serious reliability issues, suggesting larger policy questions require attention from the CAISO and the Commission. If forced to continue ratepayer funding in the short term, SDG&E proposes slashing the budget to approximately **$4 million** annually, sufficient only for emergency alert messaging—and opposes creating any new marketing collateral. - Community Choice Aggregators, efficiency providers, and demand-side trade groups also back continuation, but stress that Flex Alert is approaching maturity and should be modernized. [CalCCA](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481192.PDF?ref=calregulatory.com) and the [California Efficiency + Demand Management Council](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481195.PDF?ref=calregulatory.com) argue that future value lies less in mass-market saturation and more in tailored, customer-specific outreach that drives incremental load reduction. CalCCA specifically recommends the Commission analyze whether diminishing marginal returns at 93% awareness levels warrant adjusting funding levels for future program years. Several parties caution that, with awareness already near saturation, additional spending risks diminishing returns unless messaging strategy and metrics improve. - Consumer advocates are more divided. The Utility Consumers' Action Network [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K320/595320912.PDF?ref=calregulatory.com) extending Flex Alert but urges a strategic shift away from generic conservation appeals toward messaging that explicitly links customer actions to long-term rate stability and avoided infrastructure costs. UCAN frames Flex Alert as a “soft battery” that, if properly designed, can empower customers as active participants in managing system costs. The Small Business Utility Advocates [similarly support continuation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495643.PDF?ref=calregulatory.com) but raise concerns about rate fatigue among small businesses. SBUA calls for rigorous, ongoing evaluation to verify that claimed behavioral changes translate into measurable peak demand reductions, particularly for customer classes with limited flexibility. - In contrast, [Leapfrog Power](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K495/595495637.PDF?ref=calregulatory.com) and [Cal Advocate](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K345/595345039.PDF?ref=calregulatory.com)s oppose extending Flex Alert funding in its current form. Leap argues that a $22 million annual marketing program with no performance obligations is misaligned with modern demand-response principles and should be replaced with pay-for-performance incentives targeted at customers capable of delivering verifiable load reductions. Cal Advocates goes further, contending that continued IOU ratepayer funding is inconsistent with Commission precedent and unjustified now that the Power Saver Rewards program has ended. Cal Advocates emphasizes that Flex Alert was previously intended to be administered and funded by the CAISO on a statewide basis, and argues that extending IOU-funded marketing without structural reform would perpetuate an inequitable cost allocation. - TURN [occupies a middle position](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K201/595201116.PDF?ref=calregulatory.com), acknowledging Flex Alert’s reliability value while recommending only bridge funding for 2026\. TURN urges the Commission to use that time to redesign the funding mechanism, potentially shifting costs to a statewide allocator such as the CAISO or the California Energy Commission, require competitive procurement for future contracts, and reduce the program’s budget to reflect the sunset of Power Saver Rewards and the program’s current maturity. Reply comments are due **January 30**. ### INSTANT ANALYSIS Parties broadly support keeping Flex Alert in place for summer 2026, but the record shows limited appetite for extending the program unchanged. With Power Saver Rewards now expired, the longstanding concern over IOU ratepayers funding a statewide program has re-emerged as the main weakness in the Staff Proposal. Most utility and CCA support is pragmatic rather than permanent, framing 2026 as a bridge year to avoid disrupting summer reliability. Notably, the three IOUs are not aligned: PG&E and SCE support continuation with reforms, while SDG&E's position aligns more closely with program skeptics, advocating for either termination of ratepayer funding or a dramatic budget reduction. At the same time, multiple parties suggest that continuation beyond 2026 would require changes to funding allocation, budget size, and program design. There is also growing pressure to move beyond mass-market awareness toward measurable performance. Even supporters acknowledge diminishing returns at the current $22 million spend absent clearer evidence of incremental load reduction. **Net takeaway:** a one-year extension is likely defensible, but 2026 looks like a crossroads. Without funding reform and a tighter link to demonstrable grid value, Flex Alert faces a harder path past next summer. ### WEDNESDAY AGGREGATE: PG&E's Yield Spread Adjustment; SDG&E TIMPBA Settlement; the RA Market Price Benchmark URL: https://www.calregulatory.com/wednesday-aggregate-8/ Last updated: 2026-01-21T22:47:52.000Z Today's roundup is heavy on SDG&E filings. Topics covered include: - PG&E's [implementation](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5169-G.pdf?ref=calregulatory.com) of a Yield Spread Adjustment, as authorized by the CPUC in its [2026 Cost of Capital decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com); - An [amended joint motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481169.PDF?ref=calregulatory.com) filed by SDG&E and Cal Advocates that seeks approval of a settlement resolving SDG&E’s application to recover Transmission Integrity Management Program Balancing Account costs from January 2019 through December 2023; - SDG&E's response to an application for rehearing filed by two CCAs in which the CCAs argue that the CPUC unlawfully set [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates by retroactively applying a new Resource Adequacy Market Price Benchmark methodology to 2025 costs; - A [draft resolution](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K980/595980485.PDF?ref=calregulatory.com) approving two SDG&E mid-term reliability contracts resulting from the company's Tranche 3 solicitation, authorizing a combined 92 MW of standalone battery energy storage projects; and - A ruling requiring PG&E to explain why it filed its recent [gas-line subsidy application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M571/K244/571244398.PDF?ref=calregulatory.com) without including the non-residential gas line extension allowance calculations expressly required by prior Commission direction. --- ### PG&E RATES/COST OF CAPITAL PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5169-G.pdf?ref=calregulatory.com) to implement the Yield Spread Adjustment (YSA) authorized in the CPUC's [2026 Cost of Capital decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com), establishing how interest will be calculated on balancing and memorandum accounts beginning January 1, 2026\. The YSA is designed to reflect the difference between PG&E’s actual short-term borrowing costs and the three-month Commercial Paper rate historically used for regulatory interest. For 2026, the YSA is set at 125 basis points, based on a 12-month average spread. __PG&E Weighted Average Borrowing Rate vs. Commercial Paper Rate__ | Month | PG&E Rate | H.15 CP (90-Day) | Spread | | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------- | ---------------- | ------ | | Nov 2024 | 5.84% | 4.57% | 1.27% | | Dec 2024 | 5.53% | 4.43% | 1.10% | | Jan 2025 | 5.44% | 4.23% | 1.21% | | Feb 2025 | 5.45% | 4.27% | 1.18% | | Mar 2025 | 5.45% | 4.28% | 1.17% | | Apr 2025 | 5.45% | 4.32% | 1.13% | | May 2025 | 5.45% | 4.30% | 1.15% | | Jun 2025 | 5.46% | 4.32% | 1.14% | | Jul 2025 | 5.55% | 4.30% | 1.25% | | Aug 2025 | 5.52% | 4.20% | 1.32% | | Sep 2025 | 5.54% | 4.01% | 1.53% | | Oct 2025 | 5.42% | 3.90% | 1.52% | | Average | 5.51% | 4.26% | 1.25% | | Source: PG&E Advice Letter 5169-G/7818-E (Jan. 20, 2026). Weighted average reflects PG&E Revolving Credit Facility, AR Facility, 364-Day Floating-Rate Note, and Term Loan. | | | | _This post is for paying subscribers only._ ### Deep Dive: The Sempra IOUs' $5 Billion Post-Test-Year Ratemaking Gambit URL: https://www.calregulatory.com/deep-dive-the-sempra-ious-5-billion-post-test-year-ratemaking-gambit/ Last updated: 2026-01-20T23:04:05.000Z On January 16, multiple parties responded to a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K986/590986352.PDF?ref=calregulatory.com) filed by SoCalGas/SDG&E (the Sempra Utilities) seeking changes to the post-Test-Year ratemaking mechanism adopted by the CPUC in a 2024 decision, [D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com). (*See CRI's coverage of the Sempra Utilities' petition* [*here*](https://www.calregulatory.com/monday-aggregate-capital-recovery-attrition-design-decarbonization-cost-allocation-gas-system-continuity-w-o-new-assets/)). [Capital Recovery & Attrition DesignCapital-recovery mechanics dominate today’s report, with utilities pressing on opposite edges of the same constraint…![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1---1--3.png)CALIFORNIA REGULATORY INTELLIGENCEMC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Dec-17-2025--10-.png)](https://www.calregulatory.com/monday-aggregate-capital-recovery-attrition-design-decarbonization-cost-allocation-gas-system-continuity-w-o-new-assets/) The Sempra Utilities claim the adopted mechanism leaves approximately **$5 billion** in capital-related revenue requirements unfunded over the 2025–2027 post-Test-Year period. Opposing parties ([Indicated Shippers/Environmental Defense Fund](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K908/594908409.PDF?ref=calregulatory.com), [TURN/Southern California Generation Coalition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K345/595345016.PDF?ref=calregulatory.com), [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K908/594908410.PDF?ref=calregulatory.com), and the [Protect Our Communities Foundation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K320/595320890.PDF?ref=calregulatory.com)) argue that the petition is procedurally improper and substantively deficient. They contend that SoCalGas/SDG&E are attempting to relitigate issues that were expressly resolved in the underlying General Rate Case, and the petition functions as an untimely application for rehearing rather than a legitimate request for modification. - Opposing parties emphasize that Rule 16.4 (available [here](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M209/K618/209618807.pdf?ref=calregulatory.com)) and [Public Utilities Code §1708](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-9/article-1/section-1708/?ref=calregulatory.com) require genuinely new facts, changed circumstances, or a clear misconception of law or fact, none of which are present. In their view, an alleged “revenue shortfall” identified by the utilities arises only because the CPUC rejected the utilities’ preferred capital-driven escalation framework in favor of a uniform 3% CPI-based post-Test-Year mechanism. The latter mechanism is designed to moderate rate growth, address affordability concerns, and constrain rate-base expansion in the context of declining gas demand. - The parties argue further that granting the petition would undermine regulatory finality and violate due-process expectations of parties to the GRC. TURN/SCGC specifically argue that retroactively modifying the post-Test-Year mechanism and adjusting previously collected revenue requirements raises retroactive ratemaking concerns, citing case law establishing that the CPUC may not retroactively increase rates previously adopted after a full hearing. - Opposing parties defend the CPUC’s policy judgment in D.24-12-074, stressing that post-Test-Year mechanisms are not intended to guarantee full recovery of all projected capital expenditures or to replicate a test-year cost-of-service analysis. Instead, they characterize post-Test-Year ratemaking as a discretionary tool meant to provide utilities a reasonable opportunity to earn their authorized return through prudent management, while balancing ratepayer protections. - TURN/SCGC notably concede that O&M expenses and capital expenditures do affect revenue requirements differently (their own proposal in this proceeding used a two-part mechanism) but argue the CPUC has broad discretion to fashion an appropriate post-Test-Year mechanism in each General Rate Case, or to provide no mechanism at all. - Protect Our Communities Foundation raises additional arguments not emphasized by other opposing parties: that the utilities failed to account for billions of dollars in deferred taxes (ratepayer-provided cash available at zero cost for capital projects) when calculating their alleged "missing money." PCF also argues that capital expenditures should be trending **downward** given that the Pipeline Safety Enhancement Program began over 15 years ago and wildfire mitigation programs have been in place since 2019. - Opposing parties also note that the CPUC already authorized significant Test-Year revenue increases, adopted targeted exceptions to the 3% escalation for specific capital programs, and approved memorandum accounts for gas integrity and other defined activities. In this context, they argue that the petition’s requested two-part capital mechanism would upset the careful balance struck in the decision and shift risk from shareholders to ratepayers in ways inconsistent with affordability objectives. - Indicated Shippers/Environmental Defense Fund add that the utilities' proposed "rate smoothing" mechanism is a disguised attempt to prevent a scheduled rate decrease (resulting from the roll-off of existing memorandum account amortizations) from reaching customers' bills. By contrast, [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K481/595481175.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083723.PDF?ref=calregulatory.com) support the petition and align with the Sempra Utilities' central argument that the CPUC's adoption of a one-part post-Test-Year mechanism rests on a misconception of how capital costs affect revenue requirements. The utilities assert that capital expenditures, unlike O&M expenses, translate into revenue requirements through depreciation, return, and taxes over time, and that applying a single escalation factor to total revenue requirement materially underfunds capital additions in the post-Test Years. Both PG&E and SCE provide illustrative tables (see below), which show that a one-part mechanism funds capital additions only for the Test Year, leaving significant revenue requirement shortfalls in each subsequent attrition year. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/01/funding1.png) PG&E illustrates the funding gap created by D.24-12-074's one-part post-Test-Year mechanism. Assuming $1 billion in Test-Year capital additions escalated at 3%, the table shows that calculating revenue requirements based on actual cost components (depreciation, taxes, and return) would yield $286 million – $566 million across the attrition years, while the adopted mechanism yields only $148 million – $157 million (a cumulative shortfall of $820 million over the three post-Test Years). ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/01/funding2.png) SCE demonstrates the compounding effect of the one-part mechanism over a full General Rate Case cycle. Assuming flat $100 million annual capital expenditures, the table shows that by 2028 a utility would have invested $400 million in capital projects but could recover only $7.9 million that year under the adopted mechanism (about one-sixth of the $47.7 million revenue requirement needed to cover depreciation, return, and taxes on assets already serving customers). The utilities argue that this underfunding threatens their ability to complete Commission-approved capital projects necessary for safety, reliability, and risk mitigation, and increases the likelihood of rate volatility in future GRCs. PG&E and SCE maintain that long-standing Commission precedent supports a two-part post-Test-Year framework that separately addresses capital additions, and that modifying D.24-12-074 to adopt such an approach would better align the decision with the regulatory compact and constitutional requirements to provide utilities a fair opportunity to earn their authorized returns. **INSTANT ANALYSIS:** The Sempra Utilities' petition for modification faces broad resistance from ratepayer, environmental, and public-interest parties, who argue it is an improper attempt to relitigate the post-Test-Year mechanism adopted in D.24-12-074 and fails to meet the Rule 16.4 standard for new or changed facts. These parties defend the Commission’s uniform 3% CPI-based escalation as a deliberate affordability and rate-base-control measure, warning that reopening the decision would undermine regulatory finality and raise retroactive ratemaking concerns. Support comes primarily from other utilities, who contend the one-part post-Test-Year mechanism significantly underfunds capital additions and departs from precedent. The CPUC's treatment of this issue will demonstrate how firmly it intends to hold the line on post-Test-Year moderation in the face of renewed utility pressure. ### ERRA/PCIA Reform, Track 2: Who Gets Credit for a Decade-Old REC? URL: https://www.calregulatory.com/wednesday-aggregate-7/ Last updated: 2026-01-20T19:05:29.000Z SCE and other parties filed a [joint prehearing conference statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085039.PDF?ref=calregulatory.com) in the CPUC’s [ERRA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com)/[PCIA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) reform docket, outlining positions for Track 2, which is narrowly focused on whether Renewable Energy Credits generated before January 1, 2019 should carry a ratemaking value. The investor-owned utilities argue that pre-2019 banked RECs were fully valued under the former PCIA methodology and that assigning a new value now would violate statutory indifference and impose retroactive cost shifts on bundled customers. [CalCCA](https://cal-cca.org/?ref=calregulatory.com), the [Alliance for Retail Energy Markets](http://www.retailenergymarkets.com/?ref=calregulatory.com), and the Direct Access Customer Coalition argue that customers who later departed bundled service may be entitled to credits when those RECs are used for current [Renewables Portfolio Standard](https://www.energy.ca.gov/programs-and-topics/programs/renewables-portfolio-standard?ref=calregulatory.com) compliance. Additionally: - [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) proposes broadening the scoping issues to address differences between pre-2019 and post-2019 indifference methodologies, not just REC characteristics; - [CLECA](https://cleca.org/?ref=calregulatory.com) explicitly takes no position on Track 2 issues at this time; and - CalCCA notes the pre-2019 banked REC valuation question has been litigated eleven times in prior proceedings without settlement, making adjudicated resolution likely necessary. A procedural wrinkle: two 2025 decisions ([D.25-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K312/592312564.PDF?ref=calregulatory.com) and [D.25-12-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K808/591808611.PDF?ref=calregulatory.com)) require IOUs to implement any guidance issued before **September 1, 2026**, but the proposed Track 2 schedule targets a **September 3** voting meeting. CalCCA asks the IOUs to voluntarily commit to implementing guidance from a September 3 decision. CalCCA also raises data access concerns relevant to Track 3 and questions SCE's confidentiality designations around pre-2019 banked REC usage. **INSTANT ANALYSIS:** This filing presents a narrow but consequential Track 2 dispute over whether pre-2019 banked RECs should carry any ratemaking value under the PCIA. The IOUs argue these RECs were already valued under the former PCIA framework and that re-valuation would violate statutory indifference by shifting costs onto bundled customers. CalCCA, AReM, and DACC argue that customers who later departed bundled service may be owed credits when those same RECs are used for current RPS compliance. The disagreement concerns whether the Commission can revisit legacy REC treatment without reopening prior rate outcomes. If the Commission adopts a non-zero value, that could affect ERRA forecast mechanics, PCIA calculations, and future REC market behavior. Maintaining a zero-dollar value would reinforce the post-2019 framework and limit further challenges to legacy REC treatment. ### FRIDAY AGGREGATE: IRP Cycle 2024-2026 Changes; Woolsey Fire Financing Order; Aliso Canyon Filing URL: https://www.calregulatory.com/friday-aggregate-irp-cycle-2024-2026-changes-woolsey-fire-financing-order-aliso-canyon-filing/ Last updated: 2026-01-20T18:12:37.000Z Today's CPUC briefing includes: - An ALJ ruling setting the requirements and schedule for the next round of individual Integrated Resource Plans; - An SCE [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com) seeking CPUC approval of a financing order to securitize costs associated with the 2018 Woolsey Fire, via the issuance of recovery bonds; - A SoCalGas application telling the CPUC that Aliso Canyon remains necessary for reliability, and that reducing inventory now would be a mistake; - Parallel CalCCA applications for rehearing of CPUC decisions that approved the 2026 ERRA Forecasts for PG&E and SCE; - A draft resolution that increases funding for the [California Distributed Generation Statistics](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) platform; - A joint IOU advice letter updating the terms and conditions of the [Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com); - A scoping memo establishing the procedural framework for [LS Power’s "Power the South Bay" transmission project](https://www.lspowergrid.com/wp-content/uploads/Power-the-South-Bay-2-Pager.pdf?ref=calregulatory.com) CPCN application; - A PG&E [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7814-E.pdf?ref=calregulatory.com) seeking approval of an exceptional-case agreement to serve [Genentech](https://www.gene.com/?ref=calregulatory.com)’s South San Francisco campus expansion, with up to 30 MW of transmission-level service by 2034; and - SoCalGas's notice of a planned curtailment that will affect a limited set of noncore customers in the Riverside area. --- ### INTEGRATED RESOURCE PLANNING **Administrative Law Judge Fitch** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085015.PDF?ref=calregulatory.com) in R.25-06-019 setting the requirements and schedule for the next round of individual Integrated Resource Plans for the model years 2026, 2028, 2030, 2035, 2040, and 2045. The ruling moves the IRP filing deadline from May 5 to **June 1, 2026**, aligning it with regularly required procurement compliance filings, and provides detailed direction on the modeling inputs, assumptions, and templates that load-serving entities must use. LSEs are required to base their plans on: - Updated Commission modeling inputs (including 2024 [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) load forecasts); - Revised [RESOLVE](https://www.ethree.com/tools/resolve/?ref=calregulatory.com) assumptions (with enhanced geothermal systems and generic long-duration energy storage added as default candidate resources); - Updated resource costs and potentials; and - Finalized greenhouse gas benchmarks allocated proportionally by load to meet sector targets of 25 MMT by 2035 and 8 MMT by 2045\. These load forecasts were adjusted after CCAs submitted forecasts that in aggregate fell below the 2024 IEPR reference case, prompting the California Energy Commission to escalate individual forecasts at sector growth rates and apply pro rata adjustments to reach 100% of service area totals. PG&E, SCE, and SDG&E had objected that CCA submissions failed to account for projected data center load growth. Commission staff also provided a representative statewide least-cost portfolio as planning guidance, though LSEs retain flexibility to submit both a required conforming portfolio that meets assigned GHG targets and an optional preferred portfolio that goes beyond those requirements. The ruling mandates use of the Narrative Template, Clean System Power Calculator, and Resource Data Template, clarifies treatment of long lead-time resources, and sets **July 15** as the deadline for comments on filed IRPs. **INSTANT ANALYSIS:** This ruling fixes the analytical frame for the 2024–26 IRP cycle by standardizing load forecasts, emissions benchmarks, and modeling assumptions ahead of individual filings. Compliance risk now sits primarily with portfolio composition and procurement follow-through, rather than forecast discretion. The staff RESOLVE portfolio functions as a reference case, centered on solar, storage, geothermal, and wind, with gas capacity retained for reliability through 2045 and continued reliance on Path 26 and Path 15 transmission expansions. Aligning IRP and procurement filings places greater emphasis on internal consistency between planning assumptions and executable procurement paths. --- ### WOOLSEY FIRE SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K084/595084990.PDF?ref=calregulatory.com) seeking CPUC approval of a financing order under the Public Utilities Code to securitize costs associated with the 2018 Woolsey Fire through the issuance of recovery bonds. The request follows the CPUC’s December 2025 settlement decision authorizing recovery of approximately $1.97 billion in just and reasonable [Woolsey Fire](https://en.wikipedia.org/wiki/Woolsey%5FFire?ref=calregulatory.com)–related costs recorded in SCE’s Wildfire Expense Memorandum Account, with those costs to be financed rather than recovered through traditional ratemaking. (*See our summary of that decision* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)*.*) [December 18 CPUC Voting Meeting ResultsCovers: Cost of Capital; Long-Term Gas Planning; the Woolsey Fire![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1--4.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Dec-17-2025.png)](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/) SCE proposes issuing **$1.95 billion** in recovery bonds through a bankruptcy-remote special purpose entity, supported by a non-bypassable fixed recovery charge on customer bills and a Commission-approved true-up mechanism to ensure timely bond repayment. SCE argues that securitization will materially reduce customer costs on a net present value basis compared to conventional utility financing, with estimated savings exceeding **$800 million**, while preserving credit quality through structural protections, annual true-ups, and Commission oversight. **INSTANT ANALYSIS**: This application implements the Woolsey Fire settlement by securitizing $1.95 billion of approved wildfire costs through recovery bonds backed by a non-bypassable fixed recovery charge. The goal is lower-cost financing and rate smoothing versus traditional utility debt. The proposal tracks prior wildfire securitizations, especially the [Thomas Fire](https://en.wikipedia.org/wiki/Thomas%5FFire?ref=calregulatory.com), and is largely executional rather than substantive. Key review points will be the expedited schedule, finance team oversight of final bond terms, and confirmation that charge allocation and exemptions align with existing Commission practice --- ### ALISO CANYON SoCalGas filed a [compliance application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083702.PDF?ref=calregulatory.com) to request CPUC review of Energy Division’s [2025 Aliso Canyon Biennial Assessment](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/2025%5Faliso%5Fcanyon%5Fbiennial%5Fassessment.pdf?ref=calregulatory.com), which recommends reducing the facility’s maximum inventory level by **10 Bcf** from the current **68.6 Bcf** authorized in a 2024 decision ([D.24-12-076](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M551/K009/551009286.PDF?ref=calregulatory.com)). - SoCalGas argues that the Biennial Assessment understates continued reliance on Aliso Canyon due to overly optimistic assumptions about pipeline availability, receipt-point utilization, and storage performance, and that reducing inventory would increase gas and electric reliability risks, price volatility, and costs to ratepayers. - Notably, SoCalGas emphasizes that Staff themselves hedged the reduction recommendation, stating that "a smaller incremental or no reduction may be appropriate" given forward price risks and near-term factors including increased US LNG exports and the startup of the [Energía Costa Azul LNG ](https://www.gem.wiki/Costa%5FAzul%5FLNG%5FTerminal?ref=calregulatory.com)facility in Baja California. - The application contends that Aliso Canyon remains critical to meeting peak demand, particularly during 1-in-10 winter conditions, and that corrected modeling inputs show higher withdrawal needs than assumed by Commission Staff. - SoCalGas further asserts that the economic analysis is limited, cannot reliably predict price impacts, and fails to account for reductions to the Unbundled Storage program, which would compound adverse ratepayer effects. - The application also argues that applying Staff's own threshold methodology consistently would show winter 2026-2027 forward prices exceed the threshold, creating an internal inconsistency in the analysis. Accordingly, SoCalGas asks the Commission to decline to authorize any reduction in Aliso Canyon’s maximum inventory at this time and to authorize an increase in the inventory level if necessary to maintain system reliability and just and reasonable rates. **INSTANT ANALYSIS:** SoCalGas is directly challenging Energy Division’s first Aliso Canyon biennial recommendation, arguing that any inventory reduction is premature and increases reliability risk due to optimistic assumptions around pipeline availability, receipt-point utilization, and storage performance. The application frames the dispute as a modeling credibility issue while leveraging Staff's own hedging language against the recommendation, and highlights added ratepayer exposure from higher price volatility and reductions to the Unbundled Storage program. --- ### ERRA FORECASTS CalCCA filed [parallel](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K085/595085005.PDF?ref=calregulatory.com) [applications](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K402/594402144.PDF?ref=calregulatory.com) for rehearing that challenge the CPUC’s approval of 2026 ERRA Forecast decisions for PG&E and SCE ([D.25-12-027](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K312/592312564.PDF?ref=calregulatory.com) and [D.25-12-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K808/591808611.PDF?ref=calregulatory.com), respectively – *see our summaries* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)). [December 18 CPUC Voting Meeting ResultsCovers: Cost of Capital; Long-Term Gas Planning; the Woolsey Fire![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1--5.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Wed-Dec-17-2025-1.png)](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/) - CalCCA argues that both decisions unlawfully set [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates in ways that harm departing load and violate long-standing indifference principles. - CalCCA also contends the CPUC improperly allowed the utilities to retroactively apply a new Resource Adequacy Market Price Benchmark methodology adopted in a 2025 decision ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)) to value 2025 RA portfolios, even though PCIA rates for that year were already being collected under the prior, settled methodology. - According to CalCCA, this midstream methodological change eliminated the required true-up and instead resulted in prohibited retroactive ratemaking, exceeding the Commission’s authority, lacking adequate findings, and reflecting an abuse of discretion. Last, CalCCA challenges the Commission’s approval of proposals by both SCE and PG&E to assign zero value to pre-2019 banked Renewable Energy Credits used for bundled customer Renewables Portfolio Standard compliance in 2025 and 2026\. CalCCA argues that this treatment unlawfully deprives departed customers of benefits they helped fund and violates statutory indifference requirements and Commission precedent requiring such RECs to be valued at the RPS MPB. **INSTANT ANALYSIS:** These parallel applications present a coordinated challenge to how the Commission handled PCIA true-ups in the 2026 ERRA cycle, with CalCCA arguing that retroactive application of the revised RA Market Price Benchmark crossed from lawful balancing-account practice into prohibited retroactive ratemaking. The filings also dispute the interim acceptance of zero-value treatment for pre-2019 banked RECs, framing it as a violation of statutory indifference requirements and settled PCIA precedent. If credited on rehearing or appeal, the arguments could affect not only 2026 PCIA outcomes for PG&E and SCE but also the viability of applying D.25-06-049 across other ERRA proceedings. --- ### DISTRIBUTED GENERATION The CPUC issued [Draft Resolution E-5436](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K101/595101395.PDF?ref=calregulatory.com), which increases funding for the California Distributed Generation Statistics platform to **$2.6 million** per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion. The draft resolution directs PG&E, SCE, and SDG&E to improve data quality by revising their online interconnection application interfaces, including standardized equipment drop-downs, stronger cost validation, corrected system size calculations, and retroactive fixes to existing data. The item also orders a rebranding of [DGStats](https://www.californiadgstats.ca.gov/?ref=calregulatory.com) to reflect the inclusion of non-distributed-generation programs and authorizes publication of anonymized Contractors State License Board disclosure document data. Finally, the IOUs must host a public workshop and improve tracking and reporting of system decommissioning to address growing accuracy gaps as legacy systems retire. The earliest the Commission will consider this item is **February 26**. **INSTANT ANALYSIS:** This draft resolution upgrades DGStats into durable regulatory infrastructure by nearly tripling funding, allowing inflation adjustments, and positioning the platform as a long-term backbone for forecasting, planning, and enforcement. The draft resolution targets data quality failures directly, mandating automated sizing, validated equipment lists, retroactive corrections, standardized cost inputs, and structured decommissioning tracking (changes that will alter historical and forward-looking Distributed Energy Resource analyses). Publishing anonymized CSLB disclosure data and rebranding the platform expands DGStats from a reporting site into a transparency and compliance tool with real market discipline effects. --- ### EMERGENCY LOAD REDUCTION PROGRAM PG&E, SCE, and SDG&E jointly filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7816-E.pdf?ref=calregulatory.com) to update the [Emergency Load Reduction Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/demand-response-dr/emergency-load-reduction-program?ref=calregulatory.com) terms and conditions pursuant to a 2023 decision (D.23-12-005). The filing does not change the underlying ELRP program design, but instead makes statewide, largely administrative clarifications related to enrollment, disenrollment, settlement, baseline calculations, and incentive eligibility. The filing also formally sunsets the residential Power Saver Rewards program (ELRP Sub-Group A.6) following its authorized expiration at the end of 2025\. The utilities also propose utility-specific clean-ups, including clearer rules around missing meter data, forfeiture of incentives when service accounts close, distinctions between aggregators and service providers, updated baseline and day-of adjustment mechanics, and streamlined customer authorization and data-sharing language. Protests are due **February 4**. **INSTANT ANALYSIS:** This filing is administrative, but it clarifies and enforces payment eligibility under ELRP. The formal sunset of Power Saver Rewards closes the residential chapter and narrows ELRP’s scope back to non-residential customers and aggregations. New language around missing meter data, baseline construction, and service-account status places greater responsibility on participants and aggregators to maintain clean data and continuous enrollment. The practical takeaway is that ELRP remains available, but settlement mistakes now carry explicit financial consequences. --- ### TRANSMISSION WORK **Commissioner Karen Douglas** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K414/594414374.PDF?ref=calregulatory.com) in [A.24-05-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M531/K704/531704388.PDF?ref=calregulatory.com), setting the scope, schedule, and procedural framework for [LS Power’s Power the South Bay transmission project](https://www.lspowergrid.com/wp-content/uploads/Power-the-South-Bay-2-Pager.pdf?ref=calregulatory.com) CPCN application. The project, selected by the CAISO as a reliability-driven upgrade, was modified from a mixed AC/DC design to an exclusively 230 kV AC line, with an estimated **$677.7 million** capital cost recovered through CAISO transmission rates. The CAISO requires the project to be in service by **June 1, 2028**, and LS Power has agreed to cost-containment controls enforceable by the CAISO. **INSTANT ANALYSIS:** This scoping memo places the Power the South Bay CPCN on a fast, low-friction track. The primary substantive risk is not need or cost recovery (which are largely anchored by CAISO selection and FERC-jurisdictional transmission rates) but CEQA, specifically the acknowledged temporary (but significant) air-quality impacts at the Santa Clara terminus. The Commission is already framing an overriding considerations finding, indicating that system reliability and regional benefits will be weighed against localized construction impacts. With a briefing-only schedule and a Q1 2026 decision target, the proceeding is positioned for approval based on the existing record. --- Separately, PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7814-E.pdf?ref=calregulatory.com) seeking approval of an exceptional-case agreement to serve Genentech’s South San Francisco campus expansion with up to 30 MW of transmission-level service by 2034. The project relies on bespoke Rules 2, 15, and 16 agreements, with Genentech paying actual costs for transmission upgrades and special facilities, largely insulating existing ratepayers. Refunds are contingent on realized load and revenues, using standard Rule 15 Base Annual Revenue Calculation mechanics, while certain design and special facility costs remain non-refundable. **INSTANT ANALYSIS:** This is a procedurally conservative, low-risk transmission service filing that cleanly walls off cost exposure from existing ratepayers through actual-cost treatment, limited refunds, and non-refundable special facilities. Its real significance is precedential: it shows how PG&E is still using Rules 2, 15, and 16 exceptional cases to onboard large transmission-level loads while Rule 30 remains interim, preserving flexibility for bespoke negotiations. --- ### NATURAL GAS CURTAILMENT SoCalGas issued a planned maintenance notice advising that certain noncore customers in (and around) Riverside will be subject to a temporary natural gas [service reduction](https://www.socalgas.com/business/energy-market-services/curtailments?ref=calregulatory.com) pursuant to Rule 23\. The curtailment is scheduled from 6:00 a.m. **February 2**, through 6:00 p.m. **February 6**, although the duration may vary depending on work completion. Affected customers will receive individual maximum-usage limits in advance of the event and are advised to coordinate directly with their SoCalGas account representatives and monitor Envoy for updates. The notice reflects a localized, planned maintenance action rather than a systemwide constraint. **INSTANT ANALYSIS:** This is a routine, localized maintenance curtailment affecting a limited set of noncore customers in the Riverside area. It does not indicate broader system constraints, policy change, or near-term reliability risk for the Southern California gas system. The item is most relevant as an operational heads-up for affected industrial customers and does not warrant broader market or regulatory concern absent clustering or escalation of similar notices. ### New IRP Proposed Decision Allocates 6 GW Across California Load-Serving Entities URL: https://www.calregulatory.com/new-cpuc-irp-proposed-decision-allocates-6-gw-across-california-load-serving-entities/ Last updated: 2026-01-17T02:41:03.000Z **Administrative Law Judge Fitch** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K083/595083681.PDF?ref=calregulatory.com) that, if adopted, would require California load-serving entities to procure additional clean reliability resources to address forecasted system needs in the 2029–2032 period. The PD orders **2,000 MW** of net qualifying capacity online by **June 1, 2030**, and an additional **4,000 MW** by **June 1, 2032**, with no more than half of each tranche met by storage. The PD also transmits updated base and sensitivity portfolios to the CAISO for use in its 2026–2027 Transmission Planning Process. The procurement finding is based on updated [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) load forecasts, reliability modeling using [SERVM](https://power-gem.co/software/servm-resource-adequacy-planning/?ref=calregulatory.com), and the risk of delayed long-lead-time resources. Eligible resources must follow the Mid-Term Reliability framework and be new, zero-emitting and/or [RPS](https://www.energy.ca.gov/programs-and-topics/programs/renewables-portfolio-standard?ref=calregulatory.com)\-eligible, with limited credit for repowering only to the extent of incremental capacity added. The PD does not impose a separate energy-procurement mandate, relying instead on [ELCC](https://blog.ucs.org/mark-specht/elcc-explained-the-critical-renewable-energy-concept-youve-never-heard-of/?ref=calregulatory.com)\-based capacity requirements and existing RPS and Resource Adequacy programs. - An [accompanying attachment](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M595/K201/595201050.PDF?ref=calregulatory.com) allocates the 6,000 MW NQC obligation across investor-owned utilities, Community Choice Aggregators, and aggregated Electric Service Providers based on adjusted 2026 load shares (see table below). - The largest shares fall on PG&E and SCE bundled service, followed by major CCAs such as Clean Power Alliance, East Bay Community Energy, and San Diego Community Power. ESP obligations are shown only in aggregate and will be conveyed confidentially to individual providers. Comments are due **February 3**. The earliest the CPUC will consider this item is **February 26**. Procurement Obligations by Load Serving Entity Proposed Decision — Attachment A (R.25-06-019) | Load Serving Entity | Type | 2026 Load(GWh) | Adj. Share | 2030(MW NQC) | 2032(MW NQC) | Total(MW NQC) | | ------------------------------------------- | ---- | -------------- | ---------- | ------------ | ------------ | ------------- | | Pacific Gas and Electric (bundled) | IOU | 5,144 | 17.3% | 347 | 694 | 1,041 | | PG&E Direct Access (aggregated)\* | ESP | 11,393 | 4.1% | 82 | 164 | 245 | | Clean Power San Francisco | CCA | 3,394 | 1.7% | 34 | 68 | 103 | | East Bay Community Energy | CCA | 9,432 | 4.7% | 95 | 190 | 285 | | King City Community Power | CCA | 36 | 0.0% | 0.4 | 1 | 1 | | Marin Clean Energy | CCA | 5,966 | 3.0% | 60 | 120 | 180 | | Central Coast Community Energy | CCA | 5,791 | 2.9% | 58 | 117 | 175 | | Peninsula Clean Energy Authority | CCA | 3,831 | 1.9% | 39 | 77 | 116 | | Pioneer Community Energy | CCA | 1,793 | 0.9% | 18 | 36 | 54 | | Redwood Coast Energy Authority | CCA | 634 | 0.3% | 6 | 13 | 19 | | San Jose Clean Energy | CCA | 4,543 | 2.3% | 46 | 91 | 137 | | Silicon Valley Clean Energy | CCA | 4,132 | 2.1% | 42 | 83 | 125 | | Sonoma Clean Power Authority | CCA | 2,236 | 1.1% | 23 | 45 | 68 | | Valley Clean Energy Alliance | CCA | 724 | 0.4% | 7 | 15 | 22 | | Southern California Edison (bundled) | IOU | 51,858 | 35.8% | 716 | 1,431 | 2,147 | | SCE Direct Access (aggregated)\* | ESP | 12,003 | 4.3% | 86 | 172 | 259 | | Apple Valley Choice Energy | CCA | 250 | 0.1% | 3 | 5 | 8 | | City of Pomona | CCA | 431 | 0.2% | 4 | 9 | 13 | | Clean Power Alliance of Southern California | CCA | 11,166 | 5.6% | 112 | 225 | 337 | | Desert Community Energy | CCA | 369 | 0.2% | 4 | 7 | 11 | | Lancaster Clean Energy | CCA | 618 | 0.3% | 6 | 12 | 19 | | Orange County Power Authority | CCA | 2,275 | 1.1% | 23 | 46 | 69 | | Energy for Palmdale's Independent Choice | CCA | 497 | 0.3% | 5 | 10 | 15 | | Pico Rivera Innovative Municipal Energy | CCA | 218 | 0.1% | 2 | 4 | 7 | | Rancho Mirage Energy Authority | CCA | 286 | 0.1% | 3 | 6 | 9 | | San Jacinto Power | CCA | 172 | 0.1% | 2 | 3 | 5 | | Santa Barbara Clean Energy | CCA | 347 | 0.2% | 3 | 7 | 10 | | San Diego Gas & Electric (bundled) | IOU | 2,658 | 1.8% | 37 | 73 | 110 | | SDG&E Direct Access (aggregated)\* | ESP | 3,942 | 1.4% | 28 | 57 | 85 | | Clean Energy Alliance | CCA | 2,492 | 1.3% | 25 | 50 | 75 | | San Diego Community Power | CCA | 8,340 | 4.2% | 84 | 168 | 252 | | TOTAL | | 176,972 | 100% | 2,000 | 4,000 | 6,000 | **\*Note:** Procurement obligations for electric service providers (ESPs) are presented in aggregate. Individual ESP obligations remain confidential and will be conveyed to each ESP within two weeks of adoption. **INSTANT ANALYSIS:** On resource eligibility, the PD excludes fossil resources, limits repowering to incremental capacity only, and permits energy-only resources solely when co-located with fully deliverable storage. The 50% storage cap is the central policy choice: it constrains over-reliance on storage and indirectly drives additional energy procurement without reopening the Renewables Portfolio Standard or imposing a separate energy mandate. Why the PD matters for CRI readers: it establishes the next reliability obligation after Mid-Term Reliability, shapes procurement behavior through 2032, and feeds directly into the CAISO's transmission approvals with cost-recovery implications. The PD also creates a narrow window for projects to secure remaining federal incentives, increasing near-term procurement pressure even asthe [Reliable and Clean Power Procurement Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/the-reliable-and-clean-power-procurement-program?ref=calregulatory.com) remains under development. ### January 15, 2026 CPUC VOTING MEETING RESULTS: SDG&E Wildfire Costs; POLR Framework; Data Center Transmission Upgrades URL: https://www.calregulatory.com/january-15-2026-cpuc-voting-meeting-results-sdg-e-wildfire-costs-provider-of-last-resort-framework-data-center-transmission-upgrades/ Last updated: 2026-01-15T23:07:34.000Z At its January 15, 2026 voting meeting, the CPUC adopted: - An SDG&E General Rate Case decision that disallows **$206.1 million** in O&M costs and **$242.5 million** in capital expenditures, while approving **$77.9 million** in O&M and **$945.5 million** in capital as reasonable and necessary wildfire mitigation investments; - A procedural framework for how non–investor-owned utilities may seek designation as a Provider of Last Resort under Senate Bill 520; - An SCE ERRA Compliance decision authorizing recovery of **$51.442 million** in undercollected balances across five accounts, mainly driven by Emergency Load Reduction Program costs; - PG&E’s request to facilitate transmission upgrades needed to energize a new 90-MW Microsoft data center in San Jose; - Two Mid-Term Reliability actions affecting PG&E’s energy storage portfolio; - A resolution that rejects **$16.4 million** in requested funding and disallowing **$7.2 million** in cost recovery for PG&E natural gas RD&D expenses incurred in 2023–2024; and - A resolution approving requests of PG&E and SDG&E to establish [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant export tariffs for customer-generation facilities that lose access to [Net Energy Metering or Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) due to prevailing wage violations under the Public Utilities Code. Additionally, the CPUC withdrew a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) that denied a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) program through December 31, 2025\. And the Commission delayed action once again on a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) that denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. This item is now scheduled for consideration on **February 5**. Full meeting results are provided below. ## WILDFIRE MITIGATION/SDG&E RATES This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K094/595094639.pdf?ref=calregulatory.com) addresses SDG&E's General Rate Case Track 2 request to recover wildfire mitigation costs recorded in its Electric and Gas Wildfire Mitigation Plan Memorandum Accounts (WMPMAs) for the 2019–2022 period, above amounts authorized in its Test Year 2019 GRC. SDG&E sought recovery of roughly $284 million in operations and maintenance costs and $1.188 billion in capital expenditures incurred to comply with expanded wildfire mitigation requirements enacted through [Senate Bill 901](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb901?ref=calregulatory.com) and [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com). The decision finds that while many of these investments were required and prudent, a substantial portion of the recorded costs were not reasonable for ratepayer recovery under the CPUC’s standards, particularly where SDG&E failed to sufficiently demonstrate incrementality, cost-effectiveness, or proper allocation between capital and O&M. - The decision disallows **$206.1 million** in O&M costs and **$242.5 million** in capital expenditures, while approving **$77.9 million** in O&M and **$945.5 million** in capital as reasonable and necessary wildfire mitigation investments. Major disallowances include costs for drone inspections, aviation firefighting, PSPS communication practices, data governance tools, and certain inspection and community outreach activities that were either already funded in prior GRC authorizations, insufficiently justified, or misclassified. - The decision defers final authorization of some drone-related costs to Track 3 of the proceeding. After accounting for approved costs and prior interim rate relief, the decision authorizes a net revenue requirement of **$416.6 million** for 2019–2027 and allows SDG&E to amortize the remaining undercollection over three years, resulting in an average residential bill impact of about **$5.09 per month** for non-CARE customers. - [Appendix A](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K094/595094640.pdf?ref=calregulatory.com) provides a detailed cost reduction summary, showing how individual wildfire mitigation initiatives were adjusted. Across capital accounts, approximately $242.5 million is removed, with large reductions tied to drone assessments, centralized data repositories, aviation firefighting, covered conductor programs, and Public Safety Power Shutoff communications, while certain inspection activities were reclassified from capital to O&M. On the O&M side, about **$206.1 million** is disallowed, including significant reductions to drone assessments, fuels management, PSPS communications, vegetation restoration initiatives, and indirect labor and overhead costs. The appendix also documents proportional reductions to indirect costs and consultant expenses, including Ernst & Young review costs, to align recoverable amounts with approved direct expenditures. - [Appendix B](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K180/595180560.pdf?ref=calregulatory.com) presents the authorized Results of Operations model for both electric and gas WMPMAs, translating the approved costs into annual revenue requirements, depreciation, return, taxes, and interest from 2019 through 2027\. The model shows that electric wildfire mitigation costs dominate the overall revenue requirement, while gas-related costs are comparatively small and result in a net overcollection of approximately **$735,000**. Separately, the decision denies SDG&E's request for **$16.9 million** in ongoing capital-related gas costs, finding SDG&E failed to demonstrate their connection to wildfire mitigation or adequately explain its allocation methodology. The appendix also reflects prior interim rate relief of $289.9 million granted in 2024–2025 and shows how the remaining undercollection is carried forward and amortized to support rate stability. "I want to be clear," said Assigned Commissioner **Darcie Houck**, "that the investor-owned utilities submitting applications have the burden of proof to show that the funds requested should be authorized. "They control the information and should be presenting it in a way that's complete, understandable and clear. That said, we also recognize that safety is an absolute top priority, and given that the risk reductions that may be achieved through the use of advanced technologies have the potential to greatly improve safety, we want to encourage appropriate safety measures and fully consider whether the cost of inspections and repairs are just and reasonable." Houck credited SDG&E's wildfire mitigation efforts, noting the utility has not experienced a major wildfire since the 2007 Witch Fire. But she emphasized the CPUC's duty to ensure ratepayer costs remain just and reasonable, citing a recent report finding California's investor-owned utilities spent a combined **$9.2 billion** on wildfire risk reduction in 2023." Ratepayers alone cannot continue to shoulder the burden," she said, calling on utilities, the Commission, and the legislature to find solutions outside the traditional ratesetting box to contain wildfire costs while maintaining safety standards. Commissioner **John Reynolds** echoed the burden-of-proof point, noting that SDG&E failed to demonstrate the reasonableness of its drone program but that the decision appropriately gives the utility a second opportunity in Track 3 given the importance of wildfire safety spending. He encouraged SDG&E to bring key information forward earlier in future proceedings. **INSTANT ANALYSIS:** This decision is a hard cost-discipline marker for wildfire mitigation recovery: it approves much of SDG&E's 2019–2022 wildfire spending but draws clear lines around proof, incrementality, and allocation. Large disallowances (especially for drones, aviation firefighting, PSPS communications, data tools, and overhead/support costs) reflect impatience with broad programmatic claims that lack initiative-level justification. For utilities, the takeaway is direct: future WMPMA recovery will turn on granular cost-benefit showings and clean capital/O&M classification, not portfolio-level narratives. --- ## PROVIDER OF LAST RESORT This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K952/594952727.pdf?ref=calregulatory.com) establishes a procedural framework for how non–investor-owned utilities may seek designation as a Provider of Last Resort (POLR) under Senate Bill 520, while declining to resolve hypothetical policy questions in the absence of a concrete applicant. The decision finds that no non-IOU entities currently intend to assume full POLR responsibilities for all customer classes within a geographic area, and that interest expressed by some parties is conditional and fact-specific. Consequently, the decision adopts a case-by-case application approach rather than a generalized rulemaking. It requires any non-IOU applicant to submit a comprehensive application demonstrating financial, technical, and legal capability; compliance with procurement, reliability, and disconnection rules; and protections against cost shifting. The decision clarifies that POLR obligations may not be divided by customer class, affirms that applications must be jointly filed with the incumbent IOU (without granting the IOU veto power), and requires IOUs to be named as respondents. "I do want to acknowledge," said Commissioner **John Reynolds**, "that every utility has not just the privilege but the obligation to serve customers in its territory." He added: > POLR is a serious responsibility. At present, the electric investor-owned utilities act as Providers of Last Resort — the backstop in case an alternative provider fails financially. For example, [when Western Community Energy went bankrupt](https://westerncommunityenergy.com/press-release-wce-files-for-chapter-9-bankruptcy/?ref=calregulatory.com), Southern California Edison had to take 100,000 customers back and provide them electricity service with only four weeks of notice. Southern California Edison, as the Provider of Last Resort, had to be ready for this type of event. So this is a serious responsibility with serious requirements. > This proceeding earlier established the financial requirements of a Provider of Last Resort and a cost-tracking mechanism if customers return en masse to the incumbent utility. Now this proceeding establishes the next steps for any load-serving entity that wishes to take on the privilege and obligation of serving as a provider of last resort. Reynolds then made a connection between this proceeding and the Power Charge Indifference Adjustment mechanism. "PCIA," he said, "is used by the Commission to fairly allocate costs between customers who receive their generation from an incumbent utility and those who receive it through direct access or through a Community Choice Aggregator. Sometimes PCIA has been maligned, sometimes misconstrued as a tax, but the PCIA is not a tax — it's a payment made to ensure fairness, so that all customers cover the costs for work that our utilities have done on behalf of all electric customers, not just their own customers – like being the Provider of Last Resort." **INSTANT ANALYSIS:** This decision resets the POLR conversation by halting broad policy debates until a real applicant steps forward. Any non-IOU entity considering POLR status now faces a high evidentiary bar: all-customer-class service (though partial geographic territory is permitted); mandatory IOU coordination without IOU veto power; and a bespoke, application-driven review of cost recovery, regulatory authority, and operational readiness. In practice, the ruling leaves IOUs firmly in place as default POLRs while preserving only a narrow, slow, and fact-intensive pathway for future challengers. --- ## SCE ERRA COMPLIANCE This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K913/594913852.pdf?ref=calregulatory.com) approves SCE’s 2022 ERRA compliance application and finds that SCE largely acted prudently and in compliance with Commission rules during the 2022 record year. The decision authorizes recovery of **$51.442 million** in undercollected balances across five accounts, mainly driven by Emergency Load Reduction Program costs, producing an estimated **$0.45 per month increase** for the average residential customer. Two cost items are disallowed: **$56,500** in CAISO sanctions, which cannot be recovered from ratepayers as financial penalties, and **$1.65 million** in double-charged franchise fees to departed customers, which must be refunded through a one-time bill credit. The decision also requires SCE to return **$14,547** in foregone Public Safety Power Shutoff revenues to customers. **INSTANT ANALYSIS**: This decision shows the Commission's continued willingness to approve sizable ERRA undercollections when utilities demonstrate overall procurement compliance, even under 2022 fuel and reliability pressures. At the same time, the decision draws a firm boundary around penalties and administrative errors, confirming that CAISO sanctions and tariff-driven double charges remain shareholder risks, not recoverable from ratepayers. The Commission applied [Public Utilities Code §748.1](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-4/article-2/section-748-1/?ref=calregulatory.com) *sua sponte* (neither party had raised it) to bar recovery of the CAISO penalties. For CRI readers, the takeaway is that ERRA is still a backward-looking reasonableness review, but one where even minor accounting failures can produce disallowances and refunds in an otherwise clean case. --- ## PG&E + DATA CENTERS [Resolution E-5439](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K932/594932206.pdf?ref=calregulatory.com) approves, with modifications, PG&E’s request to facilitate transmission upgrades needed to energize a new 90-MW Microsoft data center in San Jose. The resolution authorizes four agreements covering new 115-kV transmission facilities and substation work, but limits how PG&E can refund Microsoft’s upfront energization costs to protect ratepayers. Rather than applying the standard [Rule 15](https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC%5FRULES%5F15.pdf?ref=calregulatory.com) refund method, the resolution caps annual refunds at 75% of PG&E’s actual net transmission revenues from Microsoft, plus an adjustment for the [Income Tax Component of Contribution](https://www.lawinsider.com/clause/itcc-income-tax-component-of-contribution?ref=calregulatory.com), and extends the refund window from 10 to 15 years. The resolution finds this slower refund structure necessary given the project’s scale, transmission-level connection, and risk of stranded costs if projected load does not materialize, while still allowing Microsoft to recover its full eligible costs over time. PG&E opposed the 75% cap in comments but the resolution rejects all three of the utility's arguments. **INSTANT ANALYSIS:** This resolution establishes a tougher ratepayer-protection template for large, transmission-level data center interconnections ahead of a finalized Rule 30 framework. By capping refunds at 75% of actual net transmission revenues and extending recovery to 15 years, the resolution makes clear that hyperscale loads will not receive fast, front-loaded refunds based only on projected demand. The resolution explicitly disclaims precedential effect, stating that it should not prejudice the ongoing Rule 30 proceeding ([A.24-11-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com)). For CRI readers, the takeaway is this: future data center, AI, and high-load projects in PG&E territory should expect bespoke cost-recovery limits, slower refunds, and closer scrutiny of stranded-cost risk (though the Commission's final approach awaits Rule 30). --- ## PG&E and MID-TERM RELIABILITY The CPUC approved two related Mid-Term Reliability actions affecting PG&E’s storage portfolio. In [Resolution E-5432](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K908/594908500.pdf?ref=calregulatory.com), the Commission authorizes PG&E to execute a third amendment to its existing 300-MW lithium-ion battery contract with [Nighthawk Energy Storage](https://www.nighthawkenergystorage.com/?ref=calregulatory.com), a subsidiary of [Arevon Energy](https://arevonenergy.com/?ref=calregulatory.com). The amendment pushes the project's initial delivery date from June 1, 2025 to **June 1, 2026** and approves a revised contract price. Resolution E-5432 finds the delay and price adjustment reasonable given permitting and interconnection delays, inflation, higher interest rates, and supply-chain pressures. It concludes that approval avoids default risk and higher replacement costs while preserving Mid-Term Reliability compliance. Resolution E-5432 also notes that Nighthawk has now obtained local permits from the City of Poway and San Diego County, secured project financing, and holds a Large Generator Interconnection Agreement with SDG&E, with an expected online date of **March 1, 2026** (ahead of the June 1 contractual deadline). --- With [Resolution E-5437](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K136/594136007.pdf?ref=calregulatory.com), the Commission separately approved PG&E's execution of a new Mid-Term Reliability contract with Balsam Project, LLC, a subsidiary of [Aypa Power Development](https://www.aypa.com/?ref=calregulatory.com), for the 225-MW Dirac Battery Energy Storage System. The eight-hour lithium-ion project will be located in Chino and is expected to come online in **May 2028** and deliver capacity under a 15-year agreement beginning **August 2028**. The resolution finds the contract reasonable, competitively procured, and consistent with prior Mid-Term Reliability decisions, approving cost recovery through PG&E's Portfolio Allocation Balancing Account with [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) eligibility under the 2021 vintage, subject to prudent administration. **INSTANT ANALYSIS:** Together, these approvals show the CPUC balancing schedule risk in near-term Mid-Term Reliability resources with continued build-out of long-lead-time, eight-hour storage. The Nighthawk third amendment reflects regulatory tolerance for delivery slippage when delays are largely outside developer control and replacement risk is higher. The Dirac approval reinforces that competitively procured, eight-hour lithium-ion projects qualify as long-duration storage under a 2025 decision ([D.25-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M569/K671/569671981.PDF?ref=calregulatory.com)) and can clear cost-reasonableness review with confidential pricing and PCIA eligibility. For CRI readers, the combined takeaway is precedent: amended mid-term contracts can survive repeated schedule and price resets, while new eight-hour storage remains a viable compliance pathway for the 2028–2031 window under the Mid-Term Reliability framework. --- ## PG&E and NATURAL GAS RESEARCH [Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M595/K045/595045490.pdf?ref=calregulatory.com) denies PG&E’s proposed Gas RD&D investment plans for 2024 and 2025, rejecting **$16.4 million** in requested funding and disallowing **$7.2 million** in cost recovery for RD&D expenses incurred in 2023–2024. The resolution finds PG&E failed to demonstrate clear ratepayer benefits, relied on insufficient impact analysis, proposed potentially duplicative activities, and did not comply with required administrative cost reporting formats (including failure to use the required template for breaking out the 10% admin budget by category) and planning rules under a 2023 decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)) and [Public Utilities Code §740.1.](https://codes.findlaw.com/ca/public-utilities-code/puc-sect-740-1/?ref=calregulatory.com) PG&E must resubmit revised Tier 3 Advice Letters within 60 days and comply with revised consultation, reporting, and coordination requirements before any Gas RD&D funding can be approved. **INSTANT ANALYSIS:** The Commission is drawing a firm line that gas RD&D funding must show a direct, defensible ratepayer benefit, rather than rely on broad decarbonization objectives or compliance-related work. The resolution raises the approval bar for gas RD&D statewide and puts hydrogen and methane research under closer review unless utilities clearly distinguish RD&D from mandated or overlapping programs. The resolution also signals that Energy Division may develop formal strategic goals for gas RD&D modeled on the [Electric Program Investment Charge](https://www.energy.ca.gov/programs-and-topics/programs/electric-program-investment-charge-epic-program?ref=calregulatory.com) program, which would institutionalize this tighter framework across all gas administrators. --- ## PURPA [Resolution E-5425](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K021/594021941.pdf?ref=calregulatory.com) approves requests of PG&E and SDG&E to establish [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant export tariffs for customer-generation facilities that lose access to [Net Energy Metering or Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/net-energy-metering-and-net-billing?ref=calregulatory.com) due to prevailing wage violations under the Public Utilities Code. The resolution clarifies that these facilities may continue exporting energy under a PURPA tariff priced pursuant to a 2020 decision ([D.20-05-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M337/K709/337709639.PDF?ref=calregulatory.com)). However, the resolution adopts an explicit capacity cap of 20 MW per generating facility. This cap aligns with federal PURPA must-take obligations as implemented by FERC and matches the D.20-05-006 pricing structure, which was designed for facilities of 20 MW or less. While a 2023 decision ([D.23-11-068](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K977/520977266.PDF?ref=calregulatory.com)) did not originally impose a size limit, Resolution E-5425 concludes that adding a 20 MW cap avoids confusion, reduces legal risk, and maintains consistency with the federal must-take obligation. PG&E and SDG&E are directed to refile their tariffs reflecting this limitation, and SCE is required to update its previously approved PURPA tariff to match, ensuring uniform treatment across all large electric IOUs. **INSTANT ANALYSIS:** Resolution E-5425 reshapes the off-ramp for NEM and NBT customers that lose tariff eligibility due to prevailing wage violations by formally capping the fallback PURPA export tariff at 20 MW per facility. While framed as a clarification, the decision matters because it closes an ambiguity left open in D.23-11-068 and aligns California’s wage-enforcement framework with federal PURPA must-take limits and Rule 21 classifications. The practical effect is to limit how large customer-sited projects can remain economically viable after a wage violation, while also standardizing treatment across PG&E, SDG&E, and SCE. For developers and large behind-the-meter customers, the ruling reinforces that wage compliance failures now carry not just tariff consequences, but hard capacity ceilings that cannot be bypassed through interconnection or export pathways. --- ## UTILITY SITE ACCESS This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K929/594929112.pdf?ref=calregulatory.com) allows SCE to outsource and monetize telecommunications site access on utility property under [General Order 69-C](https://www.cpuc.ca.gov/industries-and-topics/internet-and-phone/carrier-reporting-requirements/go-69-c-staff-data-request?ref=calregulatory.com) without filing a formal [Section 851](https://law.justia.com/codes/california/code-puc/division-1/part-1/chapter-4/article-6/section-851/?ref=calregulatory.com) application. The decision finds the arrangement remains a limited, revocable use that does not interfere with utility operations, but conditions approval on Commission acceptance of a Tier 3 Advice Letter identifying the buyer and demonstrating its qualifications, conflicts, and market-power safeguards. The decision also imposes five-year true-up requirements to ensure the lump-sum payment is properly allocated between active (tower) and passive (ground) revenue under the Gross Revenue Sharing Mechanism. The decision also requires shareholders to make ratepayers whole if Non-Tariffed Products & Services revenue falls below the **$16.67 million** threshold. **INSTANT ANALYSIS:** The decision confirms that SCE may outsource and monetize secondary uses of utility property under General Order 69-C (including third-party assignment and lump-sum payments) without a formal Section 851 application. Approval is conditioned on vetting the buyer through a Tier 3 Advice Letter, along with revocability, compliance oversight, and ratepayer protections. The decision references a similar PG&E transaction and directs staff to evaluate whether General Order 69-C should be updated, which suggests this framework may have broader applicability. ## OTHER ITEMS - **CRUDE OIL TRANSPORTATION**: [Resolution O-0100](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K523/594523250.pdf?ref=calregulatory.com) authorizes San Pablo Bay Pipeline Company, LLC to recover **$894,683** in retroactive charges for under-collected crude oil transportation rates from March 1, 2023 through February 28, 2024, consistent with a 2025 Decision ([D.25-06-044](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K971/571971447.PDF?ref=calregulatory.com)). The resolution reduces the requested amount by $8,243 by adopting a revised interest calculation methodology proposed by shippers. The resolution leaves disputes over interim rates to pending rate proceedings [A.24-01-016](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M524/K040/524040462.PDF?ref=calregulatory.com) and [A.25-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M555/K961/555961198.PDF?ref=calregulatory.com). - **ENERGY EFFICIENCY:** [Resolution E-5442](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K550/594550778.pdf?ref=calregulatory.com) certifies Peninsula Clean Energy Authority's request to renew and administer its Energy Efficiency [FLEXmarket program](https://www.peninsulacleanenergy.com/business/rebates-offers-business/flexmarket-program/?ref=calregulatory.com) for a new three-year term, from August 1, 2025 through **July 31, 2028**, under the "elect to administer" pathway. The resolution approves a total budget of **$2.97 million**, funded through PG&E non-bypassable EE charges, and requires Peninsula Clean Energy to meet cost-effectiveness thresholds (a pointed requirement given that the program's Total Resource Cost fell to 0.09 in 2024) and coordinate with PG&E and [BayREN](https://www.bayren.org/?ref=calregulatory.com) to avoid customer confusion. - **HYDRO SALE**: The CPUC approved SCE's application to sell the Lytle Creek and Fontana hydroelectric plants (3.45 MW combined) to Fontana Union Water Company, finding the sale in the public interest and categorically exempt from CEQA. The decision authorizes recovery of an estimated **$9.5 million** pre-tax loss through existing balancing accounts and Power Charge Indifference Adjustment rates, and requires post-closing Tier 1 advice letters with final loss and tax calculations. - **SDG&E HOUSEKEEPING:** [Resolution E-5405](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K543/594543939.pdf?ref=calregulatory.com) approves SDG&E’s request to recover non-officer compensation costs tied to the company's Vice President, People and Culture role, but reduces the request to **$282,983** in O&M expenses for Test Year 2024 after cutting employee food service costs and disallowing professional membership expenses. The approved amounts result in a **$265,000** revenue requirement for 2024 and **$1.1 million** for the 2024–2027 General Rate Case cycle, with minimal rate impacts. ### WEDNESDAY AGGREGATE: SoCalGas AMI Cost Tracking; SCE Low-Income Budgets; a Challenge to Undergrounding Resolution SPD-37 URL: https://www.calregulatory.com/january-14-2026-cpuc-briefing-socalgas-ami-cost-tracking-sce-low-income-program-budgets-a-challenge-to-the-cpucs-undergrounding-resolution-spd-37/ Last updated: 2026-01-15T02:28:40.000Z Today's aggregate includes: - Activity involving SoCalGas's AMI replacement application; - SCE's application for CARE, ESA, and FERA budgets for the 2028–2033 cycle; - An application for rehearing of [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com), which revised the CPUC’s [Senate Bill 884 undergrounding framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com); - SoCalGas's [2025 Q4 Safety Culture Improvement Plan Quarterly Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K415/594415459.PDF?ref=calregulatory.com); and - A request asking to transfer indirect control of the Wild Goose and Lodi gas storage facilities from Brookfield to Rockpoint Gas Storage Inc., a publicly traded company created through an October 2025 initial public offering. --- ### Natural Gas Advanced Metering Infrastructure SoCalGas filed [a motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K293/594293848.PDF?ref=calregulatory.com) asking the CPUC to authorize an interest-bearing Advanced Meter Infrastructure Replacement Memorandum Account to track costs incurred while the Commission reviews its [AMI replacement application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K231/593231269.PDF?ref=calregulatory.com) (*see our summary of the application* [*here*](https://www.calregulatory.com/wednesday-aggregate-6/)). [New SoCalGas AMI ApplicationAs we head into 2026, a request: if you or your team find this work useful, please consider becoming a paid CRI subscriber.![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1--1.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-22-2025--3-.png)](https://www.calregulatory.com/wednesday-aggregate-6/) - SoCalGas argues its existing AMI system, deployed between 2012 and 2018, is approaching end-of-life, with module battery failures expected around 2030 and manufacturer support winding down, creating operational, billing, and cybersecurity risks if replacement work is delayed. - SoCalGas says it must begin vendor selection and system pre-planning during the pendency of the case and seeks to record about **$4 million** in incremental costs effective December 30, 2025, the application filing date, with recovery subject to a later reasonableness review. - SoCalGas cites Commission precedent approving similar memorandum accounts for PG&E and SDG&E AMI and billing modernization projects and emphasizes that the request does not prejudge cost recovery, but preserves neutrality for ratepayers and shareholders while the application is under review. **INSTANT ANALYSIS:** This is a standard but consequential interim cost-protection move. SoCalGas is laying down a marker to begin AMI replacement work now, rather than wait for a final decision, by securing a memorandum account effective as of the application filing date. The Commission has consistently approved similar requests for PG&E and SDG&E when large, time-sensitive system replacements risk higher costs or operational failure if delayed, which strengthens SoCalGas’s position. The true battles are deferred: authorization of the memo account does not guarantee recovery, but it meaningfully reduces SoCalGas’s exposure and increases the likelihood that early AMI replacement costs will be treated as reasonable once the merits of the broader application are decided. --- ### Low-Income Subsidies SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K291/594291722.PDF?ref=calregulatory.com) seeking CPUC approval of its Energy Savings Assistance, California Alternate Rates for Energy, and Family Electric Rate Assistance programs and budgets for the 2028–2033 cycle. The application requests **$781.8 million** in total cost recovery, including $674.5 million for ESA delivery and $107.3 million for CARE and FERA administration. SCE proposes to serve nearly 387,000 homes, targeting 195.4 GWh in cycle savings versus 131.5 GWh in the prior cycle, maintain a 92% CARE participation rate, and increase FERA participation to 30% by 2033\. The proposal folds building electrification and expanded HVAC offerings into the ESA program while closing the Southern Multifamily Whole Building program and transitioning that delivery to ESA as well. SCE estimates the request would increase system average rates by about **0.12%**, or $0.14–$0.22 per month for a typical residential customer. Cost recovery would continue through existing balancing account mechanisms. (*We summarized PG&E's equivalent filing* [*here*](https://www.calregulatory.com/friday-aggregate-pg-e-natural-gas-rates-rule-30-diablo-canyon/)*.*) [PG&E Natural Gas Rates; Rule 30; Diablo CanyonPG&E’s 2027 Gas CARD application drew immediate, broad-based resistance from consumer advocates, generators, and large customers![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1--2.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/IMG_5373.JPG)](https://www.calregulatory.com/friday-aggregate-pg-e-natural-gas-rates-rule-30-diablo-canyon/) **INSTANT ANALYSIS:** This application sets the baseline for the 2028–2033 income-qualified program cycle and will likely be absorbed into a consolidated IOU proceeding. Nearly **$0.8 billion** is proposed for ESA, CARE, and FERA, with modest systemwide rate impacts. The main move is consolidating electrification and expanded HVAC measures into ESA while winding down pilots and regional programs, even as cost-effectiveness falls below Commission targets. SCE emphasizes affordability, arguing that higher administrative spending and upfront eligibility checks will reduce subsidy leakage over time, a claim intervenors are likely to scrutinize closely. --- ### Undergrounding Cal Advocates, TURN, and the Mussey Grade Road Alliance filed a joint [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K402/594402099.PDF?ref=calregulatory.com) challenging [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com), which revised the CPUC’s [Senate Bill 884 undergrounding framework](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com). The parties argue the Commission committed legal error by creating an expedited “Phase 1 Application” process without defining party status, shortening response timelines to 15 days, and eliminating meaningful discovery and hearings. They contend these procedural defects violate the CPUC’s own rules and deny due process in decisions that will shape future undergrounding cost recovery. For context, see our summary of Resolution SPD-37 [here](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/). [December 4, 2025 CPUC Voting Meeting ResultsThe CPUC’s meeting included attempts to impose methodological discipline on billion-dollar capital programs![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1--3.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Mon-Dec-08-2025--12-.png)](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/) **INSTANT ANALYSIS:** This application is about procedural control rather than undergrounding policy itself. The joint parties are pushing back on the CPUC’s use of a resolution to impose an accelerated, quasi-adjudicatory process that could shape billions in future cost recovery without formal party status, discovery, or hearings. If granted, rehearing would slow SB 884 implementation but reinforce firm limits on how far the Commission can go in setting cost, audit, and oversight rules outside a standard application proceeding. --- ### SoCalGas's Safety Culture SoCalGas filed its[ 2025 Q4 Safety Culture Improvement Plan Quarterly Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K415/594415459.PDF?ref=calregulatory.com) in [I.19-06-014](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M306/K870/306870841.PDF?ref=calregulatory.com), detailing progress on implementing its revised safety culture framework approved in a 2023 decision ([D.23-12-034](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M521/K824/521824854.PDF?ref=calregulatory.com)). The report describes companywide efforts during October–December 2025 to embed safety as a shared value rather than a narrow compliance function, structured around four plan elements. Key activities included executive and director safety culture coaching (68 leaders total), expanded leadership field engagement through 87 “Live-a-Day” visits, rollout of enhanced supervisor onboarding and leadership training programs, pilot implementation of structured Tailgate Safety Briefings, and near-completion of a new Safety Manual for Employees shaped through frontline co-creation. SoCalGas also advanced governance changes to its Safety Management System (SMS), completed an SMS Policy (August 2025) and SMS Manual (December 2025), and began integrating revised plan actions into ongoing Plan-Do-Check-Act review cycles. The filing reports **$5.9 million** in cumulative program costs to date, outlines lessons learned and implementation challenges, and identifies planned refinements and additional activities for 2026, including expanded learning teams, clearer metrics, and deeper employee feedback mechanisms to support sustained cultural change. **INSTANT ANALYSIS:** SoCalGas is demonstrating procedural compliance with D.23-12-034 by documenting steady implementation of its revised Safety Culture Improvement Plan using a Plan-Do-Check-Act framework, with heavy emphasis on leadership training, internal communications, and Safety Management System governance rather than operational rule changes. The report reads as a maturity and accountability exercise aimed at the Safety Policy Division (showing activity, metrics, and feedback loops) while deferring any substantive safety outcome evidence to future quarters. --- ### Natural Gas Storage Brookfield Infrastructure Fund GP II, Rockpoint Gas Storage Inc., Wild Goose Storage, LLC, and Lodi Gas Storage, L.L.C. filed a[ joint application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K365/594365127.PDF?ref=calregulatory.com) under Public Utilities Code §854. - The request asks to transfer indirect control of the Wild Goose and Lodi gas storage facilities from Brookfield to Rockpoint Gas Storage Inc., a publicly traded company created through an October 2025 initial public offering. Rockpoint Gas Storage Inc. already holds a 40% interest in the operating companies through that IPO; this application seeks authorization for Rockpoint Gas Storage Inc. to acquire Brookfield's remaining 60% interest, with the change of control occurring when RGSI crosses 50%. - The end state would be widely held public ownership, with no single controlling shareholder. A 12-month standstill from the October 15, 2025 IPO means the earliest transaction date would be October 15, 2026, aligned with the applicants' proposed September 2026 decision timeline. - The applicants state the transaction will not change operations, management, staffing, tariffs, or safety practices. Rockpoint would continue day-to-day oversight, and all existing CPCN conditions and CPUC jurisdiction would remain in place. They argue the transaction is not adverse to the public interest because it preserves reliability and competition while improving transparency and access to capital. - The filing explicitly states that [A.25-12-004](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K511/590511213.PDF?ref=calregulatory.com) (the pending revolving credit facility refinancing application involving Wild Goose and Lodi asset pledges) is "not interrelated" and "should not be consolidated" with this proceeding. [Natural Gas Storage UpdateWild Goose Storage/Lodi Gas Storage filed an application seeking exemptions from the Public Utilities Code![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/icon/Electromagnetic_radiation-1-.png)CALIFORNIA REGULATORY INTELLIGENCE (CRI)MC![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/thumbnail/iterograph_Fri-Dec-12-2025--1-.png)](https://www.calregulatory.com/natural-gas-storage-update/) **INSTANT ANALYSIS:** While presented as a governance and capital markets transaction, this application directly implicates system-critical storage assets that support Northern California reliability during peak conditions. The applicants emphasize no change to operations, management, safety practices, tariffs, or CPUC oversight, which will frame the Commission's review and future enforcement posture. For CRI readers, this matters because §854 approvals often become durable precedent for how gas storage ownership, financing, and control can evolve as California navigates long-term gas planning, reliability risk, and capital access constraints. ### NEWS CODEX: Hydrogen; Solar Recycling; Biomass URL: https://www.calregulatory.com/news-codex-hydrogen-solar-recycling-biomass/ Last updated: 2026-01-13T21:58:46.000Z - **California Should Stop Forcing Drivers to Subsidize Deforestation:** "California spent the past year congratulating itself for raising the ambition of its Low Carbon Fuel Standard, the state’s flagship program to cut greenhouse gas emissions from transportation. In June 2025, the California Air Resources Board approved sweeping amendments that accelerate carbon-intensity reductions across gasoline and diesel. The LCFS now aims to cut transportation fuel emissions far more quickly than ever before, reaching a 30% reduction by 2030 and 90% reduction by 2045\. Without further reforms, much of this decarbonization will exist only on paper." [**ECOMODERNIST**](https://www.breakthroughjournal.org/p/california-should-stop-forcing-drivers?ref=calregulatory.com) - **California Wants to Mix Hydrogen with Gas to Cut Climate Pollution:** "The Southern California Gas Co. wants to blend and inject hydrogen into the town's gas infrastructure, after the state agency that regulates utilities directed them and other companies to launch pilot projects. Proponents see it as key to helping California reduce planet-warming pollution by curbing reliance on gas while integrating cleaner energy into existing infrastructure. It's part of a statewide effort to create safety rules for hydrogen blending." [**DESIGN & DEVELOPMENT TODAY**](https://www.designdevelopmenttoday.com/industries/energy/news/22958185/california-wants-to-mix-hydrogen-with-gas-to-cut-climate-pollution?ref=calregulatory.com) - **Comstock Metals Expands Solar Recycling Network with New California Center:** "By establishing the hub in the heart of California, the largest solar market in the U.S., Comstock aims to streamline logistics and reduce the environmental impact of transporting decommissioned infrastructure. This development is intended to address a looming waste problem that Comstock chief executive officer **Corrado De Gasperis** forecasts will soon be measured in the hundreds of millions of panels." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/12/comstock-metals-expands-solar-recycling-network-with-new-california-center/?ref=calregulatory.com) - **Does California Want To Be Part Of The Nuclear Renaissance?:** "If natural gas is banned, then nuclear will have to make up the shortage. It can take [10 to 12 years](https://nam10.safelinks.protection.outlook.com/?url=http%3A%2F%2Flarge.stanford.edu%2Fcourses%2F2017%2Fph241%2Fpark-k2%2F&data=05%7C02%7Ctanaya%40pacificresearch.org%7C59115547904c44000f6008de3c47e0d4%7C56c2f5bedd274fdaa829995353b3b27a%7C0%7C0%7C639014476769872783%7CUnknown%7CTWFpbGZsb3d8eyJFbXB0eU1hcGkiOnRydWUsIlYiOiIwLjAuMDAwMCIsIlAiOiJXaW4zMiIsIkFOIjoiTWFpbCIsIldUIjoyfQ%3D%3D%7C0%7C%7C%7C&sdata=soyzdRi8n7eWv81q%2F9PKQAafCi4%2FzyMrfD6OGMiMRT8%3D&reserved=0&ref=calregulatory.com) to add new nuclear capacity, from the planning and licensing phase to completion of construction. We should add a few years, this being California, where all construction projects become slogs. " [**ISSUES & INSIGHTS**](https://issuesinsights.com/2026/01/08/does-california-want-to-be-part-of-the-nuclear-renaissance/?ref=calregulatory.com) - **Enpower Sells Wadham Energy Biomass Facility to High Rock Energy Group:** "Enpower Corp., a California-based independent power producer, has sold its wholly owned subsidiary Wadham Energy Limited Partnership to High Rock Energy Group. The sale transfers a 27 MW rice husk biomass facility in Colusa County, California, which has operated for over 30 years providing baseload renewable power to the state's electricity grid." [**BIOENERGY INSIGHT**](https://www.bioenergy-news.com/news/enpower-sells-wadham-energy-biomass-facility-to-high-rock-energy-group/?ref=calregulatory.com) - **The Trump vs. Newsom Energy Showdown is Just Getting Started:** "**Jon Wellinghoff**, who served on the Federal Energy Regulatory Commission under presidents **George W. Bush** and **Barack Obama**, said in an interview that the antagonism between the California and federal governments jacks up the risk on private energy companies interested in investing in the state, especially in the renewable sector. 'They’re going to look at a need for a higher risk premium to ultimately invest in those types of projects when you have this conflict going on between state and federal interests,' Wellinghoff said. 'Obviously we can get a lot less done and it’s a lot less efficient if the two governments are working against each other as opposed to working for each other.'" [**POLITICO**](https://www.politico.com/news/2026/01/13/trump-newsom-california-energy-policies-00723860?ref=calregulatory.com) - **Trump Administration Sues Petaluma and Morgan Hill Over Natural Gas Bans:** "The Trump administration contends that these cities cannot adopt local rules that effectively eliminate the use of natural gas-powered appliances by banning the infrastructure that supports them. In its complaint, the Department of Justice describes Petaluma and Morgan Hill’s restrictions as not only unlawful but also burdensome to residents, arguing they 'deny consumers reliable, resilient, and affordable energy' and undermine broader national energy interests." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/trump-administration-sues-petaluma?ref=calregulatory.com) - **Unlocking Industrial Electrification in California:** "...there exists significant opportunity in California to electrify many industrial heating processes while also providing major benefits to the grid. The flexibility of some types of industrial load, if met with appropriate rates and other supportive policies, can benefit the grid by flattening demand. And utilities can sweeten the financial deal for industrial customers who electrify by rewarding those that do so with flexible demand with low off-peak rates. In sum, intelligent rate design for industrial electrification and load-shifting can financially incentivize customers to switch from fossil fuel heating while also providing grid benefits to grid operators like the ability to mitigate and control system costs, which drives down electric rates for all customer classes (industrial, commercial, and residential)." [**INDUSTRIOUS LABS**](http://cdn.sanity.io/files/xdjws328/production/a8a65d164df0ec0f428b370af398cb90237b8c29.pdf?ref=calregulatory.com) - **Why California is Keeping This Unusual Solar Plant Running When Both Trump and Biden Wanted it Closed:** "NRG spokesperson **Erik Linden** said Ivanpah's ownership has continued to invest in the facility and 'remains steadfast in its commitment to providing reliable renewable energy to the state of California.' The existing power purchase agreements remain in effect and the plant will operate under their terms for the duration of the agreements, he said." [**TECH XPLORE**](https://techxplore.com/news/2026-01-california-unusual-solar-trump-biden.html?ref=calregulatory.com) ### MONDAY AGGREGATE: Sempra Utilities' Cost of Capital Updates; SoCalGas Microgrid Optional Tariff; SDG&E Wildfire Costs URL: https://www.calregulatory.com/sempra-utilities-submit-cost-of-capital-mechanism-advice-letter-updates/ Last updated: 2026-01-15T02:27:07.000Z Today's aggregate includes: - The Sempra Utilities' updated Cost of Capital Mechanism advice-letter filings; - An ex parte communication involving SoCalGas's Microgrid Optional Tariff; - An ex parte communication involving the CPUC's General Rate Case Track 2 review of SDG&E’s wildfire mitigation costs from 2019–2022; - SoCalGas's energy-efficiency Independent Evaluator report assessing third-party EE solicitation activities; and - Another challenge to the CPUC's December 2025 Diablo Canyon cost-recovery decision. ### Cost of Capital SoCalGas and SDG&E both filed advice letters to update their Cost of Capital Mechanisms to conform to the CPUC’s Test Year 2026 Cost of Capital decision, [D.25-12-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K833/591833054.PDF?ref=calregulatory.com). Recall that D.25-12-043 adopted new capital cost parameters effective January 1, 2026 through December 31, 2028 and directed utilities to continue applying the CCM during the 2026 cycle. (*See our summary of the Cost of Capital decision* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)*; excerpts from the commissioners' D.25-12-043 discussion are available* [*here*](https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-commissioner-remarks-on-cost-of-capital-decision/)*.*) SoCalGas’s AL 6590-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) resets its CCM benchmark to **5.747%**, based on the October 2024-September 2025 average of the Moody’s A-rated utility bond index. No changes are proposed to the CCM structure, trigger, or adjustment formula. SDG&E’s AL 4787-E and AL 3489-G (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) make parallel updates to reference D.25-12-043 and reset the CCM benchmark to **5.937%**, reflecting the same period average of the Moody’s Baa-rated utility bond index. Protests to all three filings are due February 2. **INSTANT ANALYSIS**: These advice letters implement the mechanical follow-on from the CPUC's 2026 Cost of Capital decision and do not reopen Cost of Capital policy. The only practical change is the reset of CCM benchmarks to reflect recent Moody’s bond averages by utility credit rating. Unless bond spreads move enough to breach the CCM deadband, these filings are unlikely to produce near-term rate impacts or draw dispute. --- ### Microgrids SoCalGas recently conducted ex parte communications with advisors to Commissioners **John Reynolds** and **Matt Baker** regarding SoCalGas’s pending [A.25-04-006](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M564/K309/564309571.PDF?ref=calregulatory.com) for a Microgrid Optional Tariff (MOT), alongside a [presentation ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K293/594293823.PDF?ref=calregulatory.com)detailing the proposal. SoCalGas characterized the MOT as a voluntary, behind-the-meter microgrid service for non-residential customers that would be fully shareholder-funded, with all project costs recovered solely from participating customers and no subsidies or risk borne by other ratepayers. SoCalGas pointed to its [Hydrogen Innovation Experience ](https://www.socalgas.com/sustainability/hydrogen/h2home?ref=calregulatory.com#:~:text=Our%20%5BH2%5D%20Innovation%20Experience%20is,and%20communities%20of%20the%20future.)(H2IE) microgrid demonstration (featuring solar, battery storage, an electrolyzer, a fuel cell, and hydrogen storage in an integrated configuration) as evidence of its operational capability to deliver the service. SoCalGas emphasized that the tariff: - Is technology- and fuel-agnostic; - Supports grid reliability, new load energization, resilience, and affordability; and - Aligns with state policy under [Senate Bill 1339](https://www.cpuc.ca.gov/resiliencyandmicrogrids?ref=calregulatory.com) by reducing barriers to microgrid deployment while maintaining Commission oversight. SoCalGas argued that a tariffed approach is preferable to creating an affiliate, citing prior CPUC precedent approving similar shareholder-funded tariffs. In particular, SoCalGas referenced a 2012 decision ([D.12-12-037](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M040/K653/40653068.PDF?ref=calregulatory.com)), in which the CPUC found that SoCalGas did not have a competitive advantage from customer relationships or access to customer data. Additionally, SoCalGas asserted that competitive neutrality safeguards (e.g., neutral marketing, no bill inserts, no tying of services, disclosure of alternative providers, and use of previously approved ratemaking methodologies) address market power concerns. The materials also pointed to balancing accounts, tracking of embedded costs, and credit requirements as ratepayer protections, and highlighted broad stakeholder support from local governments, educational institutions, industrial customers, and technology providers as evidence that approval of the MOT would be reasonable and in the public interest. **INSTANT ANALYSIS:** SoCalGas is urging the CPUC to treat the Microgrid Optional Tariff as a direct extension of previously approved shareholder-funded service models, not a new category of utility expansion. The ex parte communication focuses on two main points: that all costs and risks remain with participating customers, and that the tariff offers a near-term way to support load growth, reliability, and resilience without creating an affiliate structure. The proceeding's outcome is likely to turn on whether the Commission is satisfied that the proposed safeguards and cost-tracking measures are sufficient to address market power and cross-subsidy concerns under existing policy and precedent. --- ### SDG&E Ex Parte Communication In early January 2026, SoCalGas/SDG&E [met with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K276/594276825.PDF?ref=calregulatory.com) staff from **Commissioner John Reynolds**’ and **Commissioner Darcie Houck**’s offices to discuss a pending [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) involving a General Rate Case Track 2 review of SDG&E’s wildfire mitigation costs from 2019–2022\. (*The PD is set for consideration at the CPUC's *January 15* voting meeting; see our preview* [*here*](https://www.calregulatory.com/cpuc-january-15-2026-voting-meeting-preview-sdg-e-grc-wildfire-costs-non-provider-of-last-resort/).) SDG&E focused on what it views as an improper and overly stringent standard of review applied to cost recovery, arguing that the PD departs from established CPUC reasonableness review practice despite a detailed evidentiary record. The utility drew a direct comparison to SCE's wildfire cost recovery proceeding ([A.22-06-003](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M482/K391/482391364.PDF?ref=calregulatory.com)), where a 2024 decision ([D.24-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M527/K298/527298607.PDF?ref=calregulatory.com)) approved nearly all of SCE's request using a "portfolio approach" to determine incrementality, arguing that SDG&E's evidentiary showing meets or exceeds what SCE provided. SDG&E walked commissioners' staff through areas where it believes the PD made factual or analytical errors, including disallowances tied to: - The Drone Investigation Assessment and Repair program; - Stakeholder cooperation and Public Safety Power Shutoff communications costs; - Data governance expenses; and - Fuels management costs, which SDG&E notes were uncontested by parties but nonetheless denied in the PD based on what the utility argues is a flawed unit cost comparison. SDG&E maintained that these activities were approved through prior Wildfire Mitigation Plans, were required to comply with CPUC and Energy Safety mandates, and were supported by extensive discovery responses, workpapers, and testimony already in the record. The discussion was framed as an effort to correct misunderstandings in the PD and to clarify how the documented costs align with Commission-approved programs and statutory obligations. **INSTANT ANALYSIS:** This ex parte communication focuses on whether the PD departs from the Commission’s established reasonableness review for wildfire cost recovery and instead applies a more demanding, hindsight-based test. SDG&E is positioning the record to show that the PD misreads prior precedent, overlooks evidence already produced in discovery and testimony, and disallows costs tied to programs the CPUC and Energy Safety required the utility to implement. If the Commission accepts that perspective, revisions could narrow or reverse key disallowances; if not, the issue is preserved for a potential application for rehearing or petition for modification. --- ### Energy Efficiency SoCalGas filed its [semi-annual Independent Evaluator report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K414/594414323.PDF?ref=calregulatory.com) in the CPUC’s new Energy Efficiency oversight rulemaking ([R.25-04-010](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M564/K857/564857040.PDF?ref=calregulatory.com)), assessing the company's third-party EE solicitation activities from April through September 2025\. (*We summarized SCE's equivalent filing* [*here*](https://www.calregulatory.com/wednesday-aggregate-6/)*.*) The Independent Evaluators find that SoCalGas largely followed fair, transparent, and well-structured solicitation processes. The utility incorporated prior CPUC and Procurement Review Group guidance, including greater reliance on Total System Benefits, [Normalized Metered Energy Consumption](https://veregy.com/an-introduction-to-normalized-metered-energy-consumption-nmec/?ref=calregulatory.com)\-based savings measurement, and pay-for-performance compensation models. The report credits SoCalGas with improving bidder communications, scoring calibration, and individualized debriefings. Evaluators also note earlier independent evaluator involvement in implementation plan review and clearer internal documentation. At the same time, the report identifies persistent weaknesses. These include: - Long delays between proposal selection and contract execution; - Internal approval bottlenecks; and - Ongoing bidder confusion around evaluation criteria and program scope. Stakeholder feedback from CPUC workshops generally supports the direction of the program. Participants praised innovation pathways like IDEEA 365 (SoCalGas’s year-round, rolling energy efficiency solicitation) but raised concerns about risk allocation, cross-IOU consistency, and tension between cost-effectiveness metrics and Total System Benefits. Since 2018, SoCalGas has executed **$302.3 million** in third-party EE contracts, with 27.91% allocated to Diverse Business Enterprises (though workshop participants noted that financial and insurance requirements continue to disadvantage smaller firms). **INSTANT ANALYSIS**: This filing shows SoCalGas continuing to professionalize its third-party EE procurement, with clearer processes and stronger evaluator oversight, but without meaningful gains in speed. Normalized Metered Energy Consumption and pay-for-performance are now firmly embedded, aligning with CPUC direction while shifting more performance risk onto implementers. IDEEA 365 remains the most credible innovation pathway, lowering entry barriers and keeping a live pipeline of new concepts. The persistent weakness is execution rather than policy, as contracting and internal approvals continue to slow delivery. The takeaway for stakeholders is stability, not acceleration: the framework is maturing, but pace remains the binding constraint. --- ### Diablo Canyon Last week [we reported](https://www.calregulatory.com/friday-aggregate-pg-e-natural-gas-rates-rule-30-diablo-canyon/) on a January 8 [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K291/594291662.PDF?ref=calregulatory.com) filed by Californians for Renewable Energy (CARE) that challenged the CPUC’s December 2025 decision approving PG&E’s 2026 cost recovery for extended operation of the Diablo Canyon Power Plant ([D.25-12-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K401/590401896.PDF?ref=calregulatory.com)). Separately, another group, San Luis Obispo Mothers for Peace (Mothers for Peace), also filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K231/593231114.PDF?ref=calregulatory.com) of D.25-12-007. Mothers for Peace argue that the Commission committed legal error by excluding core, material issues (prudency, cost-effectiveness, and the ongoing need for Diablo Canyon) from the scope of the proceeding, in violation of Public Utilities Code §§ 1705 and 451\. Mothers for Peace contend that before authorizing cost recovery, the Commission is legally required to apply the prudent manager standard and make explicit findings supported by the record, which D.25-12-007 failed to do. The application further argues that the Commission’s interpretation of [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com) unlawfully narrows its statutory obligations, effectively repealing by implication long-standing duties to evaluate whether extended plant operations remain prudent, cost-effective, and necessary for reliability. Mothers for Peace maintain that SB 846 expressly contemplates continuous review of these factors and allows termination of extended operations if they are found imprudent or uneconomic. The filing requests rehearing and oral argument, asserting that the issues raise questions of major legal and public importance because the decision departs from Commission precedent and weakens statutory protections for ratepayers against unjust and unreasonable costs. **INSTANT ANALYSIS:** Compared to CARE’s rehearing application, which argues that D.25-12-007 misapplies SB 846 by allowing barred pre-extension O&M costs and misusing Volumetric Performance Fees, San Luis Obispo Mothers for Peace challenges the decision at a more foundational level. Mothers for Peace argue the CPUC approved PG&E’s 2026 cost recovery without making required findings on prudency, cost-effectiveness, or continued need for Diablo Canyon under the Public Utilities Code, effectively excluding those issues from scope. Taken together, CARE alleges the Commission reached the wrong results under the statute, while Mothers for Peace argues the Commission skipped mandatory analysis altogether, leaving the decision exposed both substantively and procedurally, and increasing the risk of modification if rehearing is granted. ### FRIDAY AGGREGATE: PG&E's CARD Filing; Rule 30; Rate Design URL: https://www.calregulatory.com/friday-aggregate-pg-e-natural-gas-rates-rule-30-diablo-canyon/ Last updated: 2026-01-15T16:20:24.000Z PG&E dominates today's roundup. The utility's 2027 Gas CARD application drew immediate, broad-based resistance from consumer advocates, generators, and large customers, not regarding rates but over the structure of the proceeding itself. Meanwhile, an ALJ reopened the record on Rule 30 transmission-level service, reflecting CPUC discomfort with finalizing large-load cost allocation without better evidence on cost causation. Elsewhere: a schedule is provided for the dynamic pricing track of PG&E's GRC Phase 2, Cal Advocates' distribution upgrade cost study enters the DER record, SoCalGas files for approval of interstate capacity contracts, and a group challenges the CPUC's December 2025 decision in the Diablo Canyon cost-recovery proceeding. ### PG&E Natural Gas Rates On January 7, a broad cross-section of stakeholders responded to PG&E’s 2027 Gas Cost Allocation and Rate Design (CARD) application ([A.25-11-006](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050501.PDF?ref=calregulatory.com)), reflecting shared concern about both substance and process in what is the first-ever combined Gas Cost Allocation Proceeding and Gas Transmission & Storage case. - [**Small Business Utility Advocates**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230889.PDF?ref=calregulatory.com) emphasized protecting small commercial customers from disproportionate cost shifts, over-building of gas infrastructure, and adverse environmental and social impacts, while reserving judgment pending deeper analysis. - Public power and generation interests, including the [**Northern California Generation Coalition**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230906.PDF?ref=calregulatory.com) and Vistra-affiliated generators ([**Moss Landing** and **Greenleaf**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K365/594365087.PDF?ref=calregulatory.com)): - Highlight potential increases to electric-generation allocations; - Question PG&E’s gas demand and throughput forecasts in light of electrification trends and evolving large-load assumptions; - Oppose retention of fully volumetric rate designs for generators; and - Raise concerns about local transmission cost allocation and inventory management studies. Consumer advocates ([**Cal Advocates**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230798.PDF?ref=calregulatory.com) and [**TURN**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230778.PDF?ref=calregulatory.com)) formally protested, laying out an expansive scope of technical and policy issues ranging from: - PG&E’s proposed shift from marginal-cost to embedded-cost allocation; - Backbone segmentation and rate differentials; - Storage portfolio changes; - Minimum monthly transportation charge increases; and - Fixed-charge concepts. They also argue that PG&E’s forecasts, workpapers, and combined filing materially expand complexity and warrant a significantly longer procedural schedule and evidentiary hearings. The **Indicated Shippers** [echo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230799.PDF?ref=calregulatory.com) those concerns, stressing that PG&E’s application deviates from prior CPUC determinations and settlement commitments, rests on unproven assumptions tied to the still-pending 2027 General Rate Case, and risks unjustified cost shifts to noncore customers unless closely scrutinized in coordination with the GRC timeline. **INSTANT ANALYSIS**: The CARD filing has triggered immediate, broad-based resistance across consumer advocates, generators, public power, and large noncore customers, not around a single rate tweak but around the structure of the case itself. Two main issues are a focal point: PG&E’s proposed shift from marginal-cost to embedded-cost allocation, and the decision to combine GCAP and GT&S into one oversized proceeding tightly coupled to a still-unresolved GRC. The near-universal call for an expanded scope, extended schedule, and evidentiary hearings suggests this case is headed for a long, contested record rather than a fast procedural glide path. --- ### Transmission-Level Service & Cost Allocation **Administrative Law Judge Toy** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K231/593231120.PDF?ref=calregulatory.com) in [A.24-11-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com) that resets the schedule and reopens the record for PG&E’s proposed Electric Rule 30 governing transmission-level retail service. After reviewing testimony and briefs, the ALJ found the existing record insufficient to resolve significant questions around cost causation, financing, and refunds, particularly for large transmission-level loads. The ruling directs parties to submit limited additional testimony on how costs for major transmission network upgrades (Type 4 facilities) should be allocated and financed. The ruling focuses on clustered large loads, data centers, and subsequent customers that benefit from prior upgrades, as well as refund mechanics and ratepayer risk. The ruling keeps interim implementation in place while deferring final cost-allocation decisions to a later Commission order. - Limited opening testimony on questions from this ruling are due **February 18**; - Limited rebuttal testimony on questions from this ruling are due **March 13**; - Limited opening briefs on questions from this ruling are due **April 10**; and - Reply briefs on all issues are due **April 24**. **INSTANT ANALYSIS:** The CPUC is clearly uneasy with finalizing PG&E’s interim large-load cost framework without a firmer record on cost causation and fairness. By reopening the record, the Commission is reassessing how transmission upgrade costs should be assigned to large transmission-level customers, especially data centers, and whether standardized charges or customer-specific obligations are appropriate. The outcome will shape the cost, risk, and timing of future large-load interconnections in California. --- ### PG&E'S Electric Rate Design **Administrative Law Judge Atamturk** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230699.PDF?ref=calregulatory.com) in PG&E’s General Rate Case Phase 2 application ([A.24-09-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493803.PDF?ref=calregulatory.com)), setting the procedural schedule for the Dynamic Rate Options track. The ruling follows PG&E’s request for a bifurcated process and adopts a near-term stop-gap track to consider extending existing Hourly Flex Pricing and real-time pricing pilots while deferring longer-term post-pilot rate design to a future proceeding. The ALJ accepts a modified version of the parties’ compromise schedule, concluding that PG&E’s proposed longer-term Track B would push key issues too far into the future and unnecessarily tie this case to the timeline of other proceedings. The ruling contains a lengthy schedule on Page 4. **INSTANT ANALYSIS:** This GRC Phase 2 ruling preserves PG&E’s dynamic pricing pilots on an interim basis while deferring long-term rate design to a later proceeding, thereby prioritizing continuity for participating customers and avoiding premature decisions before billing systems and cost evidence are ready. --- ### Distributed Energy Resources **Administrative Law Judge Chang** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K231/593231348.PDF?ref=calregulatory.com) in [R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com) granting a Cal Advocates motion to admit its [Distribution Grid Electrification Model (DGEM) 2025 Study and Report](https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and-analyses/251030-public-advocates-office-distribution-grid-electrification-model-2025.pdf?ref=calregulatory.com) into the record. Additionally, the ruling grants PG&E’s request to allow parties time to comment on the study, recognizing its relevance to Track 1 issues in the proceeding, which examines how California’s electric distribution system must evolve to accommodate high levels of DERs, including electric vehicles and building electrification. Cal Advocates’ study evaluates nine electrification scenarios for the state’s three large investor-owned utilities, estimating distribution upgrade costs ranging from **$17 billion** to **$38 billion** by 2040, and suggests that electrification could place downward pressure on rates under certain conditions. Opening comments on the DGEM 2025 Study are due **February 5**, with reply comments due **February 12**, focusing in part on how the study should be weighed against other analyses already in the record. **INSTANT ANALYSIS:** Admitting the DGEM 2025 Study into the record anchors Cal Advocates’ electrification cost modeling within R.21-06-017’s distribution planning framework. With projected upgrade costs ranging from about $17 billion to $38 billion by 2040, the comment cycle will shape how electrification-driven capital spending is justified and how those costs are reflected in future rates. --- ### Low-Income Subsidies PG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K415/594415417.PDF?ref=calregulatory.com) asking the CPUC to approve its 2028–2033 Income-Qualified Programs ([California Alternate Rates for Energy](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com), [Family Electric Rate Assistance](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/family-electric-rate-assistance-program?ref=calregulatory.com), and [Energy Savings Assistance](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/energy-savings-assistance?ref=calregulatory.com)) with a total budget of about **$1.03 billion**, which is **$97 million** below the prior cycle. The filing continues existing program structures while tightening budgets to better reflect actual spending and emphasizing affordability, enrollment stability, and energy efficiency for low-income customers. - CARE would continue with a **93%** participation target, lower administrative costs, and targeted changes to enrollment and verification. - FERA funding would rise to reflect expanded eligibility and higher outreach costs, alongside revised enrollment targets after persistent underperformance. - ESA remains the largest component, with fewer pilots, more standardized delivery, deeper energy-savings targets, and expanded electrification, while total ESA spending declines from the prior cycle. Protests will be due 30 days from when this item appears on the CPUC's Daily Calendar. **INSTANT ANALYSIS:** PG&E is emphasizing continuity and cost discipline as affordability pressure builds, making limited ESA and FERA adjustments to reduce enrollment friction rather than reshaping low-income policy. --- ### SoCalGas Natural Gas Capacity Contracts SoCalGas submitted two expedited advice letters, AL 6588-G and AL 6589-G (available [here](https://tariffsprd.socalgas.com/scg/filings?ref=calregulatory.com)) to obtain approval of interstate natural gas transportation capacity arrangements. Advice Letter 6588-G requests approval of three new capacity contracts with [Kern River Gas Transmission Company](https://www.kernrivergas.com/?ref=calregulatory.com). AL 6589-G seeks renewal of existing capacity contracts with [TransCanada Corporation](https://www.tcenergy.com/?ref=calregulatory.com), specifically on the [NOVA Gas Transmission Ltd](https://www.tcenergy.com/operations/natural-gas/ngtl-system/?ref=calregulatory.com). and [Foothills pipeline systems](https://www.tcenergy.com/operations/natural-gas/foothills-system/?ref=calregulatory.com), used to deliver Canadian gas supplies for SoCalGas and SDG&E core customers. In both filings, SoCalGas states that Cal Advocates was consulted and does not oppose the contracts, TURN did not participate, and the agreements will not modify tariffs, withdraw service, or impose new customer conditions. Protests are due **January 20**. **INSTANT ANALYSIS:** These paired advice letters reflect SoCalGas continuing to secure upstream interstate capacity through a streamlined process. While procedurally routine, the filings show core gas procurement being stabilized incrementally outside the larger and more contested long-term gas planning debates. --- ### Group Challenges Diablo Canyon Decision Californians for Renewable Energy (CARE) filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M594/K291/594291662.PDF?ref=calregulatory.com) that challenges the CPUC’s December 2025 decision approving PG&E’s 2026 cost recovery for extended operation of the Diablo Canyon Power Plant ([D.25-12-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K401/590401896.PDF?ref=calregulatory.com)). The applicants argue the decision violates [Senate Bill 846 ](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com)and Public Utilities Code §712.8(d). CARE makes the following arguments. - The CPUC unlawfully allowed ratepayer recovery of **$304.6 million** in 2024–2025 operations and maintenance expenses that the statute explicitly bars from customer funding. CARE cites legislative history stating that funds needed to prepare for extended licensing must be covered by the Department of Water Resources loan, not ratepayers. - The CPUC improperly accepted PG&E’s distinction between transition and extended operations costs, despite legislative history that CARE says clearly prohibits passing pre-extension O&M costs to ratepayers. - The CPUC failed to address evidence showing at least **$19.4 million** in project costs incurred before November 2, 2024 that should have been disallowed even under PG&E’s own interpretation. CARE notes the decision "never mentions" these pre-November 2024 expenses or rebuts CARE's assertions, which represents a procedural failure to address record evidence. - The decision misapplies the statute by permitting Volumetric Performance Fee funds to be spent on non-Diablo Canyon projects before fully offsetting Diablo Canyon operating costs, contrary to SB 846’s ordering of priorities. Last, CARE challenges Finding of Fact 6, which states that there are no known or forecastable Nuclear Regulatory Commission license renewal conditions or Diablo Canyon Independent Safety Committee recommendations during the record period, arguing that record evidence it submitted directly contradicts this conclusion. CARE asks the Commission to amend the decision to disallow the challenged O&M expenses, reallocate all Volumetric Performance Fee funding to reduce Diablo Canyon’s revenue requirement, and strike the disputed finding of fact. **INSTANT ANALYSIS:** CARE argues that D.25-12-007 approved $304.6 million in O&M costs that PUC §712.8(d) bars from ratepayer recovery. The statute prohibits recovery of O&M expenses "incurred" before the original license expirations; the decision uses PG&E's framework, which looks at when projects are placed in service. CARE says that's a different test than the statute requires. ### WEEKEND NEWS CODEX: Willow Rock Project; Soda Mountain Solar Project; PBF's Martinez Refinery URL: https://www.calregulatory.com/weekend-news-codex-7/ Last updated: 2026-01-09T13:00:01.000Z - **A Novel Long-Duration Storage Project is Coming to the California Desert:** "The startup Hydrostor’s [Willow Rock project](https://hydrostor.ca/projects/willow-rock-energy-storage-center/?ref=calregulatory.com) would store 500 megawatts of power that could be injected into the grid for up to eight hours, totaling 4 gigawatt-hours. That’s more gigawatt-hours than any lithium-ion battery offers, and a rare step forward for a major long-duration energy storage project. Once online, it could prove a crucial tool for California, where intermittent solar generation has become the state’s [top source of electricity](https://www.canarymedia.com/articles/solar/solar-is-crushing-gas-in-california-this-year?ref=calregulatory.com)." [**CANARY MEDIA**](https://www.canarymedia.com/articles/long-duration-energy-storage/novel-energy-storage-project-california?ref=calregulatory.com) - **Bid Optimization: ERCOT & CAISO Market Outlook – Week of January 7, 2026:** "As solar production ramped back up in the new year, pricing dynamics returned to what we have seen throughout 2025 – tight TB4 spreads with little real-time price action above the day-ahead mark. However, a high miss on the net load forecast combined with strong solar production on January 5th pulled real-time prices close to negative territory. This provided a valuable charging opportunity in the real-time market and highlights the importance of capitalizing on such opportunities when the sun re-emerges after long spells of rain." [**ASCEND ANALYTICS**](https://www.ascendanalytics.com/blog/bid-optimization-ercot-caiso-market-outlook---week-of-january-7-2026?ref=calregulatory.com) - **California's Higher Gas Prices are a Policy Choice Not an Accident:** "Before the end of the year, the California Independent Petroleum Association sent a blunt message to the California Energy Commission: California’s oil industry is approaching a breaking point, and state inaction risks higher gas prices, supply disruptions, and deeper economic harm for working families and businesses. The letter urges immediate intervention to prevent the dismantling of the Valero Benicia Refinery and the collapse of the San Pablo Bay Pipeline, the last pipeline carrying Kern County crude to Northern California refineries. According to CIPA, losing either would destabilize the system." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/californias-higher-gas-prices-are-a-policy-choice-not-an-accident/?ref=calregulatory.com) - **California Introduces Bill to Legalize Plug-In Balcony Solar:** "The proposed law defines balcony solar systems as devices between 400 W and 1,200 W that connect to a standard 120 V wall outlet. The systems use integrated microinverters to convert direct current into alternating current for direct connection with home appliances. The bill prohibits utilities from triggering formal interconnection agreements for these devices." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/08/california-introduces-bill-to-legalize-plug-in-balcony-solar/?ref=calregulatory.com) - **California Reclaims Authority to Move Stalled Soda Mountain Solar Project Toward Approval:** "The California Energy Commission has issued a recommendation to certify the Soda Mountain Solar Project, moving a previously stalled development toward a final decision. The project includes plans for 300 MW of solar and 300 MW/1,200 MWh battery energy storage. The action represents a milestone for the California solar industry as it utilizes a state-level permitting pathway to address projects that have faced significant local opposition. By applying an opt-in process created by state Assembly Bill 205, the project’s developer has shifted the lead regulatory authority from San Bernardino County to the state commission." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/05/california-reclaims-authority-to-move-stalled-soda-mountain-solar-project-toward-approval/?ref=calregulatory.com) - **California Takes a "Study First" Approach to Data Center Regulation:** "California lawmakers have recently focused renewed attention on the rapid growth of data centers, driven in large part by cloud computing and artificial intelligence capacity demands. Concerns about grid reliability, electricity costs, and environmental impacts prompted a flurry of legislative proposals in the 2024–2025 session. The result, however, is a more incremental regulatory approach than many industry participants initially expected." [**MORGAN LEWIS**](https://www.morganlewis.com/blogs/datacenterbytes/2026/01/california-takes-a-study-first-approach-to-data-center-regulation?ref=calregulatory.com) - **Court Rejects Emergency Appeal to Stop Pipeline Restart:** "The Ninth Circuit Court of Appeals [rejected](https://keyt.b-cdn.net/2025/12/sable-appeal-order.pdf?ref=calregulatory.com) an attempt to stay the approval of Sable Offshore Corp.’s pipeline restart plan. The lawsuit will proceed on an expedited basis with opening briefs due January 26, 2025." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/court-rejects-emergency-appeal-to?ref=calregulatory.com) - **Foreign Billionaires Are Investing in American Energy Lawsuits:** "A prominent recent example unfolded in early 2025, when ExxonMobil [filed a federal countersuit](https://www.reuters.com/legal/exxon-mobil-sues-california-attorney-general-environmental-groups-2025-01-06/?ref=calregulatory.com) in Texas against California Attorney General **Rob Bonta**, [several U.S. environmental nonprofits](https://capitalresearch.org/article/foreign-funded-plastic-lawfare/?ref=calregulatory.com), and the Intergenerational Environment Justice Fund. The IEJF is an Australian nonprofit linked to billionaire Andrew Forrest’s Minderoo Foundation. The original lawsuit, brought by California in 2024, accused ExxonMobil of misleading the public about the recyclability of its plastics as part of broader low-carbon and energy transition efforts." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/regulation/foreign-billionaires-are-investing-in-american-energy-lawsuits/?ref=calregulatory.com) - **From Burn Piles to Biochar:** "Today, only one biomass power plant remains in operation in the San Joaquin Valley and its capacity is limited. 'We used to be able to ship that material to biomass plants or landfills,' says **Roger Isom**, president and CEO of the Western Tree Nut Association. 'Now, there’s only one operating biomass plant left in the Valley, and it can take very limited volumes.'" [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/from-burn-piles-to-biochar?ref=calregulatory.com) - **Nevada Governor Lombardo Appoints Fuel Resiliency Committee to Counter California's Radical and Punitive Energy Policies:** "The committee, operating under the Nevada Homeland Security Commission, brings together a diverse group of stakeholders from state agencies, local governments, industry leaders, and emergency management partners. Its formation follows Lombardo’s October 2025 proposal for a Fuel Resiliency Subcommittee, which was prompted by the closures of major California refineries, exposing Nevada to risks of fuel shortages, price spikes, and infrastructure bottlenecks." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/nevada-governor-lombardo-appoints-fuel-resiliency-committee-to-counter-californias-radical-and-punitive-energy-policies/?ref=calregulatory.com) - **PBF Energy Provides Update on Martinez Refinery Operations:** "PBF expects to achieve planned operating rates by the beginning of March 2026\. PBF previously projected a year-end 2025 restart. Since early in 2Q25, the Martinez refinery has been operating in the 85 000 - 105 000 bpd range. Currently, the commissioning phase of utility systems and certain idled equipment has commenced, and a phased restart of the refinery will progress as work is completed, and the quality assurance and control process is completed." [**HYDROCARBON ENGINEERING**](https://www.hydrocarbonengineering.com/refining/07012026/pbf-energy-provides-update-on-martinez-refinery-operations/?ref=calregulatory.com) - **Reversing California's Policies of Scarcity:** "With the closure of the Valero refinery in Benicia and the Philips 66 refinery in Los Angeles, the state’s remaining 11 refineries will altogether only have a capacity to process 1,338,171 barrels per day, which equates to a production deficit of 4.4 percent, and that is only when there are no disruptions whatsoever to refinery output. Typically a surplus capacity of at least five percent is needed to ensure a steady supply of gasoline and diesel fuel to consumers." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-reversing-californias-policies-of-scarcity/?ref=calregulatory.com) - **SoCalGas Connects its First Landfill-Based RNG Project to its Pipeline System:** "[Southern California Gas Company](https://www.socalgas.com/?ref=calregulatory.com) is now accepting renewable natural gas produced at the new WM Simi Valley RNG Facility into its pipeline system, marking the first time SoCalGas has interconnected a landfill-based RNG site with its infrastructure. WM captures landfill gas from its Simi Valley Landfill — which serves Ventura County and the west San Fernando Valley — and the RNG facility processes it into pipeline-quality RNG, which is then delivered into SoCalGas’s pipeline system. This RNG can be allocated to fuel consumption for heavy duty compressed natural gas vehicles and the RNG can be used to fuel homes and businesses." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/socalgas-connects-its-first-landfill-based-rng-project-to-its-pipeline-system?ref=calregulatory.com) - **Terra-Gen Boots Up 515 MWh of Energy Storage in Southern California:** "The 128.7 MW, four-hour lithium-ion battery energy storage system combined project comprises 164 battery enclosures and utilizes the existing gen-tie line connecting to Southern California Edison’s Kramer Junction Substation. The use of the resource adequacy capacity is fully contracted under two long-term resource adequacy agreements with Pacific Gas and Electric Company." [**SOLAR POWER WORLD**](https://www.solarpowerworldonline.com/2026/01/terra-gen-boots-up-515-mwh-of-energy-storage-in-southern-california/?ref=calregulatory.com) - **Valero to Keep Importing Gasoline After Benicia Refinery Closure:** "Gasoline production will continue until inventories are worked down, but the company said it expects most refining process units to be properly idled by April." [**REUTERS**](https://www.reuters.com/business/energy/valero-keep-importing-gasoline-after-benicia-refinery-closure-california-2026-01-07/?ref=calregulatory.com) ### Where the Money Lives: Pacific Gas & Electric B-20 Rates URL: https://www.calregulatory.com/where-the-money-lives-pacific-gas-electric-b-20-rates/ Last updated: 2026-01-08T02:43:50.000Z *This is the first installment of "*Where the Money Lives*," an occasional CRI feature that translates abstract rate structures and regulatory arcana into real-world financial impacts.* ### PG&E Schedule B-20 PG&E's [Schedule B-20](https://www.pge.com/tariffs/en/rate-information/electric-rates.html?ref=calregulatory.com#accordion-a84c67dc1e-item-c2ddbc7fac) is the rate structure that governs what California's largest industrial electricity users pay for power. The rate applies once your facility's demand exceeds **1,000 kW**, the threshold where you graduate from commercial customer to industrial (in the utility's eyes). On its surface, B-20 has a standard time-of-use structure: demand charges, energy charges, seasonal and hourly differentials. But the math reveals something more aggressive. The rate encodes California's grid problems in price signals. A **67%** discount during spring middays is the utility telling you, as loudly as tariff language allows, that it has more solar power than it knows what to do with. B-20 rewards operational flexibility and punishes rigidity. Customers who can shift load, shave peaks, or respond to grid conditions will see radically different economics than those running flat, inflexible processes, even at identical total consumption. I've broken down the numbers from PG&E's current B-20 rate schedule, effective January 1, 2026\. Throughout, I've modeled a **5 MW (5,000 kW) secondary-voltage industrial customer** i.e.**,** a mid-sized manufacturing plant, food processing facility, or medium data center. (Big enough to be on B-20, but not a refinery). All the figures scale linearly: a 10 MW facility doubles these numbers, a 2.5 MW facility halves them. - The first chart shows demand charges only (the portion of the bill driven by your peak draw, before any energy consumption) - The second chart shows the arbitrage value of load flexibility across TOU periods - The third chart explores a rate option that looks attractive on paper but rarely pencils out - The fourth chart covers Peak Day Pricing (PDP), an optional Demand Response program where customers accept steep surcharges during grid emergencies in exchange for guaranteed monthly credits (a risk-reward tradeoff that only makes sense if you can actually curtail when called) Overall, the story they tell is simple: in California industrial power, the money lives in your load shape. PG&E Schedule B-20 · Industrial Rates ## Where the Money Lives Summer demand charges for a 5 MW secondary-voltage industrial customer. These three charges compound, and you pay all of them. Peak Demand $42.30/kW × 5,000 kW $211,500 Part-Peak Demand $9.54/kW × 5,000 kW $47,700 Maximum Demand $40.23/kW × 5,000 kW $201,150 Total Monthly Demand Charges Before any energy consumption $460,350 **The insight:** Shaving 500 kW off your summer peak saves approximately $46,000/month in demand charges alone. Battery storage and load shifting often pencil out against charges of this magnitude. Source: PG&E Schedule B-20, effective Jan 1, 2026\. Secondary Firm rates shown. Excludes power factor adjustment (0.005¢/kWh/%). Time-of-Use Arbitrage ## The Duck Curve Dividend Winter super off-peak rates reveal how aggressively PG&E wants you to absorb midday solar. The spread is extraordinary. Summer Peak 4-9 PM 17.56¢/kWh Summer Off-Peak Other hours 11.34¢/kWh Winter Peak 4-9 PM 15.49¢/kWh Winter Super Off-Peak 9 AM-2 PM, Mar-May 5.73¢/kWh 67% Discount vs. summer peak for shifting load to winter super off-peak hours \~$272K/yr Value of shifting 5 MW into the \~460 annual super off-peak hours vs. running at summer peak Source: PG&E Schedule B-20, effective Jan 1, 2026\. Secondary Firm rates shown. Rate Structure Comparison ## The Option R Trap Option R dramatically reduces time-differentiated demand charges but still carries maximum demand charges. The tradeoff is higher volumetric energy rates, and the math only works for extremely peaky loads. STANDARD B-20 Summer Peak Demand Charge $42.30/kW Summer Peak Energy Rate 17.6¢/kWh OPTION R Summer Peak Demand Charge $5.88/kW ↓ 86% lower Summer Peak Energy Rate 40.7¢/kWh ↑ 131% higher \~¼ **The approximate break-even load factor is in the low-to-mid 20s.** If your average load during peak hours exceeds roughly one-quarter of your peak demand, standard B-20 wins. The exact threshold depends on your load shape across all TOU periods, but most continuous industrial processes clear it easily. Option R is designed for highly intermittent loads that spike briefly and idle often. Source: PG&E Schedule B-20 Option R, effective Jan 1, 2026\. Secondary Firm rates shown. Primary Firm Option R peak energy is 38.3¢/kWh; Transmission Firm is 28.9¢/kWh. Breakeven thresholds vary accordingly. Peak Day Pricing ## The Risk-Reward Calculus PDP offers guaranteed monthly credits in exchange for exposure to 90¢/kWh surcharges during grid emergencies. For a 5 MW customer: GUARANTEED CREDITS $165K Annual demand charge credits across four summer months, paid regardless of events POTENTIAL EXPOSURE $200K+ If 15 events called and you run through all of them at full load Cost per PDP event (3 hours × 5 MW × $0.90/kWh) $13,500 **The bottom line:** If you can curtail during events, PDP is free money. If you can't, you're paying approximately $35K annually for the privilege of being on call during the hottest days of the year, precisely when many facilities run hardest. Source: PG&E Schedule B-20, effective Jan 1, 2026\. PDP1 charge shown. Secondary Firm rates. Credits = ($7.21 + $1.05)/kW × 5,000 kW × 4 summer months. ### WEDNESDAY AGGREGATE: SoCalGas TIMPBA; Sempra IOUs' Corporate Restructuring; CCA Challenge to PCIA Methodology URL: https://www.calregulatory.com/cpuc-brief-socalgas-timp-recovery-sempra-restructuring-cca-rehearing-january-7-2025/ Last updated: 2026-01-15T02:30:20.000Z Today's briefing covers: - A prudence dispute over SoCalGas's $174 million TIMP recovery request; - A scoping memo on Sempra's proposed intermediate holding company; - A CCA challenge to retroactive PCIA methodology; - SDG&E's loss-of-load analysis supporting its current critical peak pricing window; and - A FERC-approved transmission credit flowing back to San Diego ratepayers. *If reports like this have been useful for you (or your team), please consider* [*becoming a paid subscriber*](https://www.calregulatory.com/pricing/) *in 2026\. Our Founder's Rate is available until *January 13* and locks members in at that price permanently (*[*$225/month*](https://www.calregulatory.com/pricing/#/portal/signup/69430ce436826b00018a9609/monthly) *or* [*$2,250/year*](https://www.calregulatory.com/pricing/#/portal/signup/69430ce436826b00018a9609/yearly)*). Team and enterprise packages are also available;* [*contact us*](https://www.calregulatory.com/contact-us/) *for assistance.* ### Natural Gas Transmission Integrity SoCalGas’s [application ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K140/565140098.PDF?ref=calregulatory.com)to recover **$173.8 million** in costs recorded in its Transmission Integrity Management Program Balancing Account (TIMPBA) has developed into a dispute over prudence, affordability, and evidentiary sufficiency. SoCalGas's request covers TIMP expenditures above a 135% cap authorized in its Test Year 2019 General Rate Case (and previously approved through [Resolution G-3600](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M533/K099/533099631.PDF?ref=calregulatory.com)), placing the burden on SoCalGas to demonstrate that both the level and timing of the additional spending were reasonable. Intervenors argue that this burden has not been met, while SoCalGas maintains that the costs were mandatory, compliance-driven, and supported by the record. In reply briefs, the Indicated Shippers and [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) each contest SoCalGas’s position that federal pipeline safety requirements justify the magnitude and pace of the spending. They argue that compliance obligations do not eliminate the utility’s responsibility to manage costs prudently, particularly in light of ratepayer affordability concerns and CPUC efforts to manage gas system costs during the transition away from fossil gas. Below are links to parties' reply briefs. (*See our summary of parties' opening briefs* [*here*](https://www.calregulatory.com/socalgas-update-parties-file-opening-briefs-in-timpba-proceeding/)*.*) - [Indicated Shippers](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230677.PDF?ref=calregulatory.com) - [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230882.PDF?ref=calregulatory.com) - [SoCalGas](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230771.PDF?ref=calregulatory.com) **INSTANT ANALYSIS:** The dispute here is not about whether TIMP work was required, but whether SoCalGas exercised cost discipline in how it was timed, scoped, and recovered. Intervenors are pressing a narrow theory: compliance does not excuse acceleration, weak documentation, or labor costs that may already be in base rates. The proposed 12-month recovery window is emerging as a flashpoint, with rate shock framed as a prudence failure, not a secondary issue. The outcome will hinge on what the CPUC treats as sufficient proof of prudence. --- ## Sempra IOUs' Corporate Restructuring The assigned commissioner (**Karen Douglas**) issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230557.PDF?ref=calregulatory.com) in [A.25-05-020](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M567/K643/567643142.PDF?ref=calregulatory.com), which concerns SoCalGas/SDG&E's request for approval of a corporate restructuring involving the creation of an intermediate holding company, "Sempra California, LLC." The application seeks either an exemption under the Public Utilities Code, or, in the alternative, a determination that the transaction does not trigger **PU Code Section 854** review. (*PU Code Section 854 is the CPUC’s gatekeeping statute for utility control transactions; it is meant to ensure that corporate reorganizations or ownership changes do not undermine regulatory protections or shift risk onto customers.*) The scoping memo confirms that the proceeding will examine whether: - Section 854 applies to the proposed holding-company formation; - An exemption is warranted if it does apply; - The transaction is in the public interest with adequate safeguards for ratepayers and Commission oversight; and - There are social and environmental impacts. **INSTANT ANALYSIS:** This scoping memo confirms that the holding-company restructuring will proceed without evidentiary hearings; the ruling treats the matter as a legal and policy determination rather than a factual dispute. The CPUC’s focus is whether the creation of an intermediate holding company triggers Section 854 and, if so, whether existing regulatory safeguards adequately protect ratepayers and preserve oversight. A final decision on this matter will set precedent on the reach of CPUC jurisdiction into upstream corporate reorganizations. --- ## SDG&E Rates/Market Price Benchmark San Diego Community Power and Clean Energy Alliance (the SD CCAs) filed an application for rehearing of a 2025 CPUC decision ([D.25-12-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K050/590050370.PDF?ref=calregulatory.com)), arguing that the CPUC unlawfully set [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates by retroactively applying a new Resource Adequacy Market Price Benchmark methodology to 2025 costs. (*See our coverage of D.25-12-008* [*here*](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/)*.*) The filing contends that SDG&E had already collected 2025 PCIA rates based on the prior, Commission-approved Market Price Benchmark methodology, and that the Commission’s subsequent change in [D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com) (when carried through into D.25-12-008) amounts to prohibited retroactive ratemaking rather than a permissible true-up. According to applicants, this approach exceeds the Commission’s authority, violates the Public Utilities Code, lacks adequate findings and evidentiary support, and produces significant, unjustified cost impacts on unbundled customers. The application asks the Commission to grant rehearing and hold a consolidated oral argument alongside related rehearing requests in other ERRA forecast proceedings. **INSTANT ANALYSIS:** This rehearing application is a direct challenge to the CPUC’s use of a revised RA Market Price Benchmark to re-price 2025 PCIA costs, with CCAs arguing the Commission crossed a clear legal boundary by applying a new methodology to costs already collected. If the Commission retreats here (or the courts later intervene), the decision could constrain how PCIA true-ups are handled and limit the CPUC’s ability to reallocate above-market costs onto departed load in future proceedings. --- ## Rate Design/Critical Peak Pricing SDG&E filed Advice Letter 4781-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to update its critical event period based on a loss-of-load analysis of its local capacity areas. - Using a stochastic Loss of Load Expectation analysis modeled in [PLEXOS](https://www.linkedin.com/products/energy-exemplar-plexos/?ref=calregulatory.com) and incorporating projected 2026 resources, SDG&E evaluated the San Diego Greater Reliability Area and the San Diego sub-area to identify hours with the highest likelihood of capacity shortfalls. - The results show that loss-of-load risk remains concentrated in the evening hours, with the highest relative risk occurring between **4 p.m. and 10 p.m.**, consistent with prior years’ findings and reflecting ongoing solar and battery penetration shifting peak risk later in the day. Based on this analysis, SDG&E concludes that its existing Critical Peak Pricing event window of 4 p.m. to 9 p.m. remains valid and supported by system conditions. Protests are due **January 20**. | Current Hours & Analysis Results | Hours | | -------------------------------- | ------- | | December 2018 LOLE Analysis | 4–9 pm | | December 2019 LOLE Analysis | 6–11 pm | | December 2020 LOLE Analysis | 5–10 pm | | December 2021 LOLE Analysis | 4–9 pm | | December 2022 LOLE Analysis | 4–9 pm | | December 2023 LOLE Analysis | 5–10 pm | | December 2024 LOLE Analysis | 4–9 pm | | December 2025 LOLE Analysis | 4–10 pm | ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2026/01/SDGE_LOLE_Figure1_clean.jpg) **INSTANT ANALYSIS**: SDG&E’s Loss of Load Expectation results continue to show evening-hour reliability risk extending to 10 pm, but the utility argues that the densest portion of that risk remains within the existing 4 p.m. –9 p.m. Critical Peak Pricing window. The filing implicitly highlights a growing mismatch between reliability physics and the behavioral limits of demand-side rate design (a gap that may widen as solar penetration increases). --- ### Transmission Rates SDG&E filed Advice Letter 4783-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to notify the CPUC that the Federal Energy Regulatory Commission has approved SDG&E’s annual update to its Transmission Access Charge Balancing Account Adjustment (TACBAA) rates. The filing explains that FERC approved SDG&E’s November 2025 TACBAA update on December 31, 2025, with rates effective January 1, 2026\. The TACBAA mechanism reconciles differences between the transmission costs SDG&E pays as a load-serving entity and the revenues it receives as a participating transmission owner under the CAISO tariff, with any net difference flowed through to retail end-use customers. For 2026, the FERC-approved update results in an approximate **$165.8 million** revenue credit to retail customers, which SDG&E implemented in rates beginning January 1, 2026. **INSTANT ANALYSIS**: This filing highlights transmission true-ups as a real swing factor in retail rates. FERC’s approval of SDG&E’s 2026 TACBAA update delivers an approximately $166 million credit to retail customers, showing how CAISO transmission cost reconciliation can temporarily offset other upward delivery-rate pressures, even as underlying cost trends continue to move higher. ### Rate Roundup: Jan. 1, 2026 Advice Letter Summaries for PG&E, SCE, SDG&E, and SoCalGas All in One Place URL: https://www.calregulatory.com/rate-roundup-jan-1-2026-advice-letter-summaries-for-pg-e-sce-sdg-e-and-socalgas-all-in-one-place/ Last updated: 2026-01-06T22:10:53.000Z Over the holidays, California’s major investor-owned utilities filed their consolidated **January 1, 2026** electric and gas rate implementations. ### **Electric Impacts** - [**PG&E Electric Rates for January 1, 2026: Bundled Rates Fall 5.7% as DA and CCA Charges Jump 19%**](https://www.calregulatory.com/pg-e-electric-rates-for-january-1-2026/) - [**SCE Rates for January 1, 2026: $444 Million Reset – Rates Down Now, System Costs Up Long-Term**](https://www.calregulatory.com/southern-california-edison-rates-for-january-1-2026/) - [**SDG&E Electric Rates for January 1, 2026: 10% Bundled Increase but Procurement Isn't the Driver**](https://www.calregulatory.com/sdg-e-electric-rates-for-january-1-2026-10-bundled-increase-but-procurement-isnt-the-driver/) ### **Natural Gas Impacts** - [**PG&E Natural Gas Rates for January 1, 2026: Rates Fall on Accounting, Not Reform**](https://www.calregulatory.com/pg-e-natural-gas-rates-for-january-1-2026/) - [**SDG&E Natural Gas Rates for January 1, 2026: Transport Rates Down, Bills Up**](https://www.calregulatory.com/sdg-e-natural-gas-rates-for-january-1-2026/) - [**SoCalGas Rates for January 1, 2026 Include a Massive 54.6% Backbone Transportation Service Increase**](https://www.calregulatory.com/socalgas-rates-for-january-1-2026-include-a-massive-54-6-backbone-transportation-service-increase/) The surface results vary: - Electric bundled rates fall at PG&E and SCE but rise at SDG&E; and - Gas transportation revenues decline modestly across PG&E and SoCalGas/SDG&E's systems Yet the filings point to a consistent underlying dynamic: cost pressure is shifting away from commodity energy and toward system access, reconciliation, and risk recovery. ### Electric IOUs On the electric side, the major electric IOUs enter 2026 with higher revenue requirements: - A **$1.7 billion** increase at PG&E; - **A $444 million** increase at SCE; and - Continued upward pressure at SDG&E from capital recovery, transmission reconciliation, and balancing-account true-ups. The near-term bundled rate declines at PG&E and SCE are not driven by a shrinking cost base, but by timing: large prior-year overcollections and amortizations temporarily offset new costs. SDG&E, with fewer offsetting balances, shows the pressure directly: bundled rates are up **10%,** residential delivery is up **19%**. And procurement is not the driver (SDG&E's [**Energy Resource Recovery Account**](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com) revenue requirement actually dropped **$67 million**). Delivery-side costs, wildfire mitigation, transmission, [cost of capital](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K833/591833054.PDF?ref=calregulatory.com), and legacy true-ups dominate the filings. Departed-load customers see the trend most clearly. At PG&E, Direct Access and Community Choice Aggregator customers face **19%** increases on a class-average level as wildfire recovery, Power Charge Indifference Adjustment, Cost Allocation Mechanism, and Diablo Canyon extended-operations costs continue to migrate into non-bypassable, transmission-weighted charges. As energy becomes a smaller share of the bill, fixed system costs occupy a growing floor that procurement choices alone cannot avoid. ### Natural Gas IOUs Gas filings show a parallel pattern expressed through different mechanics. Systemwide gas transportation revenues decline modestly at SDG&E, SoCalGas, and PG&E, largely due to balancing-account amortizations and cost-of-capital resets. But allocation rules matter. SDG&E and SoCalGas push increasing amounts of system risk into transmission and backbone services, with SoCalGas’s BTS customers absorbing a **54.6% rate increase** despite an overall revenue reduction. PG&E’s gas true-up similarly reflects accounting cleanup rather than new spending, with lower end-use transportation charges offset by higher backbone and storage components. **Bottom line:** Across both electric and gas systems, January 2026 rates are being shaped by accounting hydraulics, capital recovery, and the growing expense of maintaining a hardened, financeable, always-available system. Even where near-term bills decline, those reductions are largely timing artifacts. Energy is becoming a smaller share of customer bills. Access to the system (and its risks) is increasingly the product. --- Below are quick-reference links to CRI's coverage of the IOUs' preliminary rate filings from last fall (i.e., the filings that were submitted prior to the final consolidations/true-ups described above). - [**January 1, 2026 Electric Rate Updates: PG&E, SCE, and SDG&E**](https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/) - [**PG&E Files Natural Gas and PPP Surcharge Updates**](https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/) - [**SDG&E's 2026 Natural Gas Rates and PPP Surcharge**](https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/) - [**SoCalGas Annual Consolidated Rate Update Filing**](https://www.calregulatory.com/socalgas-annual-consolidated-rate-update-filing/) ### CPUC JAN. 15, 2026 VOTING MEETING PREVIEW: SDG&E GRC Wildfire Costs; Non-IOU Provider of Last Resort Framework; PG&E Long-Duration Storage URL: https://www.calregulatory.com/cpuc-january-15-2026-voting-meeting-preview-sdg-e-grc-wildfire-costs-non-provider-of-last-resort/ Last updated: 2026-01-06T14:21:41.000Z The CPUC's **January 15, 2026** voting meeting [agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M594/K021/594021078.pdf?ref=calregulatory.com) carries $1.2 billion in capital decisions and two framework-setting items that may shape utility operations for years. Below are the proposed decisions and draft resolutions that are currently scheduled for consideration. - For SDG&E's wildfire-mitigation cost recovery, the CPUC disallows **$435 million** out of the $1.47 billion requested. An **ALJ Larsen** [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) calls for better documentation and cost-benefit analysis. Every California utility filing Wildfire Mitigation Plan costs should read this PD closely. - The [Provider of Last Resort](https://www.cpuc.ca.gov/consumer-support/consumer-programs-and-services/electrical-energy-and-energy-efficiency/community-choice-aggregation-and-direct-access-/provider-of-last-resort?ref=calregulatory.com) framework builds procedural infrastructure for a future that hasn't arrived. No CCA has sought full POLR designation, but when one does, the application pathway will exist, with financial security, insurance, and anti-cost-shifting requirements baked in. - A pair of PG&E energy-storage items illustrate the mid-term reliability squeeze: Balsam (225 MW, eight-hour) moves toward 2028 delivery while Nighthawk (300 MW) gets a second delay extension to avoid outright default. *If reports like this have been useful for you (or your team), please consider* [*becoming a paid subscriber*](https://www.calregulatory.com/pricing/) *in 2026\. Our Founder's Rate is available until *January 13* and locks members in at that price permanently (*[*$225/month*](https://www.calregulatory.com/pricing/#/portal/signup/69430ce436826b00018a9609/monthly) *or* [*$2,250/year*](https://www.calregulatory.com/pricing/#/portal/signup/69430ce436826b00018a9609/yearly)*). Team and enterprise packages are also available;* [*contact us*](https://www.calregulatory.com/contact-us/) *for assistance.* --- ### SDG&E GENERAL RATE CASE This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) resolves SDG&E’s request to recover wildfire-mitigation costs recorded in its Wildfire Mitigation Plan Memorandum Accounts from May 2019 through 2022. SDG&E sought recovery of $284 million in O&M and $1.188 billionin capital, reflecting extensive grid-hardening, vegetation management, inspections, situational-awareness tools, and other wildfire-risk-reduction measures pursuant to post-2019 wildfire-mitigation legislation. - The PD finds some costs reasonable and aligned with mandated wildfire-risk reduction but disallows **$192.6 million** in O&M and **$242.4 million** in capital, citing insufficient support, cost-effectiveness concerns, and other deficiencies. The PD ultimately approves **$90.6 million** in O&M and **$945.2 million** in capital as just and reasonable. - The PD also addresses recovery of the undercollected revenue requirement associated with depreciation, taxes, and return on rate base for WMP-related assets through 2027\. After subtracting the $289.9 million in interim relief already collected (subject to refund), the PD authorizes **$430.9 million** in additional revenue requirement, amortized over three years to mitigate bill impacts on residential customers. - The PD rejects [TURN](https://www.turn.org/about-turn?ref=calregulatory.com)’s request to force SDG&E to refile the application but requires SDG&E to include cost-benefit ratios in future wildfire-cost-recovery filings. --- ### PROVIDER OF LAST RESORT This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K884/590884359.PDF?ref=calregulatory.com) establishes a procedural framework for how non-investor-owned entities may seek designation as a Provider of Last Resort under [Senate Bill 520](https://californiachoiceenergyauthority.com/senate-bill-520-sb-520-provider-of-last-resort-polr/?ref=calregulatory.com), without pre-judging eligibility criteria in the absence of a concrete applicant. (*Providers of Last Resort are the load-serving entity designated to supply electricity to customers when their chosen provider fails or exits the market*). The PD concludes that, because no non-IOU entity has expressed intent to assume full POLR responsibility for all customer classes in a geographic area, it would be inefficient and speculative for the Commission to resolve detailed substantive issues in advance. Instead, the PD adopts a streamlined, application-driven approach under which any prospective non-IOU Provider of Last Resort must submit a comprehensive application demonstrating compliance with Senate Bill 520’s minimum statutory requirements, including financial security, insurance, procurement compliance, technical and operational capacity, and protections against cost-shifting. The PD: - Clarifies that Provider of Last Resort obligations may not be divided by customer class; - Affirms that IOUs cannot veto a non-IOU Provider of Last Resort application but must participate in a joint filing process where feasible; and - Leaves questions regarding the scope of Commission regulatory authority to be resolved on a case-specific basis. --- ### PG&E LONG-DURATION STORAGE [Draft Resolution E-5437](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K929/588929861.PDF?ref=calregulatory.com) approves PG&E’s long-duration storage contract with the Balsam Project LLC for a 225-MW Dirac Battery Energy Storage System and an eight-hour lithium-ion facility expected online by **May 20, 2028** and delivering Resource Adequacy beginning **August 1, 2028**. The contract emerged from PG&E’s Long-Lead-Time Mid-Term Reliability solicitation and is intended to satisfy a portion of the utility’s long-duration storage obligations under the following decisions: [D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com); [D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com); and [D.25-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M569/K671/569671981.PDF?ref=calregulatory.com). Costs will be recovered through the Portfolio Allocation Balancing Account and assigned a 2021 [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) vintage. The draft resolution also affirms that the project meets updated eight-hour dispatch requirements. --- ### PG&E MID-TERM RELIABILITY [Draft Resolution E-5432](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K550/590550980.PDF?ref=calregulatory.com) approves PG&E’s request to further amend its Mid-Term Reliability contract with [Nighthawk Energy Storage, LLC](https://www.nighthawkenergystorage.com/?ref=calregulatory.com) (an [Arevon Energy](https://arevonenergy.com/?ref=calregulatory.com) affiliate) by extending the project’s required online date from June 1, 2025 to **June 1, 2026** and adjusting the contract price to reflect current market conditions. The Nighthawk project, originally approved in 2022 as part of PG&E’s Mid-Term Reliability procurement obligation, has faced successive delays due to interconnection challenges, permitting issues, supply-chain pressures, inflationary cost increases, and higher financing costs. Energy Division finds PG&E’s negotiated amendment reasonable, noting that absent this relief the developer would likely default, jeopardizing a **300-megawatt** storage resource essential to PG&E’s Mid-Term Reliability compliance. The Draft Resolution, which is redacted, concludes that the revised price remains competitive in the current market and that the project (now permitted, financed, and holding a CAISO interconnection agreement) has a credible path to meeting the amended June 1, 2026 delivery date. --- ### SCE ERRA COMPLIANCE This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K408/590408806.PDF?ref=calregulatory.com) finds that SCE’s 2022 Energy Resource Recovery Account procurement, generation management, and contract administration were largely compliant with CPUC standards and SCE's Bundled Procurement Plan. The PD authorizes recovery of **$51.442 million** in undercollected balances (mainly tied to the [Emergency Load Reduction Program](https://elrp.sce.com/?ref=calregulatory.com)), resulting in an estimated **$0.45/month** residential bill impact in 2026. SCE must remove CAISO sanctions from the ERRA/Portfolio Allocation Balancing Account because it failed to justify them and refund **$1.65 million** in double-charged franchise fees to departed customers via a 2026 PABA adjustment. --- ### HYDROELECTRIC ASSETS/LEGACY GENERATION EXIT This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K712/592712378.PDF?ref=calregulatory.com) approves SCE’s sale of the Lytle Creek and Fontana hydroelectric plants to Fontana Union Water, finding the assets non-essential and the transaction in the public interest. Although the plants total just 3.45 megawatts, the PD authorizes recovery of **$9.5 million** in pre-tax losses through the Portfolio Allocation Balancing Account and Power Charge Indifference Adjustment, allocating costs to bundled and non-exempt departing load customers. --- ### DATA CENTERS [Draft resolution E-5439](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K889/590889612.PDF?ref=calregulatory.com) approves (with modifications) PG&E’s [request](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7635-E.pdf?ref=calregulatory.com) to energize a new 90-megawatt Microsoft data center in San Jose through transmission-level upgrades, including new 115-kilovolt facilities and dedicated lines. The Draft Resolution finds the agreements necessary but determines that applying the standard [Electric Rule 15](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/electric-reliability/undergrounding-program-description/rule-20/cpuc-rule-20-undergrounding-programs-current-proceeding-r1705010/electric-tariff-rules-15-and-16-distribution-line-and-service-extensions?ref=calregulatory.com) refund framework without adjustment would pose undue risk to ratepayers due to the project’s size, transmission-level interconnection, and uncertainty around long-term revenue realization. To address this risk, the draft resolution modifies the Base Annual Revenue Calculation refund process by limiting annual refunds to 75% of PG&E’s actual net transmission revenues from Microsoft, with an adjustment for the Income Tax Component of Contribution, and extends the refund period from ten to fifteen years. Microsoft must pay actual construction costs and receives no refunds for special facilities it requested. The draft resolution emphasizes that this is an exceptional, non-precedential determination and directs PG&E to file conforming agreements. --- ### NATURAL GAS RESEARCH [Draft Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K877/590877312.PDF?ref=calregulatory.com) denies PG&E’s proposed Gas RD&D Investment Plans for 2024 and 2025 and rejects its request to recover **$7.2 million** in RD&D costs from 2023–2024\. Consequently, PG&E may not record RD&D expenses for these years. PG&E is directed to resubmit revised 2024 and 2025 plans within 60 days addressing the identified deficiencies. The draft resolution also establishes more prescriptive planning, coordination, and reporting requirements for future Gas RD&D plans beginning in 2026, and requires unspent funds to be returned to ratepayers at the end of the current GRC cycle. --- ### BIOENERGY This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) program through **December 31, 2025**. --- ### CRPC/UNION ISLAND PIPELINE This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD concludes that the company no longer holds valid franchise rights in Antioch and Brentwood and ceased transporting gas in 2023. --- ### PURPA [Draft Resolution E-5425](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K823/588823970.PDF?ref=calregulatory.com) approves, with modifications, PG&E’s and SDG&E’s proposed [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant export tariffs for customer-generators who lose Net Energy Metering or Net Billing eligibility due to prevailing-wage violations under the Public Utilities Code and a 2023 CPUC decision ([D.23-11-068](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K977/520977266.PDF?ref=calregulatory.com)). The draft resolution concludes that while the filings generally comply with the decision, an explicit 20-megawatt capacity limit must be added to align with PURPA’s mandatory-purchase rules and the 20-MW standard-offer framework in a 2020 Commission decision ([D.20-05-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M337/K709/337709639.PDF?ref=calregulatory.com)). ### MONDAY AGGREGATE: SoCalGas Recovery for DIMPBA Costs; Line 225 Force Majeure; PG&E NG Transportation Contracts URL: https://www.calregulatory.com/monday-aggregate-interim-rate-relief-physical-risk-and-the-costs-of-system-continuity/ Last updated: 2026-01-15T02:31:27.000Z Happy New Year from CRI. Today’s aggregate captures how interim ratemaking, operational outages, and long-dated infrastructure commitments are reshaping cost exposure across California’s energy system. If reports like this have been useful for you (or your team), please consider [becoming a paid subscriber](https://www.calregulatory.com/pricing/) in 2026\. Our Founder's Rate is available until **January 13** and locks members in at that price permanently. --- ### SoCalGas Natural Gas Distribution Administrative Law Judge **Brandon Gerstle** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230826.PDF?ref=calregulatory.com) in [A.25-08-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K395/576395987.PDF?ref=calregulatory.com) that grants SoCalGas partial interim rate recovery for costs recorded in its Distribution Integrity Management Program Balancing Account between 2019 and 2023\. The PD authorizes SoCalGas to recover **$35.5 million** on an interim basis, representing **60%** of the $59.1 million requested, for a 12-month period, subject to refund with interest pending a final reasonableness determination. The PD finds that interim recovery is warranted because it: - Produces direct interest savings for ratepayers (approximately $918,000); - Promotes intergenerational equity by aligning cost recovery more closely with when costs were incurred; and - Helps preserve SoCalGas’ financial integrity following a recent credit-rating downgrade, which can indirectly reduce future capital costs. At the same time, the PD rejects SoCalGas’ request for 85% interim recovery, concluding that a lower percentage better balances ratepayer affordability concerns (particularly in light of recent gas rate increases) while still achieving the public-interest benefits of interim relief. Recovery would be implemented through a Tier 1 advice letter using the **Equal Percent of Authorized Margin** cost-allocation methodology. **Rate Impacts** SoCalGas provided the following table to demonstrate what transportation rates would look like if its 85% interim relief request were granted (in dollars per therm). Actual impacts under the PD's recommended 60% authorization would be proportionally smaller. | Transportation | Jul-25 | Oct-25 | Jan-26 | Sep-26 | Oct-26 | | ------------------------------------------------------------------- | ------ | ------ | ------ | ------ | ------ | | **SoCalGas Summary** | | | | | | | Residential | $1.46 | $1.50 | $1.52 | $1.51 | $1.47 | | Core Commercial & Industrial (C&I) | $0.96 | $0.98 | $0.99 | $0.99 | $0.97 | | Noncore C&I - Distribution | $0.28 | $0.28 | $0.28 | $0.28 | $0.28 | | Electric Generation - Distribution | $0.26 | $0.27 | $0.27 | $0.27 | $0.26 | | Electric Transmission Level Service | $0.25 | $0.25 | $0.25 | $0.25 | $0.25 | | Residential Non-CARE class average bill - 36 therms/month ($/month) | $73.39 | $74.70 | $75.32 | $75.09 | $73.78 | SoCalGas also provided the table below, which anticipates what interim recovery costs (in millions) would look like if granted versus not granted. | | 2025 | 2026 | 2027 | Total | | --------------------- | ----- | ------- | ------- | ------- | | No Interim Recovery | $7.10 | $4.00 | $0.70 | $11.70 | | Interim Recovery | $7.10 | $3.10 | $0.30 | $10.40 | | Avoided Interest Cost | $0.00 | ($0.90) | ($0.40) | ($1.30) | Comments are due **January 20**. The earliest the CPUC will consider this item is **February 5**. **INSTANT ANALYSIS:** This PD continues the Commission’s willingness to grant interim rate relief where doing so reduces carrying costs and supports utility finances, even outside wildfire-related proceedings. By authorizing only 60% interim recovery (rather than the 85% sought) the PD attempts to balance interest-expense savings and credit-metric support against affordability concerns. --- ### Line 225 Force Majeure On December 27, SoCalGas issued an [Envoy](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome) notice reporting a potential natural gas pipeline break near the I-5 Freeway and Lake Hughes Road in the Castaic area. Crews isolated the affected pipeline segment and stopped the leak, with no signs of ignition or explosion, though significant land movement was observed and the cause remains under investigation. Consequently, Line 225 has been taken out of service for an indeterminate period under a force majeure, reducing Wheeler Ridge Zone capacity by 650 million cubic feet per day. To partially offset the outage, capacity at the Kern River/Mojave Kramer Junction Receipt Point may increase by up to 150 MMcf/d when system conditions permit, allowing customers to potentially exercise firm rights on an alternate delivery basis. Any incremental capacity will not be posted in Envoy’s Buy Rights Ledger, and customers are directed to monitor the Envoy Capacity Utilization page for cycle-by-cycle availability. **INSTANT ANALYSIS:** This force majeure removes about 0.65 Bcf/d of Wheeler Ridge Zone capacity while offering, at best, a partial and conditional backfill via Kern River/Mojave, exposing the thin operational margin of Southern California’s gas deliverability. For noncore customers and generators, the event reinforces that firm rights and corridor diversity (not spot procurement) are the binding constraint during system stress, and that outage risk is increasingly a locational and contractual problem rather than a commodity-price one. If the outage persists, this type of operational shock is exactly the kind of fact pattern that later migrates into balancing-account volatility, curtailment precedence disputes, and future infrastructure justification at the CPUC. All of which makes it an early-warning datapoint for parties with gas exposure tied to Wheeler Ridge. --- ### PG&E Natural Gas Transportation Contracts PG&E filed [Advice Letter 5157-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5157-G.pdf?ref=calregulatory.com), seeking pre-approval to enter into five firm interstate natural gas transportation contracts with NGTL, Foothills, and GTN pipelines to move Western Canadian supplies to California via Malin, Oregon. The contracts are intended to meet the Interstate Capacity Planning Range requirements established in prior CPUC decisions and to ensure adequate long-term gas supply for PG&E’s core customers. The contracts were reviewed and supported by both Cal Advocates and TURN, enabling PG&E to use the expedited advice letter process. Contract terms are confidential. Costs will continue to be recovered from core gas customers through existing pipeline demand charge mechanisms, and PG&E states the filing will not increase current rates or charges. Protests are due **January 9**. **INSTANT ANALYSIS:** This filing is a reminder that, beneath California’s electrification rhetoric, the CPUC is still underwriting long-dated interstate gas capacity to protect core customers from supply volatility. For sophisticated load-exit, self-supply, and gas-exposed customers, the takeaway is not today’s rates but tomorrow’s cost boundary: reliability insurance for core customers continues to be socialized through regulated pipeline commitments, while optionality outside the core will increasingly face a thinner, less forgiving margin for error. --- ### Crude Oil Transportation The CPUC issued [Draft Resolution O-0098](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M593/K611/593611368.PDF?ref=calregulatory.com), approving emergency interim rate relief for Crimson Pipeline's SPB-KLM system. The draft resolution authorizes a **59.2%** rate increase from $2.3571 to $3.7527 per barrel, effective August 1, 2025, subject to refund. The draft resolution: - Finds that sustained volume declines (from approximately 100 kbpd in 2021 to under 30 kbpd by late 2025, including zero nominations for December 2025) justify interim action to prevent suspension of pipeline operations. - Rejects an argument advanced by Chevron and Valero that the Public Utilities Code Section limits CPUC authority to approve increases above 10%. The draft resolution clarifies that the statutory cap constrains only what utilities may implement unilaterally, not what the CPUC may authorize. As a condition of approval, Crimson must secure a letter of credit to protect shipper refunds. Final rate determinations remain with the pending General Rate Case ([A.25-01-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M555/K961/555961198.PDF?ref=calregulatory.com)). **INSTANT ANALYSIS:** Draft Resolution O-0098 reflects the Commission’s willingness to use interim ratemaking to preserve critical infrastructure when volume collapse threatens operational continuity. The draft resolution prioritizes near-term system availability over rate stability, while deferring cost scrutiny and final rate reasonableness to the pending GRC (treating emergency relief as a temporary bridge rather than a final judgment). --- ### Bioenergy PG&E filed [Advice Letter 7796-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7796-E.pdf?ref=calregulatory.com) to obtain CPUC approval of an amendment to extend its [Bioenergy Renewable Auction Mechanism](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-bioram?ref=calregulatory.com) power purchase agreement with [Burney Forest Products](https://www.gridinfo.com/plant/burney-forest-products/10652?ref=calregulatory.com), a 29-megawatt biomass facility in Shasta County. The amendment extends the contract delivery term by five years, from October 31, 2027 to October 31, 2032\. Although the negotiated extension price exceeds the Commission’s per se reasonableness benchmark, PG&E argues that the terms are reasonable in light of market conditions, policy objectives related to wildfire risk mitigation and forest health, and the facility’s continued operational viability. An independent evaluator monitored the negotiations and concluded that the process was fair, the facility remains compliant with air quality and emissions standards, and the contract amendment merits CPUC approval, with all associated procurement costs recoverable in rates through the Tree Mortality Non-Bypassable Charge. Protests are due **January 20**. **INSTANT ANALYSIS**: This filing shows the Commission continuing to prioritize operational continuity and wildfire-mitigation capacity over strict price benchmarks for legacy bioenergy resources. By allowing a BioRAM extension above the per se reasonableness price, the CPUC is saying that certain biomass facilities function as policy infrastructure rather than least-cost energy supply, with costs expected to remain non-bypassable and socialized across customers via the Tree Mortality Non-Bypassable Charge. --- ### Additional Items - **Long-Duration Energy Storage:** SCE filed Advice Letter 5726-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) reporting that SCE will not proceed with a Long Duration Energy Storage pilot during its current General Rate Case cycle. After failing to secure federal [Infrastructure Investment and Jobs Act](https://en.wikipedia.org/wiki/Infrastructure%5FInvestment%5Fand%5FJobs%5FAct?ref=calregulatory.com) funding and after reassessing costs, benefits, and technology readiness, SCE concluded the project was not cost-effective and realized no benefits. - **Mid-Term Reliability**: SCE filed Advice Letter 5722-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)), seeking approval to count previously executed firm import “bridge” energy contracts (totaling 620 megawatts for July 2025, 620 MW for August 2025, and 570 MW for September 2025) toward its 2024–2025 "Mid-Term Reliability" requirements under [D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com)/[D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com). SCE also requests authorization to recover the associated costs from bundled customers and certain departing load customers through the Portfolio Allocation Balancing Account, arguing the contracts were executed before the Commission eliminated bridge contracts as a compliance option. - **Procurement:** SCE filed Advice Letter 5723-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)), which updates the electric capacity procurement limits and ratable rate limits in its Bundled Procurement Plan to extend those limits through 2035, aligning them with the CPUC’s Slice-of-Day Resource Adequacy framework and avoiding disruption to near-term RA solicitations. The filing applies the existing, CPUC-approved methodology to SCE’s baseload-equivalent RA position and functions as a narrow/interim update ahead of broader Bundled Procurement Plan revisions that are expected this year. (*PG&E's equivalent filing is available* [*here*](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7798-E.pdf?ref=calregulatory.com)*.*) - **Self-Generation Incentive Program**: The SGIP Program Administrators jointly filed [Advice Letter 7800-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5162-G.pdf?ref=calregulatory.com) to update the SGIP Handbook. The filing revises federal Investment Tax Credit treatment and adds new third-party ownership consumer protections. The changes narrow flexibility around the assumed 30% Investment Tax Credit, impose additional documentation requirements, and better align SGIP incentives with post-[Inflation Reduction Act](https://en.wikipedia.org/wiki/Inflation%5FReduction%5FAct?ref=calregulatory.com) federal tax credit eligibility. ### SDG&E Electric Rates for January 1, 2026: 10% Bundled Increase but Procurement Isn't the Driver URL: https://www.calregulatory.com/sdg-e-electric-rates-for-january-1-2026-10-bundled-increase-but-procurement-isnt-the-driver/ Last updated: 2026-01-05T16:20:20.000Z SDG&E filed Advice Letter 4757-E to consolidate all CPUC- and FERC-authorized electric rate changes into a single filing implementing **January 1** rates. (The filing will eventually be available on SDG&E's [advice-letter page](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com).) AL 4757-E incorporates adjustments previously approved through SDG&E's General Rate Case Track 1, the CPUC's 2026 Cost of Capital decision, procurement forecasts, wildfire cost recovery, Public Purpose Program surcharges, and transmission charges. GRC Track 2 is not included (the Commission pushed consideration of those issues to its **January 15** voting meeting). AL 4757-E updates preliminary estimates that SDG&E filed in November (*see our summary* [*here*](https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/)) with final adopted figures. --- SDG&E reports that system-average electric delivery rates (excluding the California Climate Credit) have increased by about **1.6¢/kWh**, or **7.4%**, while total bundled rates (delivery plus generation) have increased by **3.7¢/kWh**, or **10.2%**, relative to current rates. For a typical bundled residential customer using 400 kilowatt hours per month, this translates to an average monthly bill increase of approximately **$18.60** (**10.5%**) for non-CARE customers and **$10.01** (**9.7%**) for CARE customers, excluding the semi-annual Climate Credit. The filing reflects several major cost drivers. - The Commission’s final 2026 Cost of Capital decision ([D.25-12-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K833/591833054.PDF?ref=calregulatory.com), summarized [here](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)); - Wildfire-related charges (including a slightly reduced Wildfire Fund non-bypassable charge, summarized [here](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/)); and - Updated Energy Resource Recovery Account and Power Charge Indifference Adjustment calculations. These calculations reflect revised procurement forecasts and a change in how SDG&E uses banked Renewable Energy Credits (post-2018 RECs must now be utilized before pre-2019 RECs, affecting both bundled commodity rates and PCIA charges to departed load). Additionally, large regulatory account balances – including a $296.7 million Portfolio Allocation Balancing Account undercollection (up **$616 million** from current rates) – are partially offset by overcollections in other accounts. FERC-jurisdictional costs see a net increase, driven almost entirely by a **$172.2 million** swing in the Transmission Access Charge Balancing Account Adjustment, or "TACBAA." (Base transmission revenue requirements actually came in **$23.9 million** below November estimates.) Certain items have rolled off or declined (interim wildfire mitigation costs, some Public Purpose Program balances, and distributed generation overcollections), which partially offsets upward pressure on rates. Illustrative rates are provided below our Instant Analysis. Protests are due **January 20**. **INSTANT ANALYSIS**: The obvious headline here is a 10% bundled rate increase, which obscures a more interesting story about where California rate pressure is actually coming from. Energy procurement costs are not the driver (the ERRA revenue requirement dropped $67 million). Instead, look to capital recovery (the 2026 Cost of Capital decision, GRC base margin increases, program-specific rate base growth) and balancing account true-ups. The single largest swing is a $172 million TACBAA adjustment that reflects past transmission cost reconciliation, not new investment. Meanwhile, the $616 million increase in PABA undercollection is a sign of continued tension in the bundled/departed load cost allocation that Community Choice Aggregators and Direct Access customers should be watching. Residential customers absorb a disproportionate share: delivery rates are up 19.4% versus flat-to-negative movement for agriculture and lighting. Last, GRC Track 2 matters were pushed to January 15, leaving those cost-recovery issues still unresolved. | **SDG&E Consolidated January 1 Filing (AL 4757-E) — Class-Average Rates** | | | | | | | | | | | | ------------------------------------------------------------------------- | ------------------------- | ------------------------- | -------------- | ------------------ | ------ | -------------- | ---------- | -------------- | ---------- | ------- | | Customer Class | Rates on 10/01/25 (¢/kWh) | Rates on 01/01/26 (¢/kWh) | Delivery Rates | Total Rate (¢/kWh) | | | | | | | | Delivery | Commodity | Total | Delivery | Commodity | Total | Change (¢/kWh) | Change (%) | Change (¢/kWh) | Change (%) | | | **Residential** | 21.483 | 15.777 | 37.260 | 25.650 | 17.532 | 43.182 | 4.167 | 19.40% | 5.922 | 15.89% | | **Small Commercial** | 23.628 | 13.478 | 37.106 | 23.885 | 15.391 | 39.276 | 0.257 | 1.09% | 2.170 | 5.85% | | **Medium & Large C&I** | 17.517 | 16.156 | 33.673 | 18.903 | 19.278 | 38.181 | 1.386 | 7.91% | 4.508 | 13.39% | | **Agriculture** | 14.770 | 11.424 | 26.194 | 14.350 | 13.041 | 27.391 | \-0.420 | \-2.84% | 1.197 | 4.57% | | **Lighting** | 25.186 | 10.341 | 35.527 | 22.940 | 11.994 | 34.934 | \-2.246 | \-8.92% | \-0.593 | \-1.67% | | **System Total** | 19.602 | 15.515 | 35.117 | 21.647 | 17.676 | 39.323 | 2.045 | 10.43% | 4.206 | 11.98% | | **Class-Average Rates Excluding California Climate Credit** | | | | | | | | | | | | **Residential** | 25.248 | 15.777 | 41.025 | 28.167 | 17.532 | 45.699 | 2.919 | 11.56% | 4.674 | 11.39% | | **System Total** | 20.950 | 15.515 | 36.465 | 22.502 | 17.676 | 40.178 | 1.552 | 7.41% | 3.713 | 10.18% | *Note:* Rates shown in ¢/kWh. Negative changes shown with a minus sign. ### WEEKEND NEWS CODEX: SoCalGas Pipeline Break; San Mateo County Microgrid; Fixed Rate on Utility Bills URL: https://www.calregulatory.com/wnews-codex/ Last updated: 2026-01-04T00:54:29.000Z - **California Needs Both Clean Energy and a Nuclear-Power Backstop:** "California might generate as much energy from wind and sun as it uses overall, but not when it’s needed. To keep the power flowing, the state will actually need up to 80 gigawatts of gas-fired backup capacity — far more than it has today — or risk repeated shortfalls." [**TIMES of SAN DIEGO**](https://timesofsandiego.com/opinion/2026/01/01/california-needs-both-clean-energy-and-nuclear-power-backstop/?ref=calregulatory.com) - **California Records One of its Largest Drops in Climate Pollution on Record:** "To meet California’s goal of reducing greenhouse gas emissions by 40% below 1990 levels by 2030, the state must reduce emissions by an average of 4.4% each year. At the most recent five-year average annual reduction pace of 2.8%, California will meet its 2030 goal in 2035 — an improvement from last year when experts projected the date would be 2037." [**CLEAN TECHNICA**](https://cleantechnica.com/2025/12/23/california-records-one-of-its-single-largest-drops-in-climate-pollution-on-record/?ref=calregulatory.com) - **California Water District Plans Up to 21 GW of Solar on Land Fallowed Due to Water Shortages:** "The board of California’s Westlands Water District has adopted a clean infrastructure plan that it projects could result in 21 GW of solar power at full buildout. The Valley Clean Infrastructure Plan is a 'major land-repurposing initiative' in response to water shortages that 'force large-scale land fallowing across the San Joaquin Valley,' the water district said in a statement." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/02/california-water-district-plans-up-to-21-gw-of-solar-on-land-fallowed-due-to-water-shortages/?ref=calregulatory.com) - **Google Acquires Clean Energy Developer Intersect Power for Nearly $5 Billion:** "Alphabet Inc. (Google) has entered a definitive agreement to acquire Intersect Power, a California-based developer of utility-scale solar and battery energy storage systems. The transaction totals approximately $4.75 billion in cash and the assumption of debt. The deal is expected to close in the first half of 2026." [**PV MAGAZINE**](https://pv-magazine-usa.com/2026/01/02/google-acquires-clean-energy-developer-intersect-power-for-nearly-5-billion/?ref=calregulatory.com) - **Land Movement Suspected in SoCalGas Pipeline Break:** "Land movement likely led to damage to a Southern California Gas Co. pipeline near Castaic in the vicinity of Interstate 5 and Lake Hughes Road on the afternoon of Dec. 27 that disrupted fuel transportation and shut down the freeway for hours. Utility crews isolated the damaged section of pipeline, stopping the leak, but the event triggered a force majeure declaration, the utility said on its ENVOY system. 'The cause of the break has not been determined; however, significant land movement has been observed near the break,' SoCalGas said on its website and ENVOY. “\[A\] preliminary inspection of the area by a geologist has determined this was the most likely cause of the pipeline break.” By Dec. 30, the utility had removed a key statement from its update, which said, 'There are no indications of an ignition or explosion.'" [ **CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regional%5Froundup/land-movement-suspected-in-socalgas-pipeline-break/article%5F49f15255-18ac-444d-ae0f-39074c046ea3.html?ref=calregulatory.com) - **Sable Pipeline Gets Go-Ahead to Restart California Pipeline:** "The [Federal Pipeline and Hazardous Materials Safety Administration](https://www.phmsa.dot.gov/?ref=calregulatory.com) just gave [Sable Offshore Corp](https://sableoffshore.com/overview/default.aspx?ref=calregulatory.com). a Christmas present: Sable can begin pumping oil from its three platforms off the coast of Santa Barbara, Calif., after a federal appeals court allowed the restart of a contested pipeline, Bloomberg Law [reported](https://news.bloomberglaw.com/environment-and-energy/sable-gets-go-ahead-to-restart-controversial-california-pipeline?ref=calregulatory.com). 'Environmental groups lost their bid at the US Court of Appeals for the Ninth Circuit to stay enforcement of the federal Pipeline and Hazardous Materials Safety Administration’s emergency special permit for the Las Flores Pipeline System,' Bloomberg reported." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fl/sable-pipeline-gets-go-ahead-to-restart-california-pipeline/?ref=calregulatory.com) - **San Mateo County Commits $3 Million Toward Pescadero Microgrid to Curb Chronic Outages:** "In the last two years, the power has gone out throughout Pescadero at least 400 times. From 2021 to 2022, the town endured 25 power outages that lasted more than a day, according to San Mateo County. But through Pacific Gas & Electric’s [Microgrid Incentive Program](https://www.pge.com/assets/pge/docs/save-energy-and-money/rebate-and-incentives/PGE-MIP-Handbook.pdf?ref=calregulatory.com), a solar and battery-powered microgrid could come to Pescadero. The incentive program provides grants to install microgrids in disadvantaged communities and areas that are more vulnerable to power outages." [**LOCAL NEWS MATTERS**](https://localnewsmatters.org/2025/12/17/san-mateo-county-commits-3-million-toward-pescadero-microgrid-to-curb-chronic-outages/?ref=calregulatory.com) - **WEM Body Approves Natural Gas Resource-Management Proposal:** "The Western Energy Markets Governing Body unanimously approved changes to the California Independent System Operator’s natural gas resource market rules to make scheduling of gas units more efficient. After more than two years’ work addressing stakeholder challenges, several regional market participants told the WEM Governing Body at its Dec. 16 meeting that the enhancements would better allow them to manage and recover the operational costs associated with running natural gas fleets, including outside California." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/markets/wem-body-approves-natural-gas-resource-management-proposal/article%5F98c22f7e-e2ab-4ead-b73f-4470f085b137.html?ref=calregulatory.com) - **What Happens When Utilities Raise the Fixed Charge and Lower the Energy Charge?** "...three investor-owned utilities regulated by the California PUC will be rolling out these fixed charges in the next several months. One of them, SCE, rolled them out in November. PG&E, which serves 5 million customers in northern California, will impose a fixed charge of $24 a month in March 2026 on non-low-income customers who account for roughly a third of all customers. The latter will get a substantial discount on their bills which ranges from 18-35 percent based on their income. It is paid for by all other customers. For low income customers, the fixed charge will range from $6-12 a month. They will see lower bills when the fixed charge is implemented. But they are unlikely to electrify either their homes or their vehicles. Many of them rent their homes and don’t own vehicles." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/12/30/what-happens-when-utilities-raise-the-fixed-charge-and-lower-the-energy-charge/?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: Energy Storage PFM; Flex Alerts; New SoCalGas AMI Application URL: https://www.calregulatory.com/wednesday-aggregate-6/ Last updated: 2026-01-02T01:14:59.000Z Happy New Year, and sincere thanks for being inaugural CRI readers as we launched the platform over the past two months. In a short period, CRI has developed a high-caliber readership that includes influential parties across California and several other states. **As we head into 2026, a request**: if you or your team find this work useful, please consider [becoming a paid CRI subscriber](https://www.calregulatory.com/pricing/). Your support allows us to continue tracking and interpreting the regulatory activity that shapes your costs, your exposure, and your next move – delivered as high-speed, early-warning intelligence in one of the world’s most consequential regulatory environments. May you and yours have a wonderful 2026! --- ### Natural Gas Advanced Metering Infrastructure SoCalGas filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K231/593231269.PDF?ref=calregulatory.com) seeking CPUC authorization to implement a new revenue requirement to support a systemwide Advanced Meter Infrastructure Replacement (AMIR) Project, arguing that its existing AMI system is approaching end-of-life and becoming technologically obsolete. - SoCalGas proposes a coordinated replacement of more than six million gas meter communication modules and associated network, data-management, and cybersecurity systems to avoid a costly and operationally risky return to manual meter reading as battery failures and vendor support limitations emerge around 2030\. - SoCalGas estimates a total forecasted revenue requirement of **$3.76 billion** over the life of the project, driven by $2.1 billion in direct capital and O&M costs incurred between 2025 and 2034, with costs tracked through a new two-way balancing account. The project would be executed in phased technology development and field deployment workstreams, peaking during mass deployment from 2030 to 2034\. SoCalGas frames the project as necessary to preserve meter-to-cash functions, enhance operational visibility and cybersecurity, and maintain billing accuracy and safety. Cost recovery would be allocated primarily to core customers on a meter-count basis, resulting in gradually increasing residential bill impacts through the early 2030s. These impacts would be followed by bill reductions later in the forecast period, subject to Commission approval. **INSTANT ANALYSIS:** SoCalGas’ application is a preemptive, system-preservation filing that establishes a multi-billion-dollar cost trajectory years before AMI failures become operationally visible. By framing AMI replacement as unavoidable end-of-life remediation rather than discretionary modernization, SoCalGas is positioning the Commission to authorize a long-dated revenue stream with limited room for later prudence challenges, particularly once field deployment ramps in 2030\. SoCalGas's meter-count allocation assigns nearly all costs to core residential customers, reinforcing how non-commodity, systemwide infrastructure investments are increasingly treated as baseline service obligations rather than optional enhancements. If approved largely as filed, AMIR would add another durable fixed-cost layer that persists through electrification, load volatility, and customer attrition, illustrating how gas infrastructure costs are being stabilized in rates even as long-term gas demand remains uncertain. --- ### Energy Storage The [California Energy Storage Alliance](https://storagealliance.org/?ref=calregulatory.com) (CESA) filed a reply in [R.15-03-011 ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M149/K976/149976766.PDF?ref=calregulatory.com)defending its [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328347.PDF?ref=calregulatory.com) of a 2017 decision ([D.17-04-039](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M185/K070/185070054.PDF?ref=calregulatory.com)) which governs how station power is treated for utility-scale energy storage facilities when batteries are idle. - CESA argues that the current rules (developed when California had only a handful of storage projects) now impose unnecessary costs, billing complexity, and distorted operational incentives as the state has scaled to more than 13,000 megawatts of storage. - Its reply responds to opposition from utilities and Cal Advocates, asserting that the petition fully complies with the CPUC's Rule 16.4 by presenting new, previously unknowable facts through a sworn expert declaration based on real-world operating experience that did not exist in 2017\. (*Rule 16.4 governs petitions for modification, allowing a party to request changes based on new or changed facts*). - CESA maintains that these new facts demonstrate that idle-period station power charges increase project risk and financing costs, which are ultimately embedded in capacity bids and passed through to ratepayers in a competitive procurement environment. - While acknowledging that some near-term contract effects could benefit certain developers, CESA contends these impacts are overstated, unquantified, and outweighed by long-term reductions in storage procurement costs. The filing also rebuts claims that CESA’s proposed framework is technically infeasible, arguing that utilities already use comparable metering and baseline methods. CESA concludes that modifying the idle station power rules would reduce deployment friction, better align incentives, and support California’s reliability and clean energy goals. **INSTANT ANALYSIS:** This particular fight is about whether California’s tariff and rate-design framework can adapt once a resource moves from pilot scale to system-critical infrastructure. CESA is using Rule 16.4 to argue that storage has crossed that threshold, and that legacy station-power constructs are now embedding unnecessary financing risk into capacity bids that ultimately flow through to ratepayers. Pushback from the utilities and Cal Advocates implies institutional resistance to reopening settled cost-allocation logic, even as the underlying operating reality has changed. If the Commission accepts that lived operating experience can justify post-decision recalibration, this filing becomes a potential precedent for revisiting other legacy tariffs that were designed for a grid that may no longer exist. --- ### Demand Response/Flex Alerts The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699379.PDF?ref=calregulatory.com) in its latest Demand Response docket ([R.25-09-004](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K072/582072320.PDF?ref=calregulatory.com)) seeking party comments on a [staff proposal ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827656.PDF?ref=calregulatory.com)to extend funding for California’s [Flex Alert ](https://www.flexalert.org/?ref=calregulatory.com)marketing campaign through 2026\. Flex Alerts are voluntary conservation appeals designed to reduce electricity demand during peak periods, particularly heat events, and have been funded by the Commission since 2021 as part of its broader grid reliability response following the outages of 2020\. - The staff proposal recommends maintaining the existing statewide paid media Flex Alert campaign for 2026 at the current annual budget of **$22 million**, funded by PG&E, SCE, and SDG&E, and administered by SCE under its existing contract with [Doyle Dane Bernbach Communications Group](https://en.wikipedia.org/wiki/DDB%5FWorldwide?ref=calregulatory.com). - The proposal emphasizes rising electricity demand pressures from electrification and data center growth. Staff cites evaluation results that show near-universal public awareness of Flex Alerts and widespread voluntary load reductions during alert days, including significant reductions in air conditioning and appliance use. - The proposal contains specific questions for parties on whether the program should continue in 2026, whether SCE should extend or renew the existing contract, what the appropriate 2026 budget should be, and whether additional conditions or program elements are needed for continued administration. Comments are due **January 20**, with replies due **January 30**. **INSTANT ANALYSIS:** The Commission is treating Flex Alert as a standing reliability tool funded through utility demand-side budgets. While Flex Alerts are activated based on CAISO operating conditions, those conditions are largely shaped by CPUC policy choices governing Resource Adequacy, procurement, electrification, and Demand Response design. In practice, the Commission has chosen to absorb this reliability function entirely on the retail side rather than distribute it across the wholesale-retail boundary it already regulates. As Flex Alert becomes a recurring tool, it normalizes voluntary conservation as part of California’s core reliability stack rather than a temporary emergency measure. --- ### Utility Finances PG&E filed a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230610.PDF?ref=calregulatory.com) to an ALJ ruling seeking clarification and additional information with regard to the utility's application for a limited capital structure adjustment ([A.24-08-004](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M537/K130/537130683.PDF?ref=calregulatory.com)). In the filing, PG&E argues that its request is not a waiver under Rule IX.B of the [Affiliate Transaction Rules](https://www.sce.com/sites/default/files/inline-files/atr.pdf?ref=calregulatory.com) triggered by an adverse financial event, but rather a narrow, accounting-based adjustment to how compliance with its authorized capital structure is calculated. (*Recall that Rule IX.B is a provision of the CPUC’s Affiliate Transaction Rules that governs how a utility must maintain and demonstrate compliance with its authorized capital structure*.) - PG&E explains that it is seeking approval to exclude specific categories of non-rate-base financing (including long-term debt and equity charges associated with the [Kincade](https://en.wikipedia.org/wiki/Kincade%5FFire?ref=calregulatory.com) and [Dixie](https://en.wikipedia.org/wiki/Dixie%5FFire?ref=calregulatory.com) wildfires and a [Department of Water Resources forgivable loan](https://calmatters.org/economy/2025/08/diablo-canyon-loan/?ref=calregulatory.com)) from the equity-to-debt ratio used to determine return on rate base. (*The DWR loan is an interest-free loan of up to *$1.4 billion* provided under Senate Bill 846 to support the license extension and continued operation of the Diablo Canyon Nuclear Power Plant. Repayment is expected from federal DOE nuclear credit funding and not from ratepayers.*) - According to PG&E, these items are excluded from rate base, subject to future recovery or forgiveness, and therefore should not distort capital structure compliance calculations. PG&E cites multiple Commission precedents where similar capital structure adjustments were approved outside the context of adverse financial event waivers, grounding the Commission’s authority in Public Utilities Code Section 701 and prior decisions. PG&E further clarifies that it is not claiming the DWR loan or wildfire-related items constitute an adverse financial event, though it notes that, illustratively, the requested adjustments would amount to roughly a **1.2% change** in equity and debt ratios if applied to mid-2024 figures. **INSTANT ANALYSIS:** PG&E is pressuring the Commission to treat extraordinary wildfire-era financing and the DWR forgivable loan as structural exclusions (not emergency deviations) from capital-structure compliance under Rule IX.B. The practical effect is to keep PG&E “in compliance” with its authorized equity ratio while carrying large, non-rate-base obligations that neither earn a return nor reflect ongoing utility investment. If the Commission affirms this framing, it will reinforce a now-consistent pattern: wildfire liabilities are being absorbed through accounting architecture rather than through formal adverse-event waivers, which reduces financing costs and scrutiny while normalizing long-duration carve-outs from capital discipline. In essence, the CPUC is allowing wildfire costs to be absorbed through capital-structure exclusions, rather than handled as episodic emergencies. This seems to portend a long-term shift in how California is governing utility finance under chronic, system-level risk. --- ### Utility Back-Office Modernization SoCalGas filed a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M593/K230/593230606.PDF?ref=calregulatory.com) in [A.25-05-004](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K498/565498664.PDF?ref=calregulatory.com) to an ALJ ruling seeking additional detail on its request for incremental funding for the Customer Information System Replacement Program. The filing explains how SoCalGas estimated labor and contractor costs for organizational readiness, training delivery, and surge staffing, and clarifies that these costs are expected to exceed the **$46 million** in Customer Information System O&M funding already authorized in the company's 2024 General Rate Case. Consistent with [D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com), which the CPUC adopted in 2024, SoCalGas is now seeking an additional **$24.9 million** through this separate application and proposes allocating the incremental costs using the Equal Percentage of Authorized Margin methodology rather than usage-based allocation. As such, SoCalGas is characterizing Customer Information System costs as a vital utility operation. **INSTANT ANALYSIS:** SoCalGas’s Customer Information System filing shows how enterprise IT overruns migrate from forecast risk to rate recovery once the Commission authorizes a “come back later” pathway in a General Rate Case. By framing the additional $24.9 million as a continuation of already-approved O&M and allocating it via the EPAM methodology, SoCalGas positions CIS costs as non-usage, base-business infrastructure rather than a project with discrete beneficiaries. The result is that modernization risk is absorbed across customer classes through margin allocation, reinforcing a broader Commission pattern: large back-office systems increasingly behave like permanent utility infrastructure, not temporary projects subject to rigid cost discipline. --- ### Energy Efficiency SCE filed its [semi-annual Independent Evaluator report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699372.PDF?ref=calregulatory.com) in the CPUC’s new Energy Efficiency oversight rulemaking ([R.25-04-010](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M564/K857/564857040.PDF?ref=calregulatory.com)), covering third-party EE solicitations conducted between April and September 2025\. The report assesses SCE’s compliance with Commission directives governing solicitation transparency, Procurement Review Group oversight, and third-party portfolio minimums. The report reviews progress across local commercial, large industrial, and statewide midstream programs. Independent Evaluators generally find that SCE’s solicitation processes align with CPUC policy, while noting some persistent frictions (long contracting timelines, implementer risk exposure, and ongoing tension between Total Resource Cost thresholds and Total System Benefit objectives). The filing offers insight into how California’s EE procurement framework is functioning in practice, rather than announcing new policy or rate impacts. Those insights include acknowledgments that: - Risk is being pushed downstream, timelines remain long, and policy signals remain ambiguous (**page 11**). - Cost-effectiveness is negotiated, not assumed. The report arguably admits that Total Resource Cost is no longer a neutral metric, it's a constraint that must be managed, cured, or worked around (**page 12**). - Performance-based structures are shifting risk allocation, i.e., protecting customers and placing the onus on implementers (**page 30**). - Budget authority ≠ market clearing – process complexity, risk allocation, and cost-effectiveness screens can strand capital (**page 30**). **INSTANT ANALYSIS:** SCE’s report depicts California’s energy-efficiency regime as a managed procurement system in which outcomes are shaped by process design, cost-effectiveness constraints, and risk allocation rather than budget authority alone. Although solicitations align with CPUC directives, the record highlights persistent friction. The result is a portfolio that is procedurally dense, slow to convert authorized funding into executed programs, and governed primarily by negotiation and screening mechanics rather than straightforward deployment. ### SCE Rates for January 1, 2026: $444 Million Reset -- Rates Down Now, System Costs Up Long-Term URL: https://www.calregulatory.com/southern-california-edison-rates-for-january-1-2026/ Last updated: 2026-01-05T01:09:51.000Z SCE submitted Advice Letter 5725-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to implement its full, consolidated set of CPUC- and FERC-authorized electric revenue requirement and rate changes effective **January 1, 2026**. **How to read this filing:** Advice Letter 5725-E implements a **$444 million increase** in SCE’s authorized system revenue requirement, but that figure should not be read as a one-for-one increase in January 1 customer rates. The consolidated year-end filing blends new base costs with the amortization of large prior-year balancing account over- and under-collections. In this case, refunds and timing credits (particularly in procurement and public purpose accounts) temporarily offset rising delivery, transmission, wildfire, and non-bypassable costs. Consequently, some customer classes see near-term rate **declines** even as the underlying cost structure continues to expand. ### What SCE is Revealing AL 5725-E shows that the largest upward rate pressure comes from delivery-side and non-energy components rather than commodity energy alone. Distribution revenue requirements increase significantly due to: - General Rate Case-authorized capital and O&M; - Wildfire mitigation and vegetation management costs; - Pension and medical balancing account true-ups; and - Updated uncollectibles. Transmission costs will also rise following FERC-jurisdictional base transmission updates and transmission balancing account adjustments. On the procurement side, the adopted 2026 Energy Resource Recovery Account forecast increases fuel and purchased power revenue requirements, even as large ERRA and other balancing account amortizations partially offset that increase in rate levels. The updated [2026 Cost of Capital decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com) (*summarized* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)) modestly lowers SCE’s authorized rate of return and reduces the base revenue requirement compared to preliminary filings, while flowing through to capital-heavy balancing and memorandum accounts. In parallel, AL 5725-E incorporates fixed recovery charges associated with multiple wildfire-related securitizations, including new Thomas Fire and Montecito Debris Flow recovery bonds, along with ongoing Wildfire Fund non-bypassable charges. Last, the advice letter updates the Diablo Canyon extended-operations non-bypassable charge, reflecting SCE’s share of statewide costs allocated on a coincident-peak basis and adjusted for the first true-up year. Protests are due **January 20.** **INSTANT ANALYSIS:** Advice 5725-E functions as a year-end ratemaking reset that adds $444 million to system revenue requirements while framing the change as a routine consolidation. Rate pressure comes overwhelmingly from delivery-side and non-bypassable costs (distribution capital, wildfire mitigation and securitization, transmission revenue updates, and pension and medical true-ups) rather than from energy procurement. ERRA shifts still matter, but mainly as timing adjustments layered on top of a much larger cost base. The filing reinforces a clear direction of travel: customer bills are increasingly driven by the cost of maintaining a hardened, financeable, always-available system. For bundled, Direct Access, and Community Choice Aggregator customers, this means procurement choices alone offer diminishing insulation from rising charges as access to the system (not energy usage) becomes the primary object of cost recovery. As alluded to above, large balancing account amortizations will produce **net rate reductions** for most customer classes in the near term, despite the increased revenue requirement (see table below). | Bundled Average Rates (¢/kWh) | | | | | | --------------------------------- | ------------------ | --------------- | ----------------- | -------- | | Customer Group | Current (11/15/25) | Proposed Change | Proposed (1/1/26) | % Change | | Residential | 35.3 | (0.8) | 34.5 | \-2.3% | | Lighting – Small and Medium Power | 32.2 | (1.7) | 30.5 | \-5.3% | | Large Power | 21.3 | (0.9) | 20.3 | \-4.3% | | Agricultural and Pumping | 25.4 | (1.1) | 24.3 | \-4.3% | | Street and Area Lighting | 36.1 | 0.3 | 36.4 | 0.9% | | Standby | 18.0 | (2.8) | 15.1 | \-15.8% | | Total | 30.2 | (1.3) | 28.9 | \-4.3% | | Residential Bill Impact ($/Month) | | | | | | Description | Current (11/15/25) | Proposed Change | Proposed (1/1/26) | % Change | | Non-CARE residential bill | $193.06 | \-$5.51 | $187.56 | \-2.9% | | CARE residential bill | $117.46 | \-$5.06 | $112.40 | \-4.3% | ### PG&E Electric Rates for January 1, 2026: Bundled Rates Fall 5.7% as DA and CCA Charges Jump 19% URL: https://www.calregulatory.com/pg-e-electric-rates-for-january-1-2026/ Last updated: 2026-01-05T01:11:24.000Z PG&E submitted [Advice Letter 7797-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7797-E.pdf?ref=calregulatory.com), its Annual Electric True-Up filing, to implement consolidated electric rate and tariff updates effective **January 1, 2026**. **The main story**: Load-exit economics continue to shift. Bundled customers will see a **5.7% average rate decline** driven by balancing-account timing. Meanwhile, Direct Access and Community Choice Aggregator customers face a **19% increase** as wildfire recovery, Power Charge Indifference Adjustment, Cost Allocation Mechanism, and Diablo Canyon extended-operations costs settle into non-bypassable charges. Entities that assume utility costs can be avoided through procurement choices alone must reckon with a fixed-cost floor that is rising faster than the commodities being displaced. --- The filing rolls forward all CPUC- and FERC-authorized revenue requirement changes since PG&E’s preliminary true-up filing (*summarized* [*here*](https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/)), updates year-end balancing account forecasts based on recorded data through November 2025, and incorporates final Commission decisions adopted through December 18, 2025\. In total, PG&E forecasts a **$1.7 billion increase** in electric revenues relative to revenues at present rates, driven primarily by balancing account amortizations, wildfire-related charges, generation and procurement adjustments, and other approved program costs. Despite the higher overall revenue requirement, system-average bundled rates are declining due to sales growth and rate design effects, while Direct Access and CCA rates rise because those customers’ rates exclude commodity charges and therefore reflect a higher share of non-commodity cost recovery. The advice letter also implements: - Updated cost-of-capital parameters; - Diablo Canyon extended-operations cost recovery under Senate Bill 846; - Energy Resource Recovery Account and Power Charge Indifference Adjustment updates; - Transmission-related pass-throughs accepted by FERC; and - Various Public Purpose Program and wildfire-related charges. Illustrative rates are provided below. Protests are due **January 20**. **INSTANT ANALYSIS**: PG&E’s January 1 electric rate implementation shows California’s cost-recovery center of gravity continuing to move away from energy procurement and toward system access. In short, energy is becoming a smaller share of customer bills, and access to a resilient, always-available system is becoming the product. | **PG&E January 1, 2026 Proposed Rate Changes** (excluding GHG revenue returns) • $/kWh | | | | | -------------------------------------------------------------------------------------- | -------- | -------- | ------ | | Schedule | Present | 01/01/26 | Change | | System-Level Summary | | | | | Bundled - System Average | $0.36200 | $0.34126 | \-5.7% | | Direct Access/CCA Average | $0.20591 | $0.24564 | +19.3% | | Key Commercial Schedules | | | | | Direct Access/Community Choice Aggregation | | | | | B-20 Transmission | $0.0628 | $0.08994 | +43.2% | | B-20 Primary | $0.13177 | $0.16265 | +23.4% | | B-20 Secondary | $0.15154 | $0.18492 | +22.0% | | B-19 (all voltages weighted) | $0.17931 | $0.21805 | +21.6% | | Standby | | | | | Standby - Transmission | $0.11081 | $0.14831 | +33.8% | | Standby - Primary | $0.33400 | $0.35604 | +6.6% | | Standby - Secondary | $0.27804 | $0.31553 | +13.5% | | Bundled | | | | | B-20 Transmission | $0.20082 | $0.18263 | \-9.1% | | B-20 Primary | $0.27157 | $0.25016 | \-7.9% | | B-20 Secondary | $0.30556 | $0.28308 | \-7.4% | | B-19 (all voltages weighted) | $0.33992 | $0.31690 | \-6.8% | | Standby | | | | | Standby - Transmission | $0.18650 | $0.17005 | \-8.8% | | Standby - Primary | $0.42999 | $0.41174 | \-4.2% | | Standby - Secondary | $0.48869 | $0.45259 | \-7.4% | ### SDG&E Natural Gas Rates for January 1, 2026: Transport Rates Down, Bills Up URL: https://www.calregulatory.com/sdg-e-natural-gas-rates-for-january-1-2026/ Last updated: 2026-01-05T01:12:40.000Z SDG&E filed Advice Letter 3484-G (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to implement the consolidated update to its gas transportation rates effective **January 1, 2026**. Protests are due **January 20**. (*For comparative context, see our summary of SDG&E's preliminary January 1 filing* [*here*](https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/).) AL 3484-G details a net decrease of approximately **$22.5 million** (-2.8%) in SDG&E’s overall gas transportation revenue requirement, inclusive of franchise fees and uncollectibles. This consolidation is driven by amortized regulatory account balances, updated cost-of-capital parameters, post-test-year revenue requirement adjustments, reduced natural gas leak abatement costs, and the return of Low Carbon Fuel Standard credits for natural gas vehicle service. Core customers account for the bulk of the reduction (**$22.1 million**), with a smaller decrease for noncore customers (**$0.4 million**), partially offset by updated cost allocations from SoCalGas and harmonization of certain rates across the two utilities. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/consolidated.png) While transportation charges will decline, typical bundled residential bills are projected to increase modestly in 2026 due to higher gas procurement costs and Public Purpose Program surcharges, which offset transportation charge decreases (see chart below, which excludes the [California Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com)). ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/annual.png) Meanwhile, illustrative transportation rates, as provided by SDG&E, are available below. The largest increases occur on the noncore transmission side because Sempra-wide cost normalization shifts upstream SoCalGas transportation costs onto transmission service, reinforcing the distinction between backbone and distribution pricing without increasing total noncore revenue. __SDG&E: January 1, 2026 Natural Gas Transportation (Class-Average) Rates__ | Customer Class | Present Rates ($/therm) | Proposed Rates ($/therm) | Rate Change ($/therm) | Percentage Change | | ------------------------------------------- | ----------------------- | ------------------------ | --------------------- | ----------------- | | Core | | | | | | Residential | $2.11107 | $2.09918 | ($0.01189) | \-0.6% | | Commercial & Industrial | $0.91949 | $0.82119 | ($0.09830) | \-10.7% | | NGV Post-Sempra-Wide | $0.38603 | $0.32830 | ($0.05773) | \-15.0% | | **Total Core** | $1.57547 | $1.52863 | ($0.04684) | \-3.0% | | Noncore C&I | | | | | | Distribution-Level Service | $0.40209 | $0.38615 | ($0.016) | \-4.0% | | Transmission-Level Service | $0.07027 | $0.07867 | $0.008 | 12.0% | | **Total Noncore C&I** | $0.30810 | $0.29906 | ($0.009) | \-2.9% | | Noncore Electric Generation | | | | | | Distribution-Level Service Post-Sempra-Wide | $0.30353 | $0.27731 | ($0.026) | \-8.6% | | Transmission-Level Service | $0.06764 | $0.07616 | $0.009 | 12.6% | | **Total Electric Generation** | $0.12444 | $0.12459 | $0.000 | 0.1% | | **Total Noncore** | $0.15054 | $0.14939 | ($0.001) | \-0.8% | | **System Total** | $0.97236 | $0.94485 | ($0.02751) | \-2.8% | **INSTANT ANALYSIS:** SDG&E’s consolidated gas rate update reduces overall gas transportation revenue by about 3% through regulatory account amortization and cost-of-capital updates, while reallocating upstream SoCalGas costs toward noncore transmission service. Bundled residential bills nonetheless rise modestly as gas procurement and public-purpose surcharges increase, reflecting cost reallocation rather than new system spending. ### SoCalGas Rates for January 1, 2026 Include a Massive 54.6% Backbone Transportation Service Increase URL: https://www.calregulatory.com/socalgas-rates-for-january-1-2026-include-a-massive-54-6-backbone-transportation-service-increase/ Last updated: 2025-12-31T00:56:37.000Z SoCalGas filed Advice Letter 6578-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to implement its consolidated gas transportation rate update effective **January 1, 2026\.** Protests are due **January 20**. The filing reflects: - Annual regulatory account amortizations approved in the 2024 Cost Allocation Proceeding; - Updates to Cost of Capital, greenhouse gas and climate-credit adjustments, low-income program cost recovery, leak-abatement funding; and - Revised forecasts for company-use fuel and unaccounted-for gas. In aggregate, the consolidation produces a net systemwide revenue decrease of approximately **$17.4 million** (with franchise fees and uncollectibles), with sizable bill impacts redistributed across customer classes. The precise impact on class of service is delineated below. | Class of Service | Applicable Rate Schedules | Net M$ (with FF&U) Increase/(Decrease) | | ------------------------------------- | ------------------------------------------------------ | -------------------------------------- | | Core | GR, GS, GM, GO-AC, G-NGVR, GL, G-10, G-AC, G-EN, G-NGV | ($232.8) | | Noncore | GT-NC, GT-TLS | ($8.9) | | Unbundled Storage | G-TBS | $0.0 | | Backbone Transportation Service (BTS) | G-BTS | $224.3 | | TOTAL | | ($17.4) | Core customers will see a large overall reduction, noncore transportation rates will decline modestly, but Backbone Transportation Service (BTS) rates will rise higher than expected (**54.6%**) due to higher allocated costs and integration adjustments. (*Recall that, in SoCalGas's preliminary version of this filing, which CRI summarized* [*here*](https://www.calregulatory.com/socalgas-annual-consolidated-rate-update-filing/)*, SoCalGas projected a 51.2% BTS increase.*) The increase in the BTS revenue requirement to **$224.3 million** in the 2026 consolidated rate update reflects the stacking of multiple allocation and integration adjustments, not a single driver. - The core component is the $219.6 million BTS increase arising from the annual regulatory account amortization under the 2024 Cost Allocation Proceeding framework, which reallocates balancing account balances disproportionately to backbone service even as total system revenues decline. - That base increase is then further adjusted upward through transmission system integration mechanics (most notably the assignment of $4.5 million of SDG&E Pipeline Safety Enhancement Plan backbone transmission balancing account costs to SoCalGas BTS) and minor correcting entries (including exchange cost corrections), yielding a net BTS increase of $224.3 million. In short, BTS is serving as the landing zone for layered amortization, integration, and true-up adjustments. Below are illustrative class-average rates. | Service Type | Present$/therm | Proposed$/therm | Change | % | | --------------------------------- | -------------- | --------------- | ---------- | ------- | | CORE | | | | | | Residential | $1.49280 | $1.42236 | ($0.07044) | \-4.7% | | C&I | $0.97893 | $0.89756 | ($0.08137) | \-8.3% | | NGV Post-Sempra-Wide | $0.40713 | $0.37738 | ($0.02975) | \-7.3% | | Gas A/C | $0.76716 | $0.67550 | ($0.09166) | \-11.9% | | Gas Engine | $0.29627 | $0.22849 | ($0.06778) | \-22.9% | | Total Core | $1.28292 | $1.21198 | ($0.07094) | \-5.5% | | NONCORE C&I | | | | | | Distribution-Level Service | $0.28163 | $0.27724 | ($0.00439) | \-1.6% | | Transmission-Level Service | $0.08772 | $0.08044 | ($0.00728) | \-8.3% | | Total Noncore C&I | $0.19314 | $0.18743 | ($0.00571) | \-3.0% | | NONCORE ELECTRIC GENERATION | | | | | | Distribution Post-Sempra-Wide | $0.26808 | $0.27049 | $0.00241 | +0.9% | | Transmission-Level Service | $0.08019 | $0.07679 | ($0.00340) | \-4.2% | | Total Electric Generation | $0.10968 | $0.10719 | ($0.00249) | \-2.3% | | Total Retail Noncore | $0.14599 | $0.14210 | ($0.00389) | \-2.7% | | WHOLESALE | | | | | | Long Beach / SWG / Vernon / Int'l | $0.06757 | $0.07608 | $0.00851 | +12.6% | | SDG&E Wholesale | $0.07395 | $0.07676 | $0.00281 | +3.8% | | Total Wholesale incl. SDG&E | $0.07188 | $0.07654 | $0.00466 | +6.5% | | TOTAL NONCORE | $0.12764 | $0.12586 | ($0.00178) | \-1.4% | | SYSTEM TOTALS | | | | | | System Total (w/o BTS) | $0.58790 | $0.55880 | ($0.02910) | \-4.9% | | Backbone Transportation (BTS) | $0.57976 | $0.89609 | $0.31633 | +54.6% | | System Total w/BTS | $0.64919 | $0.64710 | ($0.00209) | \-0.3% | **INSTANT ANALYSIS:** SoCalGas’s January 1, 2026 consolidated rate update aggregates a wide set of previously authorized adjustments into a modest net systemwide revenue decrease, but this masks a significant reallocation of costs. Annual regulatory account amortizations, updated cost-of-capital, greenhouse gas and climate credit true-ups, leak-abatement funding, and revised gas price forecasts collectively lower overall revenues. But Backbone Transportation Service emerges as the primary cost sink, absorbing a $224.3 million increase. Why is this happening? Pursuant to the Cost Allocation Proceeding framework, the BTS bucket functions as the residual allocator of last resort. While core and noncore distribution classes stabilize, non-volumetric, transmission-driven and integration-related costs are routed to backbone service. Under current CAP assumptions, the BTS class is designated as the only class capable of carrying system-level transmission risk without distorting retail price signals (or violating cost-causation principles). ### MONDAY AGGREGATE: Energization PD; SoCalGas AFR of Electrification Pilot; Wildfire Mitigation PD URL: https://www.calregulatory.com/monday-aggregate-energization-pd-socalgas-afr-of-electrification-pilot-wildfire-mitigation-pd/ Last updated: 2026-01-26T19:51:38.000Z Today’s roundup examines how California’s regulatory framework is reallocating energy-infrastructure risk across utilities, customers, and departed load. - Utilities get potential energization pathways via tariff but connecting customers face interim load restrictions until upgrades arrive. - SoCalGas challenges electrification mandates as procedurally defective. - PG&E absorbs $363 million in disallowed vegetation management costs despite regulatory approval of its mitigation plans. - Bundled customers and departed load face renewed PCIA cost battles. - Gas curtailments gain formal priority structure with year-long implementation buffer. Across these actions, risk is redistributed through tariffs, settlements, and procedural sequencing rather than resolved through new infrastructure investment. ## ENERGIZATION The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K699/591699367.PDF?ref=calregulatory.com) in its Timely Energization docket ([R.24-01-018](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M524/K427/524427971.PDF?ref=calregulatory.com)) that directs PG&E and SCE to establish a standardized, tariffed Standard Offer "Flexible Service Connection" to accelerate customer energization when distribution-level capacity constraints would otherwise delay service. The PD formalizes a bridging mechanism (modeled largely on PG&E’s existing "Load Limiting Letter" practice) that allows customers to receive firm, near-term electrical service by adhering to a utility-defined Limited Load Profile until upstream upgrades are completed. If the PD is ultimately adopted by the Commission, PG&E and SCE would be required to file a joint advice letter within 30 days. The filing would: - Implement the standard offer; - Update tariff rules; - Add customer disclosure and opt-in mechanisms to service application materials; and - Begin collecting detailed cost, performance, and curtailment data to support future refinement. The PD applies only to PG&E and SCE and declines to impose requirements on SDG&E or small multi-jurisdictional utilities at this time. The PD emphasizes speed, safety, and scalability by relying on static load limits, existing engineering practices, and Advanced Metering Infrastructure-based compliance rather than real-time communications or [DERMS](https://www.nrel.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com) integration. The PD keeps the proceeding open to address additional Phase II energization issues, including dynamic Flexible Service Connections and broader process reforms. The earliest the CPUC will consider this item is **February 5**. Comments are due **January 16**. **INSTANT ANALYSIS:** This PD formalizes a standardized/tariffed pathway for PG&E and SCE to serve customers facing distribution constraints by allowing interim service under predefined load limits. In essence, the Commission is turning an informal engineering workaround into a repeatable energization tool, and prioritizing speed and certainty over waiting for upstream upgrades. For large or fast-moving loads, this creates a clearer, earlier option to take service but it does not add physical capacity or resolve underlying distribution shortfalls. --- ## ELECTRIFICATION PILOT SoCalGas filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K814/591814207.PDF?ref=calregulatory.com) of an October 2025 decision ([*D.25-11-009*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K329/588329387.PDF?ref=calregulatory.com)*, see our summary* [*here*](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/)), arguing that the CPUC exceeded its legal authority and violated basic procedural requirements in establishing an electrification pilot for mobilehome parks. SoCalGas contends that the rulemaking was scoped narrowly to improve safety by converting master-metered systems to direct utility service, not to eliminate gas service. Yet, SoCalGas argues, the decision: - Imposed a new electrification initiative; - Ordered decommissioning of existing gas infrastructure; - Required long-term bans on future gas service through recorded land covenants; and - Shifted evaluation costs to gas ratepayers without prior notice or evidentiary support. SoCalGas argues these measures were never identified in scoping memos, staff proposals, or party briefs and therefore deny affected parties due process. SoCalGas further asserts that: - The Commission lacks jurisdiction to impose land-use restrictions or override statutory rights to gas service; - The gas ban is preempted by federal law; and - Forced abandonment of utility assets constitutes an unconstitutional taking. On this basis, SoCalGas asks the Commission to rehear and revise (or vacate) the decision to remove the gas ban, decommissioning mandate, and cross-subsidization requirements. Party responses are due **January 12**. **INSTANT ANALYSIS**: This application for rehearing tees up a procedural vulnerability for the Commission: the electrification pilot, gas decommissioning mandate, and long-term gas ban all appear to have emerged at the proposed-decision stage without being properly scoped or litigated. If the Commission takes rehearing seriously, the cleanest off-ramp is to narrow or sever the gas ban and decommissioning provisions rather than defend a record that never clearly noticed those outcomes. --- ## WILDFIRE MITIGATION A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K179/592179722.PDF?ref=calregulatory.com) in [A.23-12-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M521/K134/521134366.PDF?ref=calregulatory.com) (which is tentatively scheduled for consideration on **February 5**) authorizes PG&E to recover a **$1.416 billion** revenue requirement. This amount includes costs incurred primarily in 2022 related to wildfire mitigation, vegetation management, catastrophic events, and a set of customer-protection and policy-driven memorandum accounts. - The PD approves a broad, largely uncontested settlement resolving all cost categories except vegetation management, and directs PG&E to true-up recovery via the advice-letter process, with offsets for amounts already collected under interim rate relief granted in a 2024 decision ([D.24-09-003](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M540/K476/540476678.PDF?ref=calregulatory.com)). - Most notably, the PD denies recovery of **$363.4 million** in vegetation management costs, finding that PG&E failed to meet the prudent manager standard for that portion of its 2022 spending recorded in the Vegetation Management Balancing Account. - By contrast, the PD approves recovery (via [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K340/592340331.PDF?ref=calregulatory.com)) of: - Wildfire mitigation costs in the Wildfire Mitigation Balancing Account; - Catastrophic event costs associated largely with the 2022 heat events and 2022–2023 winter storms; and - Costs recorded in multiple memorandum accounts covering COVID-era customer protections, disconnections, privacy compliance, climate vulnerability assessments, microgrids, and low-income affordability pilots. The settlement reflects significant reductions from PG&E’s original request, incorporates Cal Advocates’ concerns about customer affordability, and preserves interim collections already underway, with remaining balances to be amortized beginning in March 2026\. Comments are due **January 15**. **INSTANT ANALYSIS:** While the PD authorizes recovery of $1.4 billion for 2022 wildfire mitigation, catastrophic events, and customer-protection programs through a settlement, it draws the line on vegetation management, disallowing $363.4 million for failure to meet the prudent manager standard. The main takeaway for market participants is twofold: - Catastrophic-event and policy-driven memorandum accounts continue to enjoy relatively high settlement tolerance when tied to declared emergencies and explicit CPUC mandates; but - Vegetation management, despite its centrality to wildfire mitigation, remains subject to exacting, post hoc scrutiny, with [Wildfire Mitigation Plan](https://www.cpuc.ca.gov/industries-and-topics/wildfires/utility-wildfire-mitigation-plans?ref=calregulatory.com) approval offering no safe harbor for cost recovery. (This begs the question: Is the Commission more comfortable approving costs after failure over costs that prevent failure?) For utilities, the PD reinforces that execution quality and evidentiary granularity (not just scale or urgency) will determine recoverability in future wildfire-related filings. --- ## PCIA & ERRA REFORM A [new ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K179/592179721.PDF?ref=calregulatory.com) in the Commission's Power Charge Indifference/ERRA reform docket sets the next steps in the Commission’s effort to update and reform Energy Resource Recovery Account and PCIA policies. - The ruling schedules a prehearing conference for **January 23** and directs parties to meet and confer and file a joint prehearing conference statement by **January 16**. The rulemaking contains multiple tracks and has already resolved Track 1 issues related to the Market Price Benchmark via a decision last June ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)). - Track 2 will be narrowed to address an urgent issue that arose in the 2026 ERRA forecast proceedings: how to appropriately value Renewable Energy Credits generated prior to January 1, 2019, when those “pre-2019 banked RECs” are used for bundled service compliance and PCIA calculations in 2026 and later. For the upcoming prehearing conference, the ALJ outlines preliminary issues focused on: - Whether and how costs and benefits associated with pre-2019 banked RECs should be equitably allocated between bundled service customers and customers who later departed bundled service; and - Whether the REC valuation methodology adopted in recent ERRA decisions can (or should) be applied on an industry-wide basis. Parties are invited to propose alternative issue framing, discuss initial positions, comment on the proposed Track 2 schedule, and consider procedural steps that could facilitate settlement, while unrelated matters will be deferred to a potential Track 3 later in 2026\. A proposed decision is envisioned for the **September 3, 2026** voting meeting. **INSTANT ANALYSIS:** This ruling formally narrows Track 2 to a single, high-stakes issue with immediate rate consequences: how pre-2019 banked Renewable Energy Credits are valued when used for bundled-service compliance after customer departures. By elevating this question out of the annual ERRA forecast context, the Commission is indicating discomfort with ad hoc, utility-specific Renewable Energy Credit valuation outcomes and is positioning itself to set an industry-wide precedent that could significantly shift PCIA cost responsibility between bundled customers and departed load. For market participants, the near-term takeaway is that PCIA mechanics tied to legacy RECs are now explicitly in play, with a fast procedural runway and an open invitation for settlement. This creates both downside risk and strategic opportunity for parties that engage early and shape the framing before valuation assumptions harden into CPUC doctrine. --- ## PG&E Curtailment Procedures PG&E filed [Advice Letter 5161-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5161-G.pdf?ref=calregulatory.com) to implement a decision from October ([*D.25-10-042*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K253/586253854.PDF?ref=calregulatory.com)*, summarized* [*here*](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/)), which approved revisions to PG&E’s gas curtailment framework. The advice letter transmits the final tariff language for [Gas Rule 1](https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS%5FRULES%5F1.pdf?ref=calregulatory.com) ("Definitions") and [Gas Rule 14](https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS%5FRULES%5F14.pdf?ref=calregulatory.com) ("Capacity Allocation and Constraint of Gas Service"), along with PG&E’s proposed implementation timeline and a high-level implementation plan. The revised rules establish a new, standardized prioritization structure for gas curtailments intended to align PG&E’s practices with those of other California natural gas utilities. PG&E proposes to implement the new curtailment procedures on **November 1, 2026**, coinciding with the start of the 2026–2027 winter gas season. PG&E explains that this delay is necessary to: - Complete customer notifications; - Coordinate with the CAISO and other grid operators; - Update internal tools and procedures; and - Conduct employee training, while avoiding disruption to the already-completed winter preparedness planning for the 2025–2026 season. Until then, the existing versions of Gas Rules 1 and 14 will remain in effect. PG&E notes that it has already engaged a broad set of stakeholders (including generators, gas storage operators, consumer advocates, and state agencies) and commits to continued updates through its [Pipe Ranger](https://www.pge.com/pipeline/en.html?ref=calregulatory.com) website as implementation progresses. Protests are due **January 20**. **INSTANT ANALYSIS:** Advice Letter 5161-G operationalizes the Commission’s approval of a more stringent and standardized gas curtailment hierarchy, but PG&E’s proposed 2026 implementation date effectively defers the real-world impacts for nearly a full winter cycle. This gives large noncore customers (particularly electric generators and refineries) additional runway to adjust operations and negotiate minimum usage thresholds. The long lead time highlights both the operational sensitivity of gas curtailment reform and the Commission’s continued willingness to sequence gas reliability changes cautiously. ### PG&E Natural Gas Rates for January 1, 2026: Rates Fall on Accounting, Not Reform URL: https://www.calregulatory.com/pg-e-natural-gas-rates-for-january-1-2026/ Last updated: 2026-01-05T01:14:17.000Z ## PG&E Annual Gas True-Up Filing PG&E filed [Advice Letter 5160-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5160-G.pdf?ref=calregulatory.com), seeking CPUC approval of its 2026 Annual Gas True-Up to update gas transportation rates effective **January 1, 2026**. The filing replaces PG&E's preliminary Annual Gas True-Up (*see our summary* [*here*](https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/)), which the CPUC approved earlier this month. Updated forecasts are based on recorded balances through November 30, 2025 and incorporate final, CPUC-authorized revenue requirement changes adopted late in the year. PG&E now proposes total 2026 gas transportation revenue requirements of **$5.676 billion**, a net reduction of **$292 million** from amounts currently in rates, driven primarily by lower end-use transportation revenue requirements and reduced gas Public Purpose Program surcharges, partially offset by higher unbundled storage and backbone costs. | Description | Currently in Rates($ million) | Proposed($ million) | Change($ million) | | --------------------------------------------- | ----------------------------- | ------------------- | ----------------- | | End-Use Gas Transportation | $5,108 | $4,876 | ($232) | | Storage and Backbone Unbundled Costs | 390 | 407 | $17 | | Gas PPP Surcharges | 470 | 393 | (77) | | Total Gas Transportation Revenue Requirements | $5,968 | $5,676 | ($292) | Gas transportation balancing accounts are projected to be undercollected by **$108 million** at year-end 2025 (**$98 million** less than the balances currently being amortized) resulting in downward adjustments to customer class charge components. The Annual Gas True-Up rolls forward a limited set of notable balancing accounts, including: - Core and noncore fixed-cost true-ups (**$37 million** core undercollection; **$67 million** noncore overcollection), which drive much of the net end-use transportation reductions - Hazardous substance cost recovery (**$102 million** to be collected system-wide); this is one of the largest discrete adders embedded in transportation rates - Revenue-sharing mechanisms (a **$70 million** overcollection returned to customers); this contributes significantly to a downward pressure on rates - Uncollectibles and affordability programs (tens of millions in aggregate); this reflects continued credit stress without establishing a new cost baseline - Biomethane administration (low, single-digit millions); this is directionally notable but immaterial to overall rate movement - Wildfire-related adjustments ($14 million in cost recovery, partially offset at transmission); this activity is mostly normalized into base true-ups now rather than considered exceptional - Approved capital program impacts such as Gas AMI ($40.6 million distribution and $3.9 million transmission). The filing excludes 2026 core gas procurement costs, which are addressed separately in PG&E’s concurrent procurement advice letter, which is summarized directly after this item. __PG&E – January 1, 2026Average End-User Natural Gas Transportation Rates and PPP Surcharges ($/th, Annual Class Averages)__ | Customer Class | September 2025 | January 2026 | Change % | | | | | | | | | | | | | | | -------------------------------------- | -------------- | ------------ | --------- | ------ | ------ | ------ | ------- | | -------- | ------ | - | ------ | ------ | - | ------ | ------ | | Transport | PPPS | Total | Transport | PPPS | Total | | | | | | | | | | | | | Retail Core | | | | | | | | | | | | | | | | | | Residential Non-CARE | $2.261 | $0.143 | $2.404 | $2.155 | $0.121 | $2.276 | \-5.3% | | | | | | | | | | | Small Commercial Non-CARE | $1.483 | $0.128 | $1.612 | $1.374 | $0.106 | $1.480 | \-8.2% | | | | | | | | | | | Large Commercial | $0.924 | $0.104 | $1.028 | $0.810 | $0.085 | $0.894 | \-13.0% | | | | | | | | | | | NGV1 (uncompressed) | $0.975 | $0.062 | $1.037 | $0.861 | $0.048 | $0.909 | \-12.3% | | | | | | | | | | | NGV2 (compressed) | $2.618 | $0.062 | $2.679 | $2.534 | $0.048 | $2.583 | \-3.6% | | | | | | | | | | | Retail Noncore | | | | | | | | | | | | | | | | | | Industrial – Distribution | $0.800 | $0.153 | $0.953 | $0.608 | $0.128 | $0.736 | \-22.7% | | | | | | | | | | | Industrial – Transmission | $0.408 | $0.082 | $0.490 | $0.339 | $0.066 | $0.405 | \-17.4% | | | | | | | | | | | Industrial – Backbone | $0.163 | $0.082 | $0.245 | $0.126 | $0.066 | $0.191 | \-21.8% | | | | | | | | | | | Electric Generation – Transmission | $0.410 | — | $0.410 | $0.344 | — | $0.344 | \-16.0% | | | | | | | | | | | Electric Generation – Backbone | $0.177 | — | $0.177 | $0.139 | — | $0.139 | \-21.8% | | | | | | | | | | | NGV4 Distribution (uncompressed) | $0.800 | $0.062 | $0.862 | $0.608 | $0.048 | $0.656 | \-23.9% | | | | | | | | | | | NGV4 Transmission (compressed) | $0.394 | $0.062 | $0.456 | $0.329 | $0.048 | $0.378 | \-17.1% | | | | | | | | | | | Wholesale Core & Noncore | | | | | | | | | | | | | | | | | | Alpine Natural Gas | $0.265 | — | $0.265 | $0.262 | — | $0.262 | \-1.0% | | Coalinga | $0.266 | — | $0.266 | $0.264 | — | $0.264 | \-0.9% | | Island Energy | $0.283 | — | $0.283 | $0.284 | — | $0.284 | +0.2% | | | | | | | | | | | Palo Alto | $0.260 | — | $0.260 | $0.257 | — | $0.257 | \-1.4% | | | | | | | | | | | West Coast Gas – Castle | $0.717 | — | $0.717 | $0.577 | — | $0.577 | \-19.5% | | | | | | | | | | | West Coast Gas – Mather (Distribution) | $1.032 | — | $1.032 | $0.792 | — | $0.792 | \-23.3% | | | | | | | | | | | West Coast Gas – Mather (Transmission) | $0.268 | — | $0.268 | $0.266 | — | $0.266 | \-0.8% | | | | | | | | | | Protests are due **January 12**. **INSTANT ANALYSIS:** In this filing, gas affordability is being expressed almost entirely through balancing-account hydraulics rather than new CPUC direction. The rate impacts here reflect downstream true-ups of prior policy decisions, not fresh Commission judgment, namely: - **Cost of Capital Reset**: The CPUC's 2026 cost-of-capital decision ([*D.25-12-043*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K833/591833054.PDF?ref=calregulatory.com)*; see our summary* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)) lowered the return applied to authorized gas rate base. That directly compresses fixed-cost recovery and is one of the largest drivers of the end-use transportation decline in this true-up filing. - **General Rate Case Attrition Mechanics**: The CPUC's GRC and adopted attrition formulas set what costs are allowed; how quickly they escalate; and how much lag is embedded. Those mechanics determine how over- and undercollections accumulate. The true-up filing is merely draining (or refilling) the reservoirs those rules created. - **Public Purpose Program Normalization:** PPP surcharges were already reset in [AL 5138-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5138-G.pdf?ref=calregulatory.com) (*see our summary* [*here*](https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/)). The true-up filing just reconciles balances and CARE offsets, contributing $77 million worth of downward pressure. - **Capital Program Authorizations (Gas AMI, Safety, Wildfires)**: Capital program costs such as Gas Advanced Metering Infrastructure (*see* [*D.25-12-029*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M592/K188/592188326.PDF?ref=calregulatory.com)*, summarized* [*here*](https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/)), wildfire mitigation, and safety investments were first tracked in memorandum accounts and later authorized for recovery, at which point they were transferred into balancing accounts and flowed through rates via the true-up submission. At the implementation layer, these costs function as non-discretionary pass-throughs: the Commission's policy judgment has already been made, and the true-up's role is limited to mechanical reconciliation and allocation. - **Depreciation Lives and Asset Treatment**: Longer depreciation lives and restrained asset growth temper near-term revenue requirements, even as policy fights over gas system contraction continue elsewhere. In short, the CPUC has deferred difficult gas-planning choices and let depreciation do the smoothing. --- ## PG&E Procurement Filing PG&E’s [Advice Letter 5159-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5159-G.pdf?ref=calregulatory.com) submits routine but consequential revisions to its gas tariffs to implement updated core procurement and transportation rates effective **January 1, 2026**. The filing updates gas procurement charges for residential, small commercial, large commercial, and natural gas vehicle core customers, reflecting a lower weighted-average cost of gas compared to the prior month, alongside several short-term amortization surcharges to true up under-collections in the Purchased Gas Account and related subaccounts. These include recoveries for prior under-collections tied to: - Core sales, reflecting PG&E’s procurement of gas on behalf of its core customers; - Shrinkage, which captures the difference between gas entering PG&E’s system and gas ultimately billed, including physical losses, measurement error, and unaccounted-for gas; - Firm storage, reflecting contracted storage capacity used to manage seasonal swings and ensure winter deliverability; - Pipeline demand charges, which are fixed reservation fees paid to interstate and intrastate pipelines to secure firm transportation capacity regardless of actual throughput; and - PG&E’s winter hedging program, which relies on financial instruments and physical hedges to limit exposure to winter price spikes. Consequently, procurement charges vary modestly by customer class based on capacity cost allocation, with residential core procurement set at **$0.63850/therm** and lower levels for larger commercial and natural gas vehicle customers. __Schedule G-CP Procurement Charge ($/therm) – January 2026__ | Customer Class | Residential(G-1, GM, GS, GT, GL-1, GML, GSL, GTL) | Residential(G1-NGV, GL1-NGV) | Small Commercial(G-NR1) | Large Commercial(G-NR2) | Natural Gas Vehicles(G-NGV1/2) | | -------------------------------- | ------------------------------------------------- | ---------------------------- | ----------------------- | ----------------------- | ------------------------------ | | **Procurement Charge ($/therm)** | $0.63850 | $0.59352 | $0.59538 | $0.55349 | $0.54800 | In parallel, Advice Letter 5159-G incorporates updated core transportation rates and Public Purpose Program surcharges that are being established through PG&E’s Annual Gas True-Up filing (summarized above). Protests are due **January 12**. **INSTANT ANALYSIS:** This filing shows how January 1 gas rate movement is being produced. Procurement charges ease because the weighted-average cost of gas declined month over month, with that relief partially offset by amortizations clearing prior under-collections tied to core sales, shrinkage, storage, pipeline reservations, and winter hedging. Rate changes are therefore coming from fuel price normalization layered on top of balance-account cleanup rather than changes to service scope. Viewed alongside PG&E’s Annual Gas True-Up, the pattern reveals broader gas cost recovery trends: falling throughput is concentrating fixed capacity costs into frequent true-ups and amortizations. For market participants, the focus is not new investment, but the pace of under-collection clearance, the treatment of hedging costs, and how much discretion remains in future recovery cycles. ### CPUC Sets Scope for Sempra Utilities’ Gas Cost Allocation Proceeding Covering 2027–2029 Rates URL: https://www.calregulatory.com/cpuc-sets-scope-for-sempra-utilities-gas-cost-allocation-proceeding-covering-2027-2029-rates/ Last updated: 2025-12-24T04:29:18.000Z CPUC Commissioner **John Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K310/592310495.PDF?ref=calregulatory.com) for the Sempra Utilities' Cost Allocation Proceeding, or "CAP" [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K104/582104341.PDF?ref=calregulatory.com). In the CAP, SoCalGas/SDG&E seek Commission approval to reallocate gas service, transportation, and storage costs across core and noncore customer classes at a time when gas demand is forecast to decline but overall revenues and transportation-related costs are expected to rise. The scoping memo identifies a wide range of contested issues, including: - Whether the proposed rate changes and cost allocations align with cost-causation principles; - How residential customer charges affect affordability; - How gas storage capacity at facilities such as Aliso Canyon should be allocated and reduced; and - Whether various accounting, balancing, and cost recovery mechanisms should continue or be modified. ### CAP Context: Potential Rate Impacts [As reported by CRI on November 12](https://www.calregulatory.com/wednesday-aggregate/), the Southern California Generation Coalition (SCGC) protested the CAP filing, contending that SoCalGas misleadingly compares its proposed 2027–2029 rates to “normalized” September 2025 rates (rather than actual), giving a false impression of decreases. According to SCGC’s analysis, certain rates (e.g., electric-generation transmission-level service) would actually *increase* **23%** under the proposal. SCGC also challenged SoCalGas’s plan to replace the storage and balancing regime adopted in the 2024 CAP settlement, noting reductions in total storage inventory, injection, and withdrawal capacities without sufficient justification. Other parties, as reported by CRI[ here](https://www.calregulatory.com/monday-aggregate-socalgas-cap-rates-iou-distribution-planning-the-future-of-cas-base-services-charge/), also take issue with the CAP filing. A common refrain includes distrust of the Sempra Utilities' embedded-cost framework and skepticism toward their proposal of an accelerated schedule. Activity heats up in late spring and goes full tilt in the summer. Intervenor testimony is due **May 15**, with rebuttal testimony due **June 15**. A status conference will convene on **June 22**. Evidentiary hearings, if needed, will convene on **July 20-24**. As a reminder, the Sempra Utilities provided the following illustrative rate impacts with their application. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/SDG-E-screenshot.png) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/socalgas-screenshot-table.png) **INSTANT ANALYSIS**: The scoping memo sets a procedural roadmap for the CAP but confirms that the CPUC obviously views this proceeding as the venue for a potential re-litigation of gas cost allocation, storage policy, and affordability under declining demand conditions. By explicitly acknowledging cost-causation alignment, residential bill impacts, storage capacity reductions, and the continued use of embedded-cost and balancing-account frameworks as contested issues, the CAP looks to become a significant battlefield. ### SDG&E Backs Petition to Lift EV Infrastructure Spending Cap URL: https://www.calregulatory.com/sdg-e-backs-petition-to-lift-ev-infrastructure-spending-cap/ Last updated: 2025-12-23T21:24:44.000Z SDG&E filed a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K672/591672913.PDF?ref=calregulatory.com) supporting a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K345/588345879.PDF?ref=calregulatory.com) (PFM), where multiple parties (Electrify America, the Natural Resources Defense Council, Walmart, Advanced Energy United, *et al*) seek to modify the CPUC's decision addressing SoCalGas/SDG&E's 2024 General Rate Case ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)). In their PFM, the petitioners argue that the CPUC should remove the **$7.58 million** funding cap imposed on the Electric Vehicle Infrastructure Memorandum Account (EVIMA) associated with [Electric Rule 45](https://www.sdge.com/business/electric-vehicles/lovelectric/ev-infrastructure-rule?ref=calregulatory.com). In supporting the PFM, SDG&E contends the cap was based on a misunderstanding of project status and accounting mechanics, noting that while many Rule 45 EV charging projects were in development, costs are not booked until projects are energized, making early balances appear artificially low. SDG&E argues that capping a memorandum account is inconsistent with standard regulatory practice, conflicts with the Public Utilities Code, and prematurely constrains a legislatively mandated EV infrastructure program critical to fleet and public charging deployment. SDG&E maintains that any substantive policy changes to Rule 45 should be addressed in a statewide transportation electrification rulemaking (not embedded in a single utility’s General Rate Case). It warns that the cap has already disrupted customers and developers, skewed data collection intended to inform future EV policy, and forced SDG&E to temporarily close Rule 45\. **INSTANT ANALYSIS:** This filing demonstrates how General Rate Cases are becoming a primary tool for the CPUC to place practical limits on utility-side transportation electrification, even where programs are grounded in statute. If the $7.58 million EVIMA cap remains in place, Rule 45 effectively becomes a rationed, stop-and-go program, creating uncertainty for fleet operators, charging developers, and large load customers planning medium- and heavy-duty electrification in SDG&E territory. The dispute highlights rising Commission skepticism toward uncapped memorandum accounts and a willingness to impose hard spending constraints through rate cases rather than dedicated policy rulemakings. ### PG&E Update: 2026 Base Revenue Requirement Filing & the December 1, 2025 Diablo Canyon Oral Argument in Review URL: https://www.calregulatory.com/pg-e-update-diablo-c/ Last updated: 2025-12-24T00:35:34.000Z ## ## BASE REVENUE REQUIREMENT PG&E filed [Advice Letter 5155-G/7791-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5155-G.pdf?ref=calregulatory.com) to update its 2026 base revenue requirements effective January 1, 2026\. The filing implements revenue levels previously authorized by the CPUC across electric distribution, electric generation, gas distribution, and gas transmission and storage. These levels represent an increase of **$174 million** from 2025 (*see Attachment 1, which provides a rolling, decision-by-decision reconciliation of PG&E’s adopted base revenue requirements from its 2023 GRC through the 2026 attrition year*). The filing reflects a total 2026 base revenue requirement of approximately **$15.1 billion**, incorporating approved General Rate Case attrition, pension updates, and a series of discrete Commission-directed adjustments. Key drivers include implementation of the 2023 General Rate Case decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)), updates from the [2026 Cost of Capital decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com) authorizing a 9.98% ROE, and a net revenue requirement decrease tied to [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com) wildfire hardening securitization. The advice letter also reflows revenue requirements to reflect the shift to a Non-Wildfire Self-Insurance Fund, incorporates permanent disallowances related to the [2015 Butte Fire](https://en.wikipedia.org/wiki/Butte%5FFire?ref=calregulatory.com), and true-up impacts from prior hydroelectric asset sales (Tule River, Deer Creek, and Chili Bar). The AL's updates will be incorporated into PG&E's annual electric and gas true-ups. Protests are due **January 12**. | Line No. | Revenue Requirements ($000s) | 2026 GRC | 2025 Pension | Total | | -------- | ---------------------------- | ----------- | ------------ | ----------- | | 1 | Electric Distribution | $8,510,717 | $81,329 | $8,592,047 | | 2 | Gas Distribution | $3,057,399 | $42,969 | $3,100,369 | | 2 | Electric Generation | $1,193,610 | $30,252 | $1,223,862 | | 3 | Gas Transmission & Storage | $2,169,032 | $20,480 | $2,189,512 | | 4 | Total | $14,930,759 | $175,031 | $15,105,790 | **INSTANT ANALYSIS:** This is a procedural filing but also a consequential implementation step that aggregates prior CPUC decisions into PG&E’s effective 2026 revenue baseline. AL 5155-G/7791-E defines the starting point for 2026 electric and gas rates. --- ## DIABLO CANYON ORAL ARGUMENT As [previously reported at CRI](https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/), the Commission adopted a final decision in PG&E's latest Diablo Canyon cost-recovery proceeding ([A.25-03-015](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M560/K829/560829330.PDF?ref=calregulatory.com)) on December 4\. For added context and posterity, we have summarized the proceeding's December 1 [oral argument](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827604.PDF?ref=calregulatory.com) (OA) below. --- At the OA, PG&E urged adoption of the CPUC's then-[pending proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820128.PDF?ref=calregulatory.com), which recommended authorizing PG&E's request to recover **$382.233 million** in rates to support continued operations at the Diablo Canyon Power Plant. PG&E argued that the PD faithfully implemented [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com) by: - Properly distinguishing transition costs from extended-operations costs; - Adopting the "[Consumer Price Index for All Urban Consumers](https://fred.stlouisfed.org/series/CPIAUCSL?ref=calregulatory.com)" (CPI-U) methodology to escalate the fixed management fee from 2022 dollars; and - Approving its 2026 Volumetric Performance Fee spending plan as consistent with statutory public-purpose priorities such as grid reliability, safety, and decarbonization. Opponents, led by the [Alliance for Nuclear Responsibility](https://a4nr.org/?ref=calregulatory.com), [TURN](https://www.turn.org/?ref=calregulatory.com), and EPUC, argued that the proposed decision: - Effectively rubber-stamped PG&E’s requests; - Allowed improper cost shifting from government funding to ratepayers through project rescheduling; - Approved a retroactive and cumulative escalation of the fixed management fee that violates Commission precedent and statute; and - Inadequately scrutinized Volumetric Performance Fee spending that could inflate shareholder compensation and undermine affordability. [Californians for Green Nuclear Power](https://cgnp.org/?ref=calregulatory.com) and the Coalition of California Utility Employees supported the PD, emphasizing Diablo Canyon’s reliability, safety, zero-emissions attributes, and grid-stabilizing benefits. They asserted that the Volumetric Performance Fee framework and affordability guidance were correctly applied as policy encouragement rather than enforceable legal constraints. Rebuttal arguments focused on whether the Commission’s role is limited to administering SB 846’s cost-recovery mechanics as written, or whether it must aggressively police cost effectiveness, escalation methods, and cross-subsidization to protect ratepayers. ### MONDAY NEWS CODEX: Wind Farm Project Denied; PG&E Restoration Efforts; Public Purpose Program URL: https://www.calregulatory.com/monday-news-codex-wind-farm-project-denied-pg-e-restoration-efforts-public-purpose-program/ Last updated: 2025-12-23T16:43:09.000Z - **A Path to Fast, Cheap Home Solar and Batteries – Go Through the Meter:** "One of the most effective such tools is called the meter socket adapter — and major home-electrification companies are increasingly making use of it. Over the past few years, companies including [Tesla](https://www.tesla.com/support/energy/powerwall/learn/tesla-backup-switch?ref=calregulatory.com), [ConnectDER](https://connectder.com/?ref=calregulatory.com), and [Enphase](https://enphase.com/store/storage/gen4/iq-meter-collar?ref=calregulatory.com) have won approval from a growing number of utilities to use these devices to circumvent complex electrical work that can add days of labor and thousands of dollars in costs to installations. Recent [regulatory momentum in California](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-advances-building-decarbonization-with-customer-focused-reforms?ref=calregulatory.com), the largest home solar market, is also boosting the tech, which takes the form of a metal ring that’s inserted between utility meters and the meter boxes that connect homes to the grid." [**CANARY MEDIA**](https://www.canarymedia.com/articles/distributed-energy-resources/a-path-to-fast-cheap-home-solar-and-batteries-go-through-the-meter?ref=calregulatory.com) - **A Wildfire is Coming for Electricity Bills:** "California offers a cautionary tale — both about what happens when you don’t prepare for fire, and how high those costs can get. Since 2018, the state [has spent tens of billions](https://www.independent.com/2024/12/06/californians-pay-billions-for-power-companies-wildfire-prevention-efforts-are-they-cost-effective/?ref=calregulatory.com) to pay for the aftermath of those blazes that utilities did start and remake its grid for a new era of fire. Yet it took years for those costs to pass through to customers." [**HEATMAP**](https://heatmap.news/energy/wildfires-electricity-bills?ref=calregulatory.com) - **California's Gas Market May No Longer Need to be an Energy Island:** "The proposed Western Gateway Pipeline, which would be the world’s largest fuel conduit, would [not only transport gasoline, but also jet fuel and diesel](https://www.msn.com/en-us/money/markets/phillips-66-boss-says-major-pipeline-project-has-broad-support/ar-AA1StLUO?ocid=finance-verthp-feeds&ref=calregulatory.com). According to *Bloomberg*, the pipeline network would cross from Illinois through Oklahoma, Texas, New Mexico, Arizona, and Nevada to California and adjacent markets, with connectivity to Las Vegas, Nevada. Much of the pipeline would be built along or utilize existing Kinder Morgan conduits, with a new section across New Mexico. The section of the pipeline that would cross near Mescalero Apache land in New Mexico has received buy-in from local tribes, but past endeavors at building pipelines have often been caught up in lawsuits and protests." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/californias-gasoline-market-may-no-longer-need-to-be-an-energy-island/?ref=calregulatory.com) - **California PUC Lowers Utilities' Return on Equity by 0.3 Percentage Points:** "PG&E’s ROE is now 9.98%, down from 10.28%, San Diego Gas & Electric’s is now 9.93%, down from 10.23%, Southern California Gas is down to 9.78% from 10.08%, and Southern California Edison’s is now 10.03%, down from 10.33%. California has some of the highest rates in the country, second only to Hawaii." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-public-utilities-commission-return-equity-wildfires/808346/?ref=calregulatory.com) - **California Utilities Will Keep Almost All Profits as Regulators Ease Up – They're Still Upset:** "The shareholder profits are a percentage of a utility’s 'rate base' – the total value of its assets that it can earn a return on. This includes things such as power plants. While a utility’s approved shareholder returns fluctuate, the rate bases for California’s three utilities steadily rise. Each utility’s rate base is billions of dollars, earning hundreds of millions for shareholders even if a utility doesn’t reach its full shareholder return. In 2023, for example, Edison had a rate base of $29.7 billion, and it was allowed to earn $198 million for shareholders that year. If its approved return was one percentage point lower, it would still have been allowed to earn $178 million for shareholders. Though it came in far short of this that year, it still brought shareholders $91 million from ratepayers." [**CAL MATTERS**](https://calmatters.org/economy/2025/12/regulators-cut-electric-bill-profits/?ref=calregulatory.com) - **Contentious Wind Farm Project in Shasta Denied by California Panel**: "The California Energy Commission on Friday denied the approval of the Fountain Wind project, ending a years-long battle by Shasta County to stop the controversial project from moving forward. At its business meeting in Sacramento, the CEC adopted the recommendation of its executive director not approve the project." [ **RECORD SEARCHLIGHT**](https://www.redding.com/story/news/local/2025/12/20/california-energy-commission-denies-shasta-county-fountain-wind-farm/87853324007/?ref=calregulatory.com) - **Kinder Morgan, Phillips 66 Advance Western Gateway Pipeline to California Markets:** "Supply for the system would originate from refined products connected at Borger, as well as volumes already tied into the SFPP system in El Paso, Texas. In addition, the Phillips 66-operated Gold Pipeline, which currently moves products from Borger to St. Louis, would be reversed to direct Midcontinent refinery supply toward Borger for delivery into the Western Gateway system." [**PIPELINE & GAS JOURNAL**](https://pgjonline.com/news/2025/december/kinder-morgan-phillips-66-advance-western-gateway-pipeline-to-california-markets?ref=calregulatory.com) - **PG&E Continues Restoration Efforts Following Substation Fire Impacting 130,000 Customers:** "The cause of the substation fire has not been released, as there will most likely be an investigation and report. As our industry knows, substation fires are most often triggered by equipment failures, such as overheating, insulation breakdown or loose connections. These can lead to arcing or overloading. Oil-filled power transformers pose the largest fire risk in any substation, according to [a 2019 report](https://www.tdworld.com/substations/article/20972327/fire-protection-in-substation-transformers?ref=calregulatory.com) from David Petersile of Burns & McDonnell and Bill Mackay of Advanced Safety Systems." [**T&D WORLD**](https://www.tdworld.com/disaster-response/news/55339945/pge-continues-restoration-efforts-following-substation-fire-impacting-130000-customers?ref=calregulatory.com) - **Power Brokers – What's Really Behind Your Soaring Utility Bills:** "Even the most troubled utilities seem untouchable. Pacific Gas and Electric Company serves central and northern California, where its malfunctioning infrastructure bore primary responsibility for several enormously destructive wildfires, including the 2018 Camp Fire, which caused billions of dollars in damage and killed eighty-­five people. Massive liabilities forced the company into bankruptcy, and its credit rating was downgraded to 'junk,' well below the benchmark for investment-­grade stocks. Despite all this, ­PG&E seems to be getting by. In 2024, the utility reported $2.5 billion in profit, an all-time high." [**HARPERS**](https://harpers.org/archive/2026/01/power-brokers-nick-bowlin-utility-bills/?ref=calregulatory.com) - **"The Biggest Transformation in a Century" – How California Remade Itself as a Clean Energy Powerhouse**: "'You’re going to see California fiercely litigating every single effort of the federal government to undo the fight against climate change and the fight against clean energy,' said **Noah Perch-Ahern**, an environmental attorney. 'I think that’s going to continue for years.'" [**THE GUARDIAN**](https://www.theguardian.com/us-news/2025/dec/20/california-renewable-energy?ref=calregulatory.com) - **The Public Purpose Program – California's Hidden Tax Driving Up Utility Bills:** "There are a multitude of remedies for this problem, many of which do not require the cancellation of the various PPP-funded programs. The legislature could choose to fund these programs through the [general fund](https://calbudgetcenter.org/resources/a-guide-to-the-california-state-budget-process/?ref=calregulatory.com), financed primarily by direct income and sales tax, instead of utility bills. Furthermore, lawmakers could require clearer labeling of all taxes and surcharges on bills, known as 'truth in billing,' which would increase transparency for utility companies passing costs onto consumers. This solution would solve the 'hidden' problem, but would not reduce the ultimately redistributive outcome of the program itself. Whatever the remedy might be, families deserve to know what they’re actually paying for, and who decided to impose those charges." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/will-the-delta-pumps-operate-at-capacity-this-winter/?ref=calregulatory.com) - **Why Energizing EV Chargers Takes So Long – and What We've Learned About Fixing It:** "California is the first state to pilot regulatory mechanisms to improve energization timelines, prompted by legislation that directs regulators to address growing request backlogs and slow energization processes. Building on this precedent, other states, including [Colorado](https://link.irecusa.org/3v28kyZ?ref=calregulatory.com) and [Illinois](https://link.irecusa.org/2CqUOW8?ref=calregulatory.com), have enacted or are in the process of enacting legislation that requires regulators to adopt energization timelines. While California’s actions are a good first step, it is unclear if these targets will result in [short enough timelines to keep pace with EVSE demand](https://link.irecusa.org/JZGXEH?ref=calregulatory.com) because they are based on historic energization timeframes, which have already resulted in backlogs. To ensure the established timelines are effective, regulators should establish mechanisms to evaluate their performance. This includes setting an appropriate reporting cadence and defining what data must be tracked and reported. Data tracking and mandated timelines work together, and both must be carefully designed to support accountability for energization timelines. " [**RENEWABLE ENERGY WORLD** ](https://www.renewableenergyworld.com/electric-vehicle/ev-charging/why-energizing-ev-chargers-takes-so-long-and-what-weve-learned-about-fixing-it/?ref=calregulatory.com) ### MONDAY AGGREGATE: Capital Recovery & Attrition Design; Decarbonization Cost Allocation; Gas System Continuity w/o New Assets URL: https://www.calregulatory.com/monday-aggregate-capital-recovery-attrition-design-decarbonization-cost-allocation-gas-system-continuity-w-o-new-assets/ Last updated: 2025-12-22T22:15:29.000Z Capital-recovery mechanics dominate today’s report, with utilities pressing on opposite edges of the same constraint: how to fund authorized investment while limiting long-lived gas exposure. SoCalGas/SDG&E challenge a one-part attrition design they say strands **$5 billion** in capital, while PG&E and Stanpac advance a consolidation proposal deliberately structured to avoid new assets. In parallel, SoCalGas frames biomethane procurement as a systemwide cost obligation, and SCE continues routine real-estate downsizing. --- ## SEMPRA UTILITIES' RATES SoCalGas/SDG&E (the Sempra Utilities) filed a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K986/590986352.PDF?ref=calregulatory.com) of a 2024 decision ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)), which resolved the Sempra Utilities' 2024 General Rate Case by setting a test-year revenue requirement and establishing how rates would be adjusted in the following post-test years (2025–2027). - For the post-test period, D.24-12-074 adopted a single post-test-year attrition mechanism that increases the authorized base margin revenue requirement by 3% annually, covering both operating and maintenance expenses and capital-related costs. Rather than separately updating rates to reflect actual capital additions placed into service after the test year, the Commission relied on this uniform escalation to manage rate growth and limit volatility between general rate cases. - In doing so, the Commission emphasized that post-test-year ratemaking is not intended to replicate a full test-year review, but to provide a streamlined adjustment that supports financial stability while maintaining just and reasonable rates for customers. - The decision reflected a policy judgment that a fixed escalation, combined with other authorized mechanisms and future rate cases, is sufficient to balance utility revenue needs with ratepayer protections during attrition years, even as capital investment continues under previously approved programs. ### Petition for Modification SoCalGas/SDG&E argue that the authorized post-test-year ratemaking mechanism unintentionally prevents them from recovering Commission-approved capital costs during the 2025–2027 period. - The petition explains that the decision adopted a one-part attrition mechanism, and in the utilities' view, the mechanism is based on factual misconceptions and does not function as the Commission intended. The companies argue that capital costs and O&M expenses affect revenue requirements differently, and a single escalation factor fails to account for new capital additions placed into service after the test year or for capital projects with mid- or late-test-year in-service dates. - Consequently, SoCalGas/SDG&E argue they are unable to recover depreciation, taxes, or a return on billions of dollars of authorized and largely recurring capital investments, creating what they describe as **$5 billion** in missing capital cost recovery over the GRC cycle. - The petition points to recent Commission precedent (including PG&E’s and SCE’s GRC decisions – [D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com) and [D.25-09-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M580/K788/580788967.PDF?ref=calregulatory.com), respectively) where two-part attrition mechanisms were adopted to separately address O&M and capital, and asserts there is no policy basis for treating SoCalGas and SDG&E differently. - The utilities request that the Commission modify D.24-12-074 to adopt a two-part post-test-year mechanism that separately funds capital additions using a seven-year average of recorded and forecast capital expenditures, escalated by 3%, and to implement the change through amortization beginning in 2026\. The utilities assert that this correction is necessary to preserve the regulatory compact, maintain financial integrity, and avoid adverse impacts on safety, reliability, credit quality, and customers. Responses are due **January 16**. **INSTANT ANALYSIS**: SoCalGas/SDG&E are asking the Commission to revisit a fundamental ratemaking design choice in D.24-12-074, arguing that the one-part, 3% post-test-year escalation does not track the capital investments the Commission authorized in the GRC. The petition presents the issue as a structural correction rather than a rate increase and cites recent GRC decisions where the Commission adopted two-part attrition mechanisms, putting consistency in post-test-year capital treatment directly at issue. The filing will test how the Commission intends to handle capital recovery mismatches between rate cases in the current moment. --- ## GAS SYSTEM CONTINUITY PG&E and Standard Pacific Gas Line Incorporated (Stanpac) filed a joint [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K827/591827586.PDF?ref=calregulatory.com) with the CPUC seeking approval for a multi-part transaction that would: - Transfer substantially all of Stanpac’s remaining gas transmission pipeline assets to PG&E; - Restructure how Chevron receives gas transportation service; and - Ultimately wind down the nearly century-old Stanpac joint venture. Under the proposal, PG&E would acquire Stanpac’s core pipelines and related facilities for **$150.4 million**, effectively paying about **$21.5 million** to buy out Chevron’s 1/7 ownership interest, while recovering only a limited portion of the net book value from ratepayers. Stanpac would remain in existence for a 20-year transition period, during which it would contractually provide up to **30.7 MMcf/d** of gas transportation service to Chevron using PG&E’s integrated system under new transportation and inter-utility service agreements, avoiding more than **$100 million** in otherwise necessary pipeline upgrades. The filing states: > PG&E thus will have a larger supply of gas in its system than it historically has had. Once PG&E receives this gas into its system, the gas would intermingle with PG&E’s gas, and flow east and northeast toward Lodi and Sacramento for the benefit of PG&E’s customers in those areas. Simultaneously, PG&E will flow a like quantity of gas westward from its backbone partially through PG&E’s legacy transmission system and partially through the acquired Stanpac assets, and deliver that gas at Chevron’s Richmond refinery. Accordingly, PG&E will have a greater supply of gas in its system as a result of the Transaction, which will help PG&E manage gas supply throughout the area. PG&E argues the transaction produces significant customer savings, improves gas system operations, aligns with state decarbonization and gas-transition policies by avoiding new long-lived gas investments, and sets a firm end date for the Stanpac joint venture. Following that end date, PG&E would acquire Chevron’s remaining stock for a nominal amount and seek to dissolve Stanpac entirely. Protests/responses are due **January 21**. **INSTANT ANALYSIS**: This filing will test how far the Commission is willing to approve gas-system continuity measures that explicitly avoid new capital investment, relying instead on asset consolidation and long-dated transition contracts. The proposal aligns operational necessity with the Commission’s broader preference to limit long-lived gas assets, suggesting that regulatory acceptance may hinge less on system optimization than on whether future reinvestment is structurally foreclosed. --- ## BIOMETHANE PROCUREMENT SoCalGas filed two advice letters (6574-G and 6575-G, available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to obtain CPUC approval of separate biomethane procurement agreements executed under its 2025 [Senate Bill](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com) 1440 Biomethane Request for Offers. - In AL 6575-G, SoCalGas requests approval of a biomethane procurement agreement with [Anaergia Services dba Riverside Bioenergy Facility, LLC](https://americanbiogascouncil.org/anaergia-announces-agreement-to-provide-epc-and-om-services-for-project-in-riverside-california/?ref=calregulatory.com), covering biomethane produced from landfill-diverted organic waste and wastewater through anaerobic digestion. - In AL 6574-G, SoCalGas seeks approval of a similar agreement with BioTech Energy dba [Imperial Valley Green Energy Partners, LLC](https://www.bizprofile.net/ca/el-centro/imperial-valley-green-energy?ref=calregulatory.com), which would supply biomethane produced from landfill-diverted organic waste and dry dairy manure. Both contracts would help SoCalGas meet its short-term SB 1440 procurement obligations and contribute to longer-term Renewable Gas Standard targets through 2030\. SoCalGas asserts that the contracts: - Arose from a competitive, CPUC-approved solicitation process; - Comply with detailed environmental, safety, and operational requirements (including limits on hydrogen sulfide, vehicle emissions standards, and methane leak remediation); and - Include reasonable terms for ratepayers. SoCalGas also requests authorization to recover above-market biomethane procurement costs in rates via its existing biomethane balancing account framework, with costs allocated on a non-bypassable, volumetric equal-cents-per-therm basis to **all** gas end-use customers. Notably, this method of recovery is subject to further refinement in the CPUC's ongoing cost-allocation rulemaking ([R.22-12-011](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K216/500216057.PDF?ref=calregulatory.com)). Protests are due **January 12**. **INSTANT ANALYSIS:** These advice letters show SoCalGas advancing SB 1440 biomethane procurement ahead of the 2025 landfill-diversion deadline while the center of gravity shifts to cost allocation. The contracts themselves are largely procedural but the real leverage point is SoCalGas’s explicit push to allocate above-market biomethane costs to all end-use customers on a non-bypassable, cents-per-therm basis. With R.22-12-011 still unresolved, the filings frame biomethane as a systemwide decarbonization obligation rather than a niche compliance tool, which ramp up disputes over exemptions, core transport agent treatment, and how broadly the Commission will spread costs as overall gas demand declines. --- ## SCE PROPERTIES SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M592/K179/592179677.PDF?ref=calregulatory.com) seeking authority to sell its North Coast office property, located at 28460 Avenue Stanford in Santa Clarita, to a private purchaser for approximately **$7.21 million**. SCE explains that the property, an underutilized two-acre office site formerly used by its Transmission and Distribution staff, is no longer needed due to workforce consolidation and hybrid work practices, with affected employees relocating to nearby SCE facilities. After marketing the property through a competitive process, SCE determined that the selected cash offer with limited contingencies represented the most favorable and least risky alternative, compared with holding the property or waiting for a stronger office market. The sale is expected to reduce long-term O&M costs and lower SCE’s revenue requirement by retiring roughly **$8.37 million** in net book value. However, SCE anticipates an after-tax loss on sale of about **$1.49 million**, which it proposes to allocate to ratepayers consistent with the CPUC’s gain-on-sale policies. SCE says the transaction will not impair utility operations. Protests/responses will be due 30 days from when this item appears on the CPUC's Daily Calendar. **INSTANT ANALYSIS**: This filing is a routine asset disposition that reflects ongoing utility real-estate downsizing rather than a strategic shift. Rate base is reduced, operating costs come off the books, and the resulting loss is proposed for recovery through standard balancing-account treatment, with limited implications for near-term rates or broader market dynamics. ### FRIDAY AGGREGATE: Smart Meters; Core Gas Deliveries; RPS Milestones URL: https://www.calregulatory.com/friday-aggregate-smart-meters-core-gas-deliveries-rps-milestones/ Last updated: 2025-12-22T22:16:05.000Z This week’s filings reflect growing conflicts between lifecycle infrastructure replacement, policy-driven procurement targets, and the physical limit of electric and gas systems. ## SMART METERS SDG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K226/591226623.PDF?ref=calregulatory.com) seeking CPUC approval to replace its aging Smart Meter 1.0 advanced metering infrastructure with a new Smart Meter 2.0 platform, citing widespread device failures, approaching end-of-life between 2026–2028, and growing risks to billing accuracy, outage management, cybersecurity, and customer service. The proposal requests authority to recover approximately **$825 million** in costs incurred from 2024 through 2031 for system design, foundational and next-generation technology, and mass deployment of new electric meters and gas modules, while reusing portions of existing infrastructure where feasible to limit customer impacts. SDG&E also seeks approval of a new two-way, interest-bearing Advanced Metering Infrastructure Balancing Account to track and reconcile authorized revenues, and requests an expedited schedule so deployment can begin in 2027 before failure rates outpace workforce capacity and vendor support ends. SDG&E argues that delaying the transition would materially increase program costs and operational risk, and that Smart Meter 2.0 is necessary to preserve core functionality while supporting future grid modernization and customer-facing capabilities. Protests/responses are due **January 21**. **INSTANT ANALYSIS**: SDG&E’s Smart Meter 2.0 application is a ratepayer-funded infrastructure replacement case driven by hard end-of-life risk rather than feature expansion. Smart Meter 1.0 meters that were deployed in 2009–2011 are failing at accelerating rates, vendor support is winding down, and workforce capacity to manage failures is projected to be exceeded by 2026\. SDG&E seeks expedited approval to recover $825 million in electric and gas rates via a new balancing account, arguing that delay would both degrade billing accuracy and outage visibility and increase total program costs. The core regulatory question is not whether replacement is needed (the Commission previously acknowledged Smart Meter 1.0 would require full replacement) but whether the scope, pacing, and cost controls of the Smart Meter 2.0 rollout are sufficiently disciplined to justify full rate recovery on an accelerated schedule. --- ## NATURAL GAS RATES SoCalGas/SDG&E filed an advice letter (AL 6573-G, available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Effective&ref=calregulatory.com)), which provides their biannual report on cost impacts to core customers arising from the requirement, adopted in a 2019 decision ([D.19-08-002](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M310/K135/310135933.PDF?ref=calregulatory.com)), that core gas deliveries be balanced to estimated actual consumption rather than forecasts. Covering the period from June 1 through November 30, 2025, the filing reports that SoCalGas’s system operator declared a total of 118 Operational Flow Orders (almost entirely High OFOs, with no Low OFOs until November) and no noncompliance charges incurred by Gas Acquisition during the reporting period. The utilities describe mitigation measures taken by Gas Acquisition to manage OFO exposure, including the continued use and periodic adjustment of daily Usage Guidelines to respond to uncertainty in core demand and the achievement of required storage injection targets. While the utilities acknowledge that these mitigation actions may have limited opportunities to reduce procurement costs relative to benchmarks, they state that any such impacts cannot be reliably quantified without significant assumptions. **INSTANT ANALYSIS:** This filing shows that, despite a heavy concentration of High OFO days during summer and fall 2025, SoCalGas’s Gas Acquisition operations avoided noncompliance charges by relying on conservative balancing practices and internal usage guidelines. For core customers, the immediate takeaway is stability rather than savings: mitigation actions reduced exposure to penalties but may have constrained opportunities to lower procurement costs, highlighting a continued tradeoff between operational compliance and cost optimization under the post-D.19-08-002 balancing regime. --- ## RPS PROGRAM The CPUC published its [2025 California Renewables Portfolio Standard Annual Report](https://www.cpuc.ca.gov/-/media/cpuc-websit/divisions/office-of-governmental-affairs-division/reports/2025/2025-california-renewables-portfolio-standard-rps-annual-report.pdf?ref=calregulatory.com). The report finds that California’s electricity retail sellers are broadly on track to meet the state’s statutory requirement to supply 60% renewable electricity by 2030, with most entities meeting or exceeding the interim, non-binding 44% renewable target for 2024\. Community Choice Aggregators and Electric Service Providers generally exceeded annual targets, while investor-owned utilities and Small and Multi-Jurisdictional Utilities relied more heavily on previously banked Renewable Energy Credits to demonstrate compliance for the 2021–2024 compliance period. Table 1: Investor-Owned Utilities' RPS Procurement Percentages for 2024 (Excludes RECs) | IOU | Percent | | -------------------------- | ------- | | Pacific Gas and Electric | 28% | | Southern California Edison | 38% | | San Diego Gas & Electric | 45% | Over the past decade, average RPS contract prices have declined steadily due to falling wind and solar costs, though prices rose in 2024 amid end-of-period procurement pressure, supply-chain uncertainty, and inflation concerns. Since 2020, more than **24 gigawatts** of new renewable generation and storage have interconnected to the CAISO grid. However, transmission delays remain a serious constraint. The report’s [Senate Bill 1174](https://legiscan.com/CA/text/SB1174/id/2587634?ref=calregulatory.com) assessment shows that a majority of PG&E and SCE transmission projects are delayed, placing about **13 gigawatts** of renewable and storage resources at risk of delayed operation. In response, CPUC staff highlight ongoing coordination with the CAISO and other agencies to address permitting, materials, and project-sequencing challenges, while emphasizing that [Integrated Resource Planning](https://www.cpuc.ca.gov/irp/?ref=calregulatory.com) will increasingly guide renewable procurement. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/Report.png) **INSTANT ANALYSIS:** The 2025 RPS Annual Report confirms that California is meeting near-term renewable targets largely through portfolio management and banked RECs rather than sustained new-build momentum. While headline compliance remains intact across most retail sellers, rising 2024 contract prices and growing reliance on excess procurement point to tightening conditions at the margin. The most consequential risk sits outside procurement itself: persistent transmission delays now place more than 13 GW of renewable and storage resources at risk, directly threatening the pace and timing of future RPS delivery. Absent accelerated transmission resolution and interconnection reform, RPS compliance increasingly becomes an accounting exercise rather than a physical system outcome, which will compound as IRP-driven procurement ramps and the state pushes toward [Senate Bill 100](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb100?ref=calregulatory.com) targets. --- ## INTERCONNECTION/LARGE LOADS PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7785-E.pdf?ref=calregulatory.com) seeking CPUC approval of a non-standard Electric Rules 2, 15, and 16 agreement to interconnect a new Google LLC facility in San Jose with a forecasted full-build demand of 250 megawatts at the transmission level. To serve the load, PG&E proposes an arrangement under which Google would design, construct, and initially fund a new 230 kilovolt gas-insulated switching station. The station would have a breaker-and-a-half configuration, along with associated underground transmission service lines connecting to a PG&E-owned switching station, with ownership of certain facilities transferred to PG&E upon completion. The estimated cost of the interconnection facilities ranges from **$64 million** to **$137 million**, exclusive of income tax gross-up, with an anticipated in-service date of December 2028\. PG&E frames the agreement as protective of existing ratepayers by relying on: - Actual-cost billing; - Binding cost estimates for applicant-built facilities; - Refund limits tied to the lower of actual or estimated costs; and - Explicit provisions requiring Google to bear unreimbursed special-facility costs and any costs incurred if the project is terminated. The advice letter also identifies preliminary cost-recovery venues, indicating that facilities integrated into the CAISO-controlled transmission network are likely to be recovered through FERC-jurisdictional transmission rates, while certain service lines and metering equipment would remain CPUC-jurisdictional. Protests are due **January 7**. --- ## MICROGRIDS PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7789-E.pdf?ref=calregulatory.com) providing its quarterly update on the Microgrid Incentive Program, covering program and project activity through September 30, 2025\. The report describes PG&E’s progress administering its authorized **$79.2 million** Microgrid Incentive Program budget, which is intended to support clean community microgrids that serve critical facilities and disadvantaged or vulnerable communities impacted by grid outages. As of the reporting period, program activity remains concentrated in early stages, with extensive community and developer engagement underway: 47 projects in Tranche 1 and 56 projects in Tranche 2 are in Stage 1 consultation, while 22 Tranche 1 projects have advanced into Stage 2 application review. No projects have progressed to the construction or operational stages, and no incentive award payments have been made. Spending to date consists primarily of administration costs and a limited amount of capital spending associated with the [Redwood Coast Airport microgrid ](https://redwoodenergy.org/about/community-impact/rcam/?ref=calregulatory.com)under the separate [Community Microgrid Enablement Program ](https://ccag.ca.gov/wp-content/uploads/2021/11/PGE-CMEP-La-Honda-Microgrid.pdf?ref=calregulatory.com)framework, with no accruals or outstanding contractual commitments reported as of September 30. PG&E states that forecasting remains constrained until project awards are finalized, and reports no program issues requiring mitigation at this time. **INSTANT ANALYSIS:** This filing is procedural but revealing: more than a year into PG&E’s Microgrid Incentive Program, activity remains clustered in consultation and application review, with no projects reaching construction or operation and no incentive awards issued. For market participants, the near-term takeaway is straightforward: Microgrid Incentive Program dollars remain largely uncommitted, timelines are extending, and tangible resiliency gains are arriving later than statutory or policy narratives suggest. Early-stage engagement and project readiness therefore matter more than any assumption of shovel-ready deployment. --- ## MOSS LANDING The Western Electricity Coordinating Council has released [a report](https://www.wecc.org/wecc-document/25301?ref=calregulatory.com) analyzing the January 16 fire that destroyed Phase 1 of the Moss Landing battery energy storage system. - The report uses the incident to highlight how early, warehouse-style Battery Energy Storage System designs (built before [National Fire Protection Association 855](https://www.nfpa.org/codes-and-standards/nfpa-855-standard-development/855?ref=calregulatory.com) and large-scale [UL 9540A](https://www.ul.com/services/ul-9540a-test-method?ref=calregulatory.com) fire testing) carry elevated risks compared to modern systems. The fire occurred during a high state-of-charge capacity test, a condition strongly associated with thermal runaway; it overwhelmed suppression systems, prompted evacuations, and ultimately resulted in a total loss of the Phase 1 facility, with a later re-ignition tied to residual damage. - The report situates Moss Landing within a broader pattern of BESS fires, emphasizing thermal runaway and high [State of Charge](https://www.ess-news.com/2024/09/25/the-significance-of-state-of-charge/?ref=calregulatory.com) as primary risk drivers, the limits of traditional indoor suppression strategies, and the industry’s shift toward containerized designs, updated codes, validated fire testing, and safer operating practices. **INSTANT ANALYSIS:** The WECC’s report frames the January 2025 loss as a legacy-design problem rather than a repudiation of grid storage. The report reinforces that once thermal runaway begins, suppression in dense indoor installations may not prevent propagation. Modern safety practice has therefore shifted toward containerized designs, validated fire testing, tighter State of Charge limits, and more disciplined operating and emergency-response protocols (particularly for older facilities still operating outside today’s design standards). ### December 18 CPUC Voting Meeting Results: Cost of Capital; Long-Term Gas Planning; Woolsey Fire URL: https://www.calregulatory.com/december-18-cpuc-voting-meeting-results-cost-of-capital-long-term-gas-planning-woolsey-fire/ Last updated: 2025-12-19T04:26:15.000Z The Commission closed out the year with a wide-ranging package spanning utility finance, wildfire cost recovery, affordability governance, gas transition implementation, procurement, and distribution-planning reform. Note: the following decisions were delayed until **January 15** (no reasons were given). - **SDG&E Wildfire Mitigation Costs**: This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) addresses SDG&E’s request to recover wildfire-mitigation costs recorded in its Wildfire Mitigation Plan Memorandum Accounts from May 2019 through 2022\. SDG&E sought approval to recover more than **$1.47 billion** in wildfire-mitigation spending from 2019–2022, but the PD disallows **$192.6 million** in O&M and **$242.4 million** in capital due to insufficient justification and cost-effectiveness concerns. - **Bioenergy Market Adjusting Tariff**: This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) program through **December 31, 2025**. - **Union Island Pipeline**: This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD concludes that the company no longer holds valid franchise rights in Antioch and Brentwood and ceased transporting gas in 2023. --- ## COST of CAPITAL DECISION This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K257/591257306.pdf?ref=calregulatory.com) sets the authorized test-year 2026 cost of capital for PG&E, SoCalGas, SCE, and SDG&E, largely maintaining continuity with prior authorizations while rejecting utility requests for higher equity layers or structural adjustments. The decision adopts a uniform 52% common-equity ratio for all four utilities, denies proposals to increase leverage or eliminate preferred equity, and concludes that existing capital structures remain sufficient to support investment-grade credit ratings without imposing unnecessary costs on ratepayers. Authorized returns on common equity are set at: - 9.98% for PG&E; - 9.78% for SoCalGas; - 10.03% for SCE; and - 9.93% for SDG&E... ...with corresponding overall rates of return ranging from 7.41% to 7.61%. In reaching these determinations, the decision relies primarily on discounted cash flow results, rejects use of Empirical Capital Asset Pricing Model and after-tax Weighted Average Cost of Capital adders as overstating equity costs, and finds that claimed wildfire, climate-transition, and regulatory risks do not warrant ROEs significantly above national norms. Embedded costs of long-term debt and preferred equity are adopted largely as proposed and uncontested. The decision also denies PG&E’s request for a yield-spread adjustment and resolves all remaining issues, closing the consolidated proceeding. ### Commissioner Houck's Dissent Excerpts from the full dais discussion are available [here](https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-commissioner-remarks-on-cost-of-capital-decision/). - Commissioner **Darcie Houck** was the lone dissenting voice in the 4-1 decision. In referencing **Justice Holmes** in [*Cedar Rapids Gaslight Co. v. Cedar Rapids*](https://supreme.justia.com/cases/federal/us/223/655/?ref=calregulatory.com), she framed the Commission’s task as steering between [**Scylla** and **Charybdis**](https://en.wikipedia.org/wiki/Between%5FScylla%5Fand%5FCharybdis?ref=calregulatory.com)–the twin dangers of authorizing returns so high that affordability collapses, or so low that utilities cannot attract capital to meet safety and reliability obligations. - While agreeing that utilities require investment-grade credit ratings and continued access to capital, Commissioner Houck argued the adopted ROEs do not sufficiently account for the cumulative economic strain on customers, who are increasingly absorbing wildfire risk through higher rates, insurance costs, and arrearages. She emphasized that even modest ROE adjustments carry large revenue impacts when paired with near-double-digit ratebase growth, and that customers already function as de facto backstops for wildfire exposure through the wildfire fund and securitization mechanisms. - Houck further cautioned that the current three-year Cost of Capital cycle magnifies the consequences of error and limits the CPUC’s ability to fine-tune outcomes as market conditions evolve. In her view, unresolved issues around capital-structure discipline, forecasted cost-of-debt accuracy, and procedural cadence warranted a stronger shift toward customer protections in this decision. **INSTANT ANALYSIS**: The Commission’s 2026 Cost of Capital decision threads a deliberate middle path in the ROE debate. The decision lowers authorized ROEs while reinforcing structural continuity and ratepayer protections. By holding capital structures at 52% equity, rejecting requests for higher leverage or expanded equity layers, and reducing ROEs by roughly 30 basis points, the Commission explicitly recognizes the role of California’s wildfire-risk backstops without concluding that wildfire risk has been resolved. ROEs remain above national averages to account for ongoing wildfire, climate, and regulatory exposure, but fall short of the 11%+ outcomes advanced by utilities and certain financial models. Commissioners framed the decision as a practical exercise in balancing credit quality, capital access, and affordability, particularly in light of sustained rate pressure and rising arrearages. --- ## LONG-TERM GAS PLANNING This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234578.pdf?ref=calregulatory.com) designates California’s initial set of priority neighborhood decarbonization zones pursuant to [Senate Bill 1221](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/SB-1221-implementation?ref=calregulatory.com), satisfying the statutory requirement to act by **January 1, 2026**. The decision identifies 151 census tracts across multiple counties as initial zones, focusing primarily on areas where there is demonstrated local government or community support and a concentration of foreseeable gas distribution replacement projects. The decision adopts a deliberately measured, census-tract-level approach intended to preserve flexibility for future pilot project selection while still providing sufficient specificity to enable meaningful public engagement. PG&E, SoCalGas, and SDG&E must update their SB 1221 maps by **January 16**, while no zones are designated in Southwest Gas’s service territory at this stage. The Commission explicitly characterizes these zones as “initial," commits to updating them by the end of 2026 as more data and community input become available, and orders extensive outreach (including virtual information sessions and reporting requirements) to broaden participation and inform future refinements to the decarbonization framework. An [accompanying appendix](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K892/590892609.pdf?ref=calregulatory.com) serves as the CPUC's de facto audit trail. It translates the abstract statutory factors in the Public Utilities Code into measurable infrastructure and community indicators, showing where decarbonization pilots are most plausibly cost-effective and locally supported. The appendix is also the document stakeholders will use to assess who made the cut, on what grounds, and with what underlying gas-system characteristics. Excerpts from the full dais discussion are [available here](https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-commissioner-remarks-on-senate-bill-1221-decarbonization-decision/). **INSTANT ANALYSIS:** This decision frames SB 1221 as a practical systems-management exercise grounded in avoided gas reinvestment, ratepayer protections, and implementation risk. Commissioners repeatedly emphasized the connection between decarbonization pilots and cost avoidance, particularly the need to prevent fixed gas-system costs from being shifted onto remaining (often lower-income customers) as electrification accelerates. The tract-level zones operate as controlled testing environments where infrastructure conditions and community readiness can be evaluated together rather than in isolation. The required outreach, reporting, and scheduled zone updates reflect an expectation that early pilots will surface constraints as well as opportunities. The decision positions future approvals as evidence-driven determinations shaped by cost, reliability, and community acceptance, with the pace of gas-system decarbonization governed by implementation performance rather than aspirational targets. --- ## AFFORDABILITY This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K383/591383570.PDF?ref=calregulatory.com) updates and finalizes the CPUC’s affordability framework, narrowing mandatory affordability filings to General Rate Cases with revenue increases above one percent and closing the proceeding. The decision requires utilities, when filing affordability metrics, to provide clearer context by comparing rate and revenue growth to inflation and separating operational from capital cost drivers, while better highlighting impacts on disadvantaged customers. The decision also preserves public access to detailed Cost and Rate Trackers, shifts ongoing affordability updates to CPUC-managed web postings, directs staff to examine communications-specific affordability issues, and formally transitions the framework from development to ongoing use. ### Comments from the Assigned Commissioner "When we opened the proceeding in 2018," Commissioner **Darcie Houck** said, "the outlines of what is now widely understood to be an affordability crisis were just becoming evident. The rulemaking observed that several trends may exert long-term impact on rates, including climate change, related changes to system reliability (such as wildfires), geographical differences in demand, program investments and market structures to support wider deployment of zero carbon and grid-modernization resources, and increases in transmission capital expenditures." Commissioner Houck added that, even before the rulemaking began, the average rate revenue requirement per unit of sales for the three large electric investor-owned utilities was already rising faster than inflation between 2013 and 2017\. This divergence has since accelerated, producing increases in both rates and total customer bills as utilities recover the growing costs of maintaining reliable service alongside CPUC-authorized returns on capital investments. She continued: > The purpose of the rulemaking was not to directly control these costs, but rather to provide the commission and parties with a set of data-driven metrics to estimate the impact on affordability of proposals before us in an objective and comprehensive manner, while also enabling us to track affordability over time across the full spectrum of customer needs statewide for energy, water and telecommunication services. Houck closed with the following comments. - Thursday's decision identifies Phase 2 of General Rate Cases as appropriate venues to consider affordability impacts on customers, but this is merely a starting point. - While this rulemaking has focused on residential affordability issues, non-residential customers also face rate burdens, particularly small commercial customers. **INSTANT ANALYSIS:** This decision narrows required affordability filings to General Rate Cases with revenue increases above 1%. When metrics are filed, utilities must now provide clearer context by comparing rate and revenue growth to inflation, separating operational and capital cost drivers, and more directly highlighting impacts on disadvantaged customers. The decision maintains public access to Cost and Rate Trackers, shifts ongoing affordability updates to CPUC-managed web postings, and directs staff to examine communications-specific affordability issues. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/iterograph_Wed-Dec-17-2025--1-.png) ## WOOLSEY FIRE This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894945.pdf?ref=calregulatory.com) adopts a comprehensive settlement resolving SCE's request to recover costs associated with the November 2018 Woolsey Fire, which burned roughly 97,000 acres, destroyed or damaged more than 2,000 structures, and led to thousands of claims against the utility. SCE originally sought recovery of approximately $5.43 billion in costs recorded to its Wildfire Expense Memorandum Account (WEMA), covering third-party claims, legal fees, and financing costs net of insurance, plus about $83.8 million in restoration-related capital and operating costs recorded to its Catastrophic Event Memorandum Account (CEMA). After extensive discovery, expert testimony, and contested litigation over prudence and reasonableness, SCE, the Public Advocates Office, the Energy Producers and Users Coalition, and Small Business Utility Advocates negotiated a settlement that reflects a significant reduction to the utility’s request and avoids further evidentiary hearings. - Under the adopted settlement terms, SCE may recover a portion of its recorded costs, with the remainder permanently disallowed. Specifically, SCE may recover **35%** of WEMA costs (approximately **$1.9** to **$2.0 billion**) while **$3.7 billion** is permanently disallowed. SCE may recover **85%** of CEMA costs (**$71 million**), with the remaining balance disallowed. - The settlement also confirms that **$250 million** of Woolsey-related claims costs will **not** be recovered from ratepayers and extends this discipline by requiring SCE to waive recovery of **$157 million** in WEMA costs tied to other pre-July 12, 2019 wildfires. Authorized WEMA amounts are expected to be recovered primarily through a future securitization application, with a fallback to five-year recovery using long-term debt if securitization is not approved. Meanwhile, CEMA costs will flow through standard capital and operating cost-recovery mechanisms. **INSTANT ANALYSIS**: The Woolsey Fire settlement represents one of the Commission's most aggressive wildfire cost disallowances to date, permanently shifting $3.7 billion of SCE's claimed costs away from ratepayers while still preserving a securitization pathway for a limited portion of recovery (the same mechanism referenced in the Cost of Capital decision as part of California's wildfire-risk backstop architecture that partially justified lower ROE adjustments). --- ## 2026 ERRA FORECAST DECISIONS for PG&E & SCE In respective decisions the CPUC approved the 2026 Energy Resource Recovery Account forecast applications for PG&E and SCE, adopting updated procurement cost forecasts, sales assumptions, and related rate impacts for the coming year. ### Pacific Gas & Electric For PG&E, the Commission [adopts](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K260/591260654.PDF?ref=calregulatory.com) a 2026 gross ERRA-related revenue requirement of **$4.51 billion**, about 6% higher than 2025, while authorizing amortization of a sizable ERRA overcollection carried into year-end 2025\. Despite the higher revenue requirement, bundled residential customers will see a material decrease in generation rates due largely to updated sales forecasts, balancing account treatment, and greenhouse gas allowance returns, while Direct Access and Community Choice Aggregator customers face higher generation-related charges driven by PCIA and cost-allocation outcomes. ### Southern California Edison For SCE, the Commission [approves](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234566.pdf?ref=calregulatory.com) a 2026 ERRA forecast revenue requirement of **$4.69 billion**, a 5% increase over 2025, reflecting updated fuel and purchased power costs, balancing account true-ups, greenhouse gas compliance costs, and revised portfolio assumptions. As with PG&E, bundled customers will experience a notable reduction in average generation rates even as total ERRA costs rise, while Power Charge Indifference Adjustment rates for departing load customers will increase across vintages. In both cases, the Commission finds the utilities’ sales forecasts, procurement methodologies, and cost projections reasonable for forecast purposes, emphasizes the role of subsequent compliance proceedings to true-up actual costs, and closes the applications after directing implementation through consolidated advice letters, effective January 1. **INSTANT ANALYSIS:** The Commission again pairs rising ERRA forecast revenue requirements with near-term bundled rate relief, largely through balancing account adjustments and greenhouse gas allowance returns. The more consequential issue for stakeholders is how year-end true-ups and PCIA vintaging ultimately distribute cost responsibility, particularly as actual 2026 procurement conditions are reconciled in future compliance proceedings. --- ## PG&E TRANSMISSION This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K266/591266530.pdf?ref=calregulatory.com) approves PG&E’s request to recover **$337.9 million** in recorded balances from its Transmission Revenue Requirement Reclassification Memorandum Account, which reflect the transfer of certain costs from FERC to CPUC jurisdiction following FERC Opinion No. 572 and the Transmission Owner 18 settlement. The authorized amount includes: - $372.8 million in common, general, and intangible plant costs and related expenses; - $7.7 million associated with a facility that moved from CAISO to non-CAISO operational control in 2023; and - A $42.6 million retail offset tied to assets reclassified from distribution to transmission. The decision authorizes prospective recovery beginning **January 1, 2026**, amortized over 12 to 14 months. At the same time, the Commission directs PG&E to file a Tier 2 advice letter: - Examining whether transmission assets were misclassified between 2006 and 2022; - Quantifying any associated revenue impacts on distribution customers; and - Recommending an appropriate regulatory path to address those impacts, alongside compliance reporting to ensure transparency and avoid duplication with FERC-administered refunds. **INSTANT ANALYSIS:** This decision clears a large, long-pending jurisdictional cleanup for PG&E by allowing the prospective recovery of reclassified transmission costs, but with an unusually explicit lookback requirement that could reopen historical exposure. While the recovery beginning in 2026 provides near-term revenue certainty, the mandated advice letter on potential 2006–2022 misclassification pressures PG&E to account for legacy accounting practices while limiting any claim that the Transmission Revenue Requirement Reclassification Memorandum Account is purely forward-looking. For stakeholders, the real exposure (and any upside) centers on how broadly the Commission ultimately requires past distribution customers to be made whole, rather than on the approved recovery itself. --- ## PG&E ADVANCED METERING INFRASTRUCTURE This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K833/584833313.PDF?ref=calregulatory.com) approves a [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) between PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates that resolves PG&E’s request to recover costs for its large-scale replacement of failing Gas Advanced Metering Infrastructure modules. - PG&E had sought a revenue requirement of **$143.3 million** and nearly **$500 million** in forecasted costs for 2023–2026, but intervenors challenged the adequacy of PG&E’s showing and raised concerns about premature module failures and stranded costs. - Through negotiation, the parties [agreed](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) to reduced cost recovery: **$4 million** in adopted expenses, **$420 million** in adopted capital expenditures, and an **$88.6 million** total revenue requirement, representing a 38% reduction from PG&E’s original request. - The parties' [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) also removes PG&E’s return on undepreciated assets tied to early module failures and limits additional upgrade-related spending after 2026\. The Commission finds the deal reasonable and in the public interest, concluding it reflects meaningful concessions, resolves disputes over responsibility for failures, and avoids health, safety, or environmental justice concerns. The decision adopts the settlement in full and closes the proceeding. **INSTANT ANALYSIS**: The settlement trims PG&E’s Gas AMI replacement program to a more defensible scope, cutting the utility’s original ask down to $88.6 million, while locking PG&E into a $420 million capital cap and denying any return on $9.8 million of prematurely failed modules. --- ## DISTRIBUTION PLANNING Resolutions [E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K234/591234617.pdf?ref=calregulatory.com) and [E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K380/591380244.pdf?ref=calregulatory.com) establish a coordinated upgrade to the investor-owned utilities' distribution planning framework by pairing a standardized pending loads construct with a formal scenario-planning methodology. "The resolutions," said Commissioner **Darcie Houck**, "highlight the importance of the grid-planning process and the need to consider pending loads and refined scenario planning to ensure we’re developing the grid of the future needed for the 21st century." ### Resolution E-5413 With Resolution E-5413, the Commission approves (subject to significant modification) utility proposals to introduce a uniform pending loads category into the Distribution Planning and Execution Process, defining pending loads as medium-term, location-specific load growth that is more concrete than trend-based [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) (IEPR) forecasts but not yet firm customer requests. The resolution adopts a common, three-tier confidence framework (Categories A, B, and C) and incorporates PG&E’s revised minimum criteria and SCE’s categorical structure. The resolution also allows certain medium-confidence loads to exceed the IEPR only within clearly defined, capacity-constrained “hot spots.” Utilities must report pending load data, hot spot identification, and planning adjustments in their annual Grid Needs Assessments and Distribution Upgrade Project Reports, with explicit guardrails to prevent speculative overbuilding while still enabling proactive, dig-once investment. ### Resolution E-5414 Resolution E-5414 builds on that foundation by approving a uniform scenario planning framework that uses the pending loads construct to test multiple plausible futures and translate them into a single, defensible set of planned investments. Beginning with the 2025–2026 Distribution Planning and Execution Process cycle, each utility must run Low, Base, and High scenarios grounded in the same IEPR scenario but differentiated by how pending load categories are incorporated and allowed to influence planning outcomes. Resolution E-5414 adopts a hybrid of PG&E’s scenario structure and SCE’s decision-logic approach, requiring utilities to explain how results from all three scenarios converge into one investment plan, and to disclose when and why project scopes or timing are driven by the High scenario. **INSTANT ANALYSIS:** Taken together, these resolutions reshape how IOUs justify distribution upgrades by moving the Commission away from single-forecast planning and toward a structured, multi-scenario framework. By standardizing pending load categories and requiring Low, Base, and High scenarios to roll up into a single investment plan, the CPUC is raising the bar for how utilities demonstrate the need for proactive grid buildout while still allowing forward planning for electrification-driven growth. For stakeholders, the leverage now sits in how pending loads are classified, when medium-confidence loads are permitted to exceed the IEPR in defined hot spots, and how often High-scenario outcomes ultimately drive project scope and timing in approved capital plans. --- ## RPS PROGRAM This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K248/591248385.pdf?ref=calregulatory.com) approves, with modifications, the 2025 Renewables Portfolio Standard procurement plans filed by investor-owned utilities, small and multi-jurisdictional utilities, community choice aggregators, and electric service providers. The decision authorizes continued long-term and short-term RPS procurement but rejects, without prejudice, IOU requests to eliminate Tier 1 Advice Letter review for short-term transactions, which preserves existing oversight, pending review in the Integrated Resource Planning proceeding. The decision gives PG&E, SCE, and SDG&E broad authority to procure, sell, and manage RPS resources and renewable energy credits (subject to advice-letter approval and limited plan corrections) while several Community Choice Aggregators and electric service providers are directed to supplement their plans to address identified deficiencies. **INSTANT ANALYSIS**: This decision maintains Commission oversight of RPS procurement by reaffirming advice-letter review for short-term transactions, while granting utilities broad but structured flexibility to manage renewables portfolios amid load growth, interconnection delays, and compliance risk as the state approaches its 2030 targets. --- ## SELF-GENERATION INCENTIVE PROGRAM [Resolution E-5430](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K894/590894944.pdf?ref=calregulatory.com) approves with modifications updates to the Self-Generation Incentive Program that are intended to strengthen third-party ownership consumer protections and revise how federal tax credits are accounted for after recent federal law changes. - The CPUC generally requires SGIP projects to assume a 30% federal tax credit unless applicants can document both tax-credit ineligibility and why a project could not be third-party owned, closing a prior loophole that allowed avoidance of federal cost sharing. - Resolution E-5430 ends residential host-customer tax credit eligibility for projects with Permissions to Operate after **December 31, 2025**, and solar tax credit eligibility for third-party ownership or non-residential projects after **December 31, 2027**, while largely relying on Permission to Operate dates to determine eligibility. The resolution adopts most proposed third-party ownership consumer protections, rejects one related to ownership transfer profits, bars higher SGIP incentives for projects failing foreign-entity or domestic-content rules, and directs conforming SGIP handbook updates by **January 1, 2026**. **INSTANT ANALYSIS**: Resolution E-5430 advances the CPUC’s effort to maximize federal tax credit utilization in SGIP by presuming a 30% federal cost share unless applicants can substantiate (i) tax-credit ineligibility and (ii) why a project could not be structured as third-party owned. By relying on Permission to Operate dates to define eligibility windows and declining exemptions tied to domestic content or foreign-entity constraints, the Commission narrows avenues for shifting additional costs onto SGIP funds. In theory, this will conserve program budgets while raising documentation and compliance expectations for developers and host customers. --- ## SOCALGAS FINANCES This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K552/590552447.pdf?ref=calregulatory.com) authorizes SoCalGas to issue up to **$3.3 billion** in new debt, allowing a mix of secured and unsecured instruments and the use of standard hedging and derivative tools to manage interest-rate risk and financing costs. Proceeds may be used to fund capital investments, reimburse prior treasury spending, or refinance existing debt, though the decision does not approve specific projects or guarantee cost recovery in rates. About $2.09 billion is expected to support new capital needs, with $1.21 billion used for refinancing. **INSTANT ANALYSIS**: The Commission’s approval gives SoCalGas wide financing flexibility to raise and refinance debt at scale while preserving strict after-the-fact review of borrowing costs, reinforcing the CPUC’s pattern of separating capital-markets access from any upfront assurance of rate recovery. --- ## ON-BILL FINANCING This [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K260/591260630.PDF?ref=calregulatory.com) authorizes a modified Tariff On-Bill Financing Pilot proposed by SCE and rejects Tariff On-Bill proposals submitted by SDG&E, SoCalGas, and Silicon Valley Clean Energy. The decision finds that SCE’s pilot is sufficiently narrow, implementable, and protective of customers to justify a limited test of tariff-based, meter-tied cost recovery for residential energy efficiency and electrification upgrades. The approved pilot emphasizes bill neutrality, transferability to successor occupants, savings verification with remedies, and strong consumer protections, while avoiding credit or income screening. **INSTANT ANALYSIS**: By approving only SCE’s modified pilot and rejecting all others, the Commission is deliberately constraining on-bill financing to a tightly controlled proof-of-concept, prioritizing bill neutrality, customer protections, and administrative feasibility over rapid scale. The outcome reflects continued caution around tariff-based decarbonization charges and signals that broader Tariff On-Bill Financing expansion will hinge on demonstrated performance rather than policy ambition alone. ### MID-WEEK NEWS CODEX: Heat Pumps; Hydrogen for Data Centers; Denial of Sable Permit Transfers URL: https://www.calregulatory.com/mid-week-news-codex-heat-pumps-hydrogen-for-data-centers-denial-of-sable-permit-transfers/ Last updated: 2025-12-18T01:17:56.000Z - **Biomass is a Money Pit That Won't Solve California's Energy or Wildfire Problems:** "In a [vote](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K419/590419905.pdf?ref=calregulatory.com) later this month, the California Public Utilities Commission is [expected to end](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) the BioMAT subsidy program, which requires electric utilities to buy biomass power at [exorbitant costs](https://www.biologicaldiversity.org/campaigns/debunking%5Fthe%5Fbiomass%5Fmyth/pdfs/Forest-Bioenergy-Briefing-Book-March-2021.pdf?ref=calregulatory.com) — four times the average. Californians get hit with those extra costs in our power bills, along with pollution that harms our health and climate." [**CAL MATTERS**](https://calmatters.org/commentary/2025/12/biomass-california-energy-wildfire-problems/?ref=calregulatory.com)(*CRI Editorial Note – the CPUC has* [*delayed action*](http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K403/591403103.PDF?ref=calregulatory.com) *on this item until *January 15**) - **California's Last Nuclear Power Plant Will Remain Open – For Now:** "To outside observers across the country, the Diablo Canyon deal may look strange: How can a state agency extort money and land as a condition for approving a permit? Why is the future of California’s nuclear power—10% of energy in America’s most populous state, serving 40 million people—in the hands of 12 coastal bureaucrats?" [**PACIFIC LEGAL FOUNDATION**](https://pacificlegal.org/nuclear-plant-california/?ref=calregulatory.com) - **California's Plan to Boost Plug-In Heat Pumps and Induction Stoves:** "...late last month, the California Public Utilities Commission [signed off](https://docs.cpuc.ca.gov/SearchRes.aspx?docformat=ALL&docid=588645495&ref=calregulatory.com) on a plan to spend $115 million over the next six years to develop and drive demand for the fossil-fuel-free equipment — a [first-of-its-kind](https://calmta.org/cpuc-approves-first-ever-statewide-market-transformation-initiatives-to-advance-energy-efficiency-and-decarbonization/?ref=calregulatory.com) investment for the state. These appliances, which plug into standard 120-volt wall outlets, don’t need professional installers or the [expensive electrical upgrades](https://www.canarymedia.com/articles/electrification/yes-its-possible-to-electrify-a-home-on-just-100-amps?ref=calregulatory.com) sometimes required for conventional whole-home heat pumps or 240-volt induction stoves. That ease of installation makes them crucial tools in California’s quest to [decarbonize its economy by 2045](https://lci.ca.gov/climate/carbon-neutrality.html?ref=calregulatory.com)." [**CANARY MEDIA** ](https://www.canarymedia.com/articles/electrification/california-plug-in-heat-pumps-induction-stoves?ref=calregulatory.com)(S*ee CRI's coverage of this matter* [*here*](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/)*.*) - **California Proposes a Road Usage Tax:** "In 2017, California raised its state gas tax supposedly to maintain the state’s roads, despite a state budget of [$179.5 billion](https://www.msn.com/en-us/news/us/california-s-new-tax-a-monthly-subscription-to-use-state-roads/ar-AA1S1Jxk?ocid=BingNewsSerp&ref=calregulatory.com). California has the highest gas tax in the country at [71 cents per gallon](https://taxfoundation.org/data/all/state/gas-taxes-state/?ref=calregulatory.com). But as more people switch to EVs, the gas tax will cover less of the state’s road costs. Despite California’s budget increasing to [$325 billion](https://www.msn.com/en-us/news/us/california-s-new-tax-a-monthly-subscription-to-use-state-roads/ar-AA1S1Jxk?ocid=BingNewsSerp&ref=calregulatory.com), the state needs an additional tax to build and maintain its roads." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/regulation/california-proposes-a-road-usage-tax/?ref=calregulatory.com) - **California Winery Powers 100% of its Operations with Floating Solar Array:** "California winery Nelson Family Vineyards is now powering 100% of its operations with electricity after Noria Energy has installed onsite solar arrays. The 74-year-old, 1,800-acre family farm is now fully powered by clean energy, and with no agricultural land taken out of production. Adding to an existing rooftop solar array’s production, Noria Energy installed a floating solar array on an irrigation pond. Together, the two solar projects are expected to generate about 200,000 kWh of electricity per year, powering the winery, agricultural pumps, tasting room, shop, and 12 on-site homes." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/12/17/california-winery-powers-100-of-its-operations-with-floating-solar-array/?ref=calregulatory.com) - **Development Deal Will Provide Hydrogen for California Data Centers:** "Vema Hydrogen, developer of a sustainable hydrogen production technology, said it has entered a hydrogen purchase and sale agreement with Verne, a provider of on-site power and cooling solutions. [Verne](https://www.verne-power.com/?ref=calregulatory.com) will leverage [Vema’s](https://www.vema.earth/?ref=calregulatory.com) clean energy, known as Engineered Mineral Hydrogen, to provide low-emission power for its data center customers. The companies on December 16 said operations could begin as soon as 2028." [**POWER**](https://www.powermag.com/development-deal-will-provide-hydrogen-for-california-data-centers/?ref=calregulatory.com) - **Federal Watchdog Will Investigate Energy Department Over Selective Blue State Grant Cancellations:** "The cancellation, in October, included more than 300 awards in 16 states that did not vote for **Trump** in the 2024 presidential election. Among them were 79 canceled grants for California — more than any other state on the list — totaling $2.1 billion, as well as $1.2 billion in future funding expected for the [state’s hydrogen hub](https://www.latimes.com/environment/story/2024-07-25/what-californias-hydrogen-hub-means-for-our-energy-future?ref=calregulatory.com), the Alliance for Renewable Clean Hydrogen Energy Systems, or ARCHES." [**LA TIMES**](https://www.latimes.com/environment/story/2025-12-17/federal-watchdog-will-investigate-energy-department-over-selective-blue-state-grant-cancellations?ref=calregulatory.com) - **K2 Pure Solutions Breaks Ground on Commercial Low-Carbon Hydrogen Facility in Pittsburg, California:** "Scheduled for commissioning in early summer 2026, the project will expand K2’s existing chlor-alkali operations into California’s first commercial source of low-carbon, high pressure hydrogen produced from a proven industrial site serving municipal and industrial customers." [**THE AI JOURNAL**](https://aijourn.com/k2-pure-solutions-breaks-ground-on-commercial-low-carbon-hydrogen-facility-in-pittsburg-california/?ref=calregulatory.com) - **New York and California Reach the Energy Abyss:** "For California, the most pressing energy problem is refining capacity. Just last week, Phillips 66 and Valero confirmed that they would be closing a refinery in California, thereby taking away 17% of the Golden State’s current refining capacity. Meanwhile, due to its environmental policies, California does not allow the use of normal gasoline for its internal combustion vehicles. It requires a special mix of fuels, often called California Reformulated Gasoline. This is part of what causes gas prices to exceed $6.00/gallon in California, and it means that California cannot simply import gasoline from neighboring states to make up the shortfall resulting from the closing refineries." [**FORBES**](https://www.forbes.com/sites/danielmarkind/2025/12/16/new-york-and-california-reach-the-energy-abyss/?ref=calregulatory.com) - **Port of Long Beach Launches Hydrogen Fuel Grant Program:** "Through the program, the Port is making up to $10 million available to eligible fleet operators to assist with the cost of hydrogen fuel. If all the funds are used, the program will result in at least 3.7 million zero-emissions miles for drayage services. Funding for the initiative is drawn from the Clean Truck Fund Rate program, which was founded in 2022 to pay for incentives for zero-emissions trucks and the infrastructure needed to charge and fuel them." [**FUEL CELLS WORKS**](https://fuelcellsworks.com/2025/12/17/fuel-cells/port-of-long-beach-launches-hydrogen-fuel-grant-program?ref=calregulatory.com) - **Santa Barbara County Denies Sable Permit Transfers:** "The Santa Barbara County Board of Supervisors [voted](https://santabarbara.legistar.com/LegislationDetail.aspx?ID=7780014&GUID=AAD91492-05F5-498E-9AC8-CB0143913129&Options=&Search=&ref=calregulatory.com) to deny the transfer of operating permits for offshore facilities from ExxonMobil to Sable Offshore Corp. The Supervisors voted 3-1 on December 15, following a [preliminary decision](https://www.californiaenergytransition.com/p/santa-barbara-denies-permit-transfer?ref=calregulatory.com) in November. The permits covered the Santa Ynez Unit, a gas plant, and the Las Flores Pipelines. The transfer of permits was a key step in restarting the Santa Ynez Unit, which has been shut since the 2015 Refugio oil spill." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/santa-barbara-county-denies-sable?ref=calregulatory.com) - **Storage For All Seasons – Why the Grid Needs More Than Four Hours:** " California’s integrated resource planning and procurement [proceeding](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K082/582082526.PDF?ref=calregulatory.com) suggests a buildout that would keep the system on track for decarbonization would include almost no additional four-hour duration resources after 2028, but huge amounts of eight-hour duration storage, and in the near future, 12-hour duration storage. Specifically, California is calling for more than ten GW of eight hour duration energy storage capacity on the system by 2031 and more than five GW of 12-hour duration storage on the system by 2036." [**UTILITY DIVE**](https://www.utilitydive.com/spons/storage-for-all-seasons-why-the-grid-needs-more-than-four-hours/807636/?ref=calregulatory.com) - **This Week, the California Energy Commission is Expected to Decide the Future of the Fountain Wind Project:** "In attempts to secure permission to build Fountain Wind, Repsol and its predecessor company have already been dealt significant blows, including two project denials by the county. In 2022, [a California law](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220AB205&ref=calregulatory.com) made it possible for a state agency, the California Energy Commission, to reexamine whether to approve the project. A final decision on the project is expected to be made by the commission this Friday, December 19\. According to the meeting [agenda](https://www.documentcloud.org/documents/26378726-251219%5Fcecbusinessmeetingagenda/?ref=calregulatory.com), the commission is likely to deny Repsol the required certification to build, assuming commissioners follow the executive director’s recommendation." [**SHASTA SCOUT**](https://shastascout.org/this-week-the-california-energy-commission-will-decide-the-future-of-the-fountain-wind-project/?ref=calregulatory.com) - **US Energy Storage Installations Through Q3 2025 Surpass 2024 Totals:** "The utility-scale storage segment drove growth with 4.6 GW installed in Q3, a 27% increase year-over-year, with 82% of installed capacity concentrated in Texas and California." [**WOOD MACKENZIE**](https://www.woodmac.com/press-releases/us-energy-storage-installations-through-q3-2025-surpass-2024-totals/?ref=calregulatory.com) - **US Oil Industry Doesn't See Profit in Trump's "Pro-Petroleum" Moves:** "On the West Coast, California Gov. [**Gavin Newsom**](https://www.gov.ca.gov/2025/11/20/governor-newsom-issues-statement-on-trumps-idiotic-offshore-oil-drilling-proposal?ref=calregulatory.com)and California Attorney General [**Rob Bonta**](https://oag.ca.gov/news/press-releases/california-not-your-playground-attorney-general-bonta-condemns-trump?ref=calregulatory.com)have made forceful statements against any new California offshore oil drilling. They have said any effort is economically unnecessary, environmentally reckless and '[dead on arrival](https://www.nytimes.com/2025/11/11/climate/offshore-drilling-california-trump-newsom.html?ref=calregulatory.com)' politically in the state. California local governments, environmental groups, business alliances and coastal communities also oppose drilling and have [vowed to use legal and political tools](https://www.nbclosangeles.com/news/local/california-offshore-drilling-newsom-trump/3807191/?ref=calregulatory.com) to block them." [**THE CONVERSATION**](https://theconversation.com/us-oil-industry-doesnt-see-profit-in-trumps-pro-petroleum-moves-270518?ref=calregulatory.com) - **With Bidirectional EVs, Solar and Storage, Critical California Bridge Can Stay Open During Outages:** "The San Francisco-Oakland Bay Bridge–which connects San Francisco to Oakland–is a critical escape route during disasters, but if the grid goes down, it has to close. Without electricity, the California Department of Transportation can’t communicate with crews or monitor operations. In a $5.3 million project that received a $3 million grant from the California Energy Commission and $2.3 million in matching funds, a microgrid consisting of 51 kW of solar, a 60-KWh battery plus two heavy-duty bidirectional electric vehicles will keep the bridge open during outages." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/electric-vehicles/article/55337186/with-bidirectional-evs-solar-and-storage-a-california-bridge-can-stay-open-during-outages?ref=calregulatory.com) - **Why Fast-Tracking Transmission is Permitting Reform's Biggest Hurdle:** "As the Senate gears up to take on permitting reform next year, a big question hangs over the push: Will they try to fix the slow pace of building long-haul transmission lines?" [**LATITUDE MEDIA**](https://www.latitudemedia.com/news/why-fast-tracking-transmission-is-permitting-reforms-biggest-hurdle/?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: Final CPUC Voting Meeting of 2025; Palomar Decarbonization Project; TIMPBA Briefs URL: https://www.calregulatory.com/wednesday-aggregate-5/ Last updated: 2025-12-17T19:55:04.000Z This roundup brings together the final major CPUC developments of 2025, alongside several filings and rulings that preview how key policy and infrastructure debates will carry into the new year. With the Commission set to hold its last voting meeting of the calendar year, this edition highlights consequential proposed decisions on cost of capital, long-term gas planning, and wildfire cost recovery, while also highlighting decarbonization demonstrations and internal utility cost controls. The CPUC is closing out 2025 by resolving legacy disputes while shaping the procedural and analytical frameworks that will govern 2026. ## FINAL CPUC VOTING MEETING of 2025 On Thursday, the CPUC will convene for its final business meeting of the year. (*See our full preview* [*here*](https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-preview/)*.*) Key items under consideration include: - **COST of CAPITAL**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) establishes the 2026 cost of capital for PG&E, SoCalGas, SCE, and SDG&E by maintaining each investor-owned utility’s existing capital structure and authorizing ROEs between 9.73% and 9.98%. The PD rejects efforts by utilities to raise equity layers or boost ROEs based on wildfire exposure, cash-flow pressures, or [Empirical Capital Asset Pricing Model](https://test.shareok.org/items/9b284c0f-7a95-4bf7-bb7b-22f3fa3af6f6?ref=calregulatory.com)/[After-Tax Weighted Average Cost of Capital](https://www.atlas.org/spaces/solve/after-tax-wacc-calculation-guide-7aFFDDJdm1wGQrnLyqataG?ref=calregulatory.com) adders, finding the evidentiary support insufficient. Intervenor arguments regarding high equity ratios, statutory protections, and national comparables carry more weight, leading the PD to conclude that current structures adequately support credit quality while limiting ratepayer burdens. - **LONG-TERM GAS PLANNING:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K210/587210797.PDF?ref=calregulatory.com) in the Long-Term Gas Planning docket implements [Senate Bill 1221](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB1221&ref=calregulatory.com) by designating initial neighborhood decarbonization zones — areas where gas utilities may pilot cost-effective electrification tied to upcoming gas line replacement work. Using criteria centered on community support, foreseeable pipeline replacement needs, and environmental-justice considerations, the PD identifies 142 census-tract-level zones and requires utilities to update their maps within 15 days. The PD also directs PG&E, SoCalGas, and SDG&E to conduct structured outreach and host public sessions ahead of a **March 15, 2026** refinement process. - **WOOLSEY FIRE:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K598/586598163.PDF?ref=calregulatory.com) approves a [major settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K376/586376853.PDF?ref=calregulatory.com) reducing SCE’s requested recovery for the 2018 Woolsey Fire, allowing only 35% of its $5.6 billion Wildfire Event Mitigation Account balance and 85% of its Catastrophic Event Memorandum Account costs. This leaves **$3.7 billion** in wildfire-related claims and legal expenses permanently disallowed, with the approved WEMA portion to be financed through securitization and CEMA recovery handled through standard ratemaking. The settlement also resolves trailing claims issues, applies a **$250 million** Administrative Consent Order waiver, and includes SCE’s agreement not to pursue **$157 million** tied to other pre-2019 fires. We will have same-day coverage available tomorrow, **December 18**. Please check back for results. --- ## DECARBONIZATION/HYDROGEN SDG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904936.PDF?ref=calregulatory.com) seeking CPUC approval and cost recovery for its [Palomar Decarbonization Demonstration Project](https://www.distributech.com/2026-event-schedule/san-diego-decarbonization-demonstration-project-tour?ref=calregulatory.com), an integrated renewable hydrogen system installed at the [Palomar Energy Center](https://www.energy.ca.gov/powerplant/combined-cycle/palomar-energy-project?ref=calregulatory.com), a 588-megawatt combined-cycle natural gas plant in Escondido. The fully operational project produces zero-carbon electrolytic hydrogen onsite and uses it for generator cooling, limited hydrogen blending in power generation, fleet vehicle fueling, and research and demonstration activities, replacing trucked-in fossil-based hydrogen and generating real-world operational data. SDG&E requests recovery of **$20 million** in direct capital and O&M costs incurred from 2021 through 2036 and proposes establishment of a two-way balancing account to track authorized costs and revenues. The application responds directly to concerns raised in the utility’s 2024 General Rate Case, where the Commission declined funding but invited a standalone filing with actual cost data and greater detail. SDG&E now provides a complete cost record, extensive testimony, and documentation showing how the project leverages: - Federal tax credits; - [Electric Program Investment Charge](https://www.energy.ca.gov/programs-and-topics/programs/electric-program-investment-charge-epic-program?ref=calregulatory.com) funding; and - Potential Low Carbon Fuel Standard and Renewable Energy Credit revenues to reduce ratepayer impacts. SDG&E argues the project advances California’s clean-energy mandates by demonstrating how existing gas infrastructure can be incrementally decarbonized while supporting reliability, affordability, and workforce readiness, and by generating operational, safety, and emissions data needed to inform long-term planning under [Senate Bill 100](https://aurorasolar.com/blog/100-clean-energy-for-california-what-sb-100-means-for-distributed-solar/?ref=calregulatory.com) and related statutes. Protests will be due 30 days from when this item appears on the CPUC's Daily Calendar. **INSTANT ANALYSIS:** SDG&E is seeking CPUC approval to recover costs for a fully operational hydrogen demonstration at Palomar, repositioning a previously rejected GRC proposal as a standalone filing backed by actual cost data and external funding offsets. --- ## NATURAL GAS PRICE SPIKE INVESTIGATION The administrative law judge in the CPUC's [Natural Gas Price Spike investigation](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com) issued a ruling that admits into the record the revised Energy Division Staff White Paper: Part III on high natural gas prices during Winter 2022–23\. Recall that this paper focuses on how the utilities' gas procurement incentive mechanisms (PG&E's Core Procurement Incentive Mechanism, or CPIM, and SoCalGas's Gas Cost Incentive Mechanism, or GCIM) performed during the crisis. Following multiple rounds of party comments and staff revisions, the final redlined version is available [here](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K649/590649160.PDF?ref=calregulatory.com). (*More CRI coverage of this proceeding is available*[ *here*](https://www.calregulatory.com/cpuc-proposes-administrative-changes-to-utility-gas-procurement-incentive-mechanisms/)*.*) The redlined version is a defensive consolidation: it fortifies Staff’s factual record, addresses party critiques, and narrows the near-term remedy set, while preserving optionality for broader incentive-mechanism reform later. **INSTANT ANALYSIS:** The final revised paper reinforces that winter 2022–2023 hedging by PG&E and SoCalGas mitigated (rather than caused) ratepayer harm and concludes that the core gas procurement incentive mechanisms remain fundamentally sound. However, Staff cites transparency gaps, misalignment, and reporting weaknesses (especially in PG&E’s CPIM) and tees up procedural fixes now while reserving deeper incentive reforms for a future proceeding. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/iterograph_Wed-Dec-10-2025--3--1.png) ## GAS SYSTEM PLANNING PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5153-G.pdf?ref=calregulatory.com) notifying the CPUC of a planned downrate of several gas transmission pipelines serving parts of Sacramento County, including Citrus Heights and Antelope. The filing reflects PG&E’s determination that these pipelines are no longer needed at their full nominal transmission pressure, but remain necessary to reliably serve more than 55,000 customers. PG&E proposes reducing the maximum allowable operating pressure on four radial transmission lines from 500 psig to 281 psig, a level it states is sufficient to meet system demand while aligning with updated safety and planning criteria. PG&E estimates the project will cost approximately **$5.5 million**, consisting of both capital and expense components, with temporary pressure-reduction measures implemented by late December 2025 and permanent modifications planned for 2026\. PG&E argues that the project will avoid substantially higher long-term integrity and inspection costs that would otherwise be required if the pipelines remained at higher pressure, while also reducing operational risk and the likelihood of gas leaks. **INSTANT ANALYSIS:** This filing is further proof that PG&E is starting to operationalize the CPUC’s new gas-system planning framework by selectively lowering transmission pressures on assets that are no longer needed at full capacity, while preserving near-term reliability for existing customers. These early downrate notices reveal how utilities intend to manage gas system contraction through incremental, engineering-driven adjustments rather than formal decommissioning proceedings, with implications for future cost recovery, integrity spending, and long-term gas infrastructure planning. --- ## SOCALGAS INTERNAL SYSTEMS UPGRADE The ALJ [issued a ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K649/590649159.PDF?ref=calregulatory.com) in the proceeding where SoCalGas requests **$24.9 million** in incremental funding for its Customer Information System Replacement Program. While the Commission has already authorized recovery for the CIS program in a prior decision ([D.24-12-074](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com)), the ALJ found that SoCalGas’s current testimony does not sufficiently explain how the new incremental costs were developed or how they relate to previously approved labor budgets. - The ruling requires SoCalGas to break out cost estimates for organizational readiness, training delivery, and surge staffing into detailed hours and costs, separately identifying in-house labor versus external contractors. - SoCalGas must also explain how these proposed costs compare to the annual direct labor costs already authorized in D.24-12-074 and justify its proposed use of the Equal Percent Allocated Margin cost allocation method by describing alternative methods considered and the rationale for selecting the Equal Percentage Allocated Margin. SoCalGas's response is due **December 30**. **INSTANT ANALYSIS:** The ALJ is making clear that SoCalGas’s incremental funding request will not be evaluated on trust or program momentum alone; the utility must provide labor-level cost transparency, demonstrate how the new spending differs from amounts already authorized, and defend its choice of cost allocation methodology. The ruling increases execution and recovery risk for the requested $24.9 million by requiring a clearer linkage between claimed incremental work, existing labor budgets, and ratepayer impacts. --- ## CODA Below are items we reported on at CRI earlier this week. ### PARTIES FILE OPENING BRIEFS IN SOCALGAS TIMPBA PROCEEDING On December 12, parties filed opening briefs in the proceeding where SoCalGas [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K140/565140098.PDF?ref=calregulatory.com) review and recovery of **$173.8 million** of costs recorded in its Transmission Integrity Management Program Balancing Account (TIMPBA). SoCalGas's filing packages five years of transmission-integrity spending into a single reasonableness review, creating a serious test of whether its inspection, remediation, and project-management costs can withstand intervenor scrutiny. (*Full CRI coverage* [*here*](https://www.calregulatory.com/socalgas-update-parties-file-opening-briefs-in-timpba-proceeding/)*.*) --- ### NATURAL GAS STORAGE Wild Goose Storage/Lodi Gas Storage filed a joint [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K511/590511213.PDF?ref=calregulatory.com) seeking exemptions from the Public Utilities Code to support a 2025 refinancing of their Brookfield-owned gas storage assets. Their proposed transaction would replace the prior asset-based lending facility with a new **$350 million** revolving credit facility and continue an amended **$1.25 billion** term loan through 2031\. (*Full CRI coverage* [*here*](https://www.calregulatory.com/natural-gas-storage-update/)*.*) --- ### DISTRIBUTION SYSTEM/DISTRIBUTION PLANNING Below are three recent items related to the state's distribution system and distribution planning regimen. - **CUSTOMER RELIABILITY REPORT TEMPLATE**: PG&E, SCE, and SDG&E jointly[ filed](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K649/590649143.PDF?ref=calregulatory.com) a proposed "Customer Reliability Report" template and data schema in the CPUC's Safety, Reliability and Resiliency of Electrical Distribution Systems docket to standardize how customer outage experience is reported across utilities. (*Full CRI coverage* [*here*](https://www.calregulatory.com/pg-e-sce-and-sdg-e-propose-customer-reliability-report-template-in-resiliency-rulemaking/)*.*) - **PARTIES RESPOND to DRAFT ELECTRIFICATION IMPACT REPORTS**: Parties filed comments in the CPUC's High DER Future rulemaking in response to "Draft Electrification Impacts Study Part 2" reports submitted by PG&E, SCE, and SDG&E. The comments address the utilities’ modeling of distribution-system impacts from electrification through 2040, including projected primary and secondary grid upgrade costs, demand flexibility scenarios, and proposed approaches for integrating the study’s findings into future distribution planning and execution processes. (*Full CRI coverage* [*here*](https://www.calregulatory.com/parties-in-high-ders-future-docket-respond-to-draft-electrification-impact-reports-of-ious/).) - **OVERLAP with NON-CAPACITY WORK:** PG&E, SCE, and SDG&E jointly filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7781-E.pdf?ref=calregulatory.com) seeking CPUC approval of a proposed method for addressing situations where distribution capacity needs identified in the Distribution Planning Process overlap with non-capacity distribution work, such as wildfire mitigation projects. (*Full CRI coverage* [*here*](https://www.calregulatory.com/ious-seek-approval-to-handle-distribution-capacity-wildfire-project-overlaps-under-existing-planning-framework/)*.*) ### IOUs Seek Approval to Handle Distribution Capacity & Wildfire Project Overlaps Under Existing Planning Framework URL: https://www.calregulatory.com/ious-seek-approval-to-handle-distribution-capacity-wildfire-project-overlaps-under-existing-planning-framework/ Last updated: 2025-12-16T23:21:32.000Z PG&E, SCE, and SDG&E jointly filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7781-E.pdf?ref=calregulatory.com) seeking Commission approval of a proposed method for addressing situations where distribution capacity needs identified in the Distribution Planning Process overlap with non-capacity distribution work, such as wildfire mitigation projects. The filing responds to a 2024 decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)) in the High DER Future proceeding ([R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com)) and asks the CPUC to affirm that the utilities’ existing engineering and planning processes already satisfy the Commission’s requirements without the need for new analytical frameworks or procedural changes. - The utilities explain that, in practice, when a non-capacity project is scheduled before a known future capacity need on the same assets or line path, engineers routinely evaluate whether modestly upsizing equipment at the outset is more cost-effective than performing a separate upgrade later. They contend that incorporating future capacity needs into initial projects is almost always less costly due to avoided permitting, mobilization, and construction inefficiencies, with exceptions only in cases of unusual technical or permitting complexity. - Drawing on examples presented at two CPUC-facilitated workshops in October and November 2025, the utilities emphasize that no parties identified substantive flaws in their current processes and that their engineering judgment, informed by load forecasts and standards, is sufficient to balance cost, risk, and feasibility. Their proposed method formalizes this approach through an engineering decision framework that: - Identifies distribution needs; - Applies existing standards; - Evaluates overlaps across workstreams; and - Where necessary, conducts targeted economic analysis to compare incremental upsizing costs against avoided future projects. The utilities stress that this framework already accounts for wildfire risk, forecast uncertainty, and operational constraints, and that forthcoming Commission action on scenario planning ([Draft Resolution E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850473.PDF?ref=calregulatory.com)) and pending loads ([Draft Resolution E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K748/585748983.PDF?ref=calregulatory.com)) will further refine forecasting inputs. (*Note that the CPUC has* [*tentatively moved*](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M591/K031/591031165.PDF?ref=calregulatory.com) *those two draft resolutions to the Consent Agenda for its *December 18* voting meeting, meaning their unanimous adoption is near-guaranteed*). Protests are due **January 5**. **INSTANT ANALYSIS:** The utilities' advice letter asks the Commission to validate current IOU practice rather than require a new planning construct. Approval would confirm that utilities may continue handling capacity and non-capacity overlaps through engineering judgment, with early asset upsizing treated as the preferred solution when it avoids follow-on projects. That approach shifts future disputes away from process design and toward fact-specific challenges, such as whether forecasts were reasonable or whether a particular upsizing decision was justified under the applicable standards. ### Parties in High DERs Future Docket Respond to Draft Electrification Impact Reports of IOUs URL: https://www.calregulatory.com/parties-in-high-ders-future-docket-respond-to-draft-electrification-impact-reports-of-ious/ Last updated: 2025-12-16T23:21:17.000Z On December 15, parties filed comments in the CPUC's High DER Future rulemaking ([R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com)) in response to "Draft Electrification Impacts Study Part 2" (EIS Part 2) reports submitted by PG&E, SCE, and SDG&E. (*See our coverage of these reports* [*here*](https://www.calregulatory.com/wednesday-aggregate-transmission-planning-sce-rates-biomethane-costs/) *and* [*here*](https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/)*.*) The comments address the utilities’ modeling of distribution-system impacts from electrification through 2040, including projected primary and secondary grid upgrade costs, demand flexibility scenarios, and proposed approaches for integrating the study’s findings into future distribution planning and execution processes, as required by a 2024 decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)). Parties mostly agree that the draft reports represent a substantial analytical effort but also fall short of providing a reliable foundation for near-term distribution planning without further refinement and transparency. They argue that the Final Reports must: - Clearly explain methodologies, assumptions, and data sources; - Respond directly to party feedback; and - Allow for a robust round of technical and implementation-focused comments before the results are relied upon in distribution planning or cost recovery. Several parties caution that, as drafted, the studies risk being misused as de facto spending justifications rather than illustrative planning tools, particularly given rate affordability pressures and the scale of electrification-driven investment at issue. ### Modeling Issues A dominant theme is concern that the utilities’ modeling approaches (especially for the secondary distribution system) are inconsistent, overly conservative, and insufficiently aligned with modern best practices. [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904925.PDF?ref=calregulatory.com), the [Utility Consumers' Action Network](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904791.PDF?ref=calregulatory.com) (UCAN), and [California Community Choice Association](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K255/591255769.PDF?ref=calregulatory.com) (CalCCA) all highlight large and unexplained discrepancies among PG&E, SCE, and SDG&E in projected secondary system costs, arguing these differences stem from methodological choices rather than underlying grid realities. Commenters criticize the reliance on deterministic “snapshot” methods, conservative thermal assumptions, and manual solutioning, which they argue systematically inflate projected upgrade needs and bias outcomes toward traditional wires solutions. Multiple parties urge the Commission to require clearer documentation, additional sensitivities, and, in some cases, probabilistic or time-series analyses before accepting the results for planning purposes. ### Undervalued Alternatives Another critique is that demand flexibility and non-wires alternatives are undervalued or incompletely represented. [Environmental Defense Fund](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K986/590986300.PDF?ref=calregulatory.com), UCAN, and CalCCA argue that the utilities’ scenarios often exclude key tools (e.g., flexible service connections, smart panels, and more realistic Demand Response adoption pathways) or fail to account for program and administrative costs, preventing a true cost-effectiveness comparison. This “capital-only” treatment of flexibility, commenters contend, distorts the relative economics of grid upgrades versus demand-side solutions and undermines the Commission’s modernization objectives. Some parties recommend requiring "Total Resource Cost" perspectives, realistic participation assumptions, and clearer distinctions between load shifting and shedding to avoid overstating both risks and infrastructure needs. ### Evidence of Electrification's Value At the same time, the [Vehicle-Grid Integration Council](https://www.vgicouncil.org/?ref=calregulatory.com) (VGIC) [stresses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M591/K255/591255767.PDF?ref=calregulatory.com) that the draft reports nevertheless provide strong evidence of the value of electrification and, in particular, electric vehicle-enabled demand flexibility. VGIC highlights findings showing substantial avoided distribution costs driven by managed charging and vehicle-to-grid strategies. VGIC urges the Commission to build on this evidence by expanding Vehicle Grid Integration programs and ensuring that all utilities model bidirectional EVs and active charging management consistently. **INSTANT ANALYSIS:** There is broad stakeholder agreement that EIS Part 2 is useful as a planning exercise, but not ready to support near-term distribution investment decisions. Parties warn that inconsistent and conservative modeling choices (particularly for the secondary system and demand flexibility) risk overstating upgrade needs and biasing outcomes toward traditional wires solutions at a time of heightened rate sensitivity. ### PG&E, SCE, and SDG&E Propose Customer Reliability Report Template in Resiliency Rulemaking URL: https://www.calregulatory.com/pg-e-sce-and-sdg-e-propose-customer-reliability-report-template-in-resiliency-rulemaking/ Last updated: 2025-12-16T19:53:54.000Z PG&E, SCE, and SDG&E jointly[ filed](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K649/590649143.PDF?ref=calregulatory.com) a proposed Customer Reliability Report template and data schema in the CPUC's Safety, Reliability and Resiliency of Electrical Distribution Systems docket ([R.24-05-023](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M533/K030/533030041.PDF?ref=calregulatory.com)) to standardize how customer outage experience is reported across utilities. The proposal responds to [an ALJ ruling ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K956/576956025.PDF?ref=calregulatory.com)and is intended to improve transparency and consistency while aligning new reporting requirements with existing CPUC and Energy Safety frameworks, rather than creating duplicative obligations. The IOUs recommend annual reporting to ensure data accuracy and verification, request additional lead time before the first report is due, and raise concerns about certain requirements (particularly overhead versus underground designations), arguing they may not yield meaningful insights. The proposed template focuses on outage notifications, prevention and restoration practices, and reliability metrics such as "Customers Experiencing Multiple Interruptions" and "Customer Experiencing Long-Interruption Duration"), with customer- and outage-level data designed to integrate with existing [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) (OEIS) wildfire mitigation reporting. **INSTANT ANALYSIS:** This filing is an effort by the investor-owned utilities to define the scope and limits of customer-level reliability oversight. The utilities push for annual reporting and alignment with OEIS wildfire datasets. They also challenge data requirements they see as low-value, such as simple overhead/underground labels. The apparent objective is to keep the new reporting framework bounded and auditable, rather than opening the door to ongoing, meter-level performance scrutiny with downstream enforcement or ratemaking consequences. ### Natural Gas Storage Update URL: https://www.calregulatory.com/natural-gas-storage-update/ Last updated: 2025-12-16T19:54:13.000Z Wild Goose Storage and Lodi Gas Storage filed a [joint application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K511/590511213.PDF?ref=calregulatory.com) at the CPUC seeking exemptions from the Public Utilities Code to support a 2025 refinancing of their Brookfield-owned gas storage assets. Their proposed transaction would replace the prior asset-based lending facility with a new **$350 million** revolving credit facility and continue an amended **$1.25 billion** term loan through 2031\. As part of the refinancing, Wild Goose and Lodi would pledge their assets and provide corporate guarantees to support affiliate-level borrowing. The applicants argue that portfolio-wide financing lowers borrowing costs, improves liquidity, and does not impair safety or service, noting that both facilities operate at market-based rates with no captive customers and that similar exemptions have been repeatedly approved in prior re-financings. Protests to this item will be due 30 days from when it appears on the CPUC's Daily Calendar. **INSTANT ANALYSIS**: This filing continues the Commission’s long-standing practice of allowing independent gas storage operators to participate in portfolio-level financings. The filing reinforces that the CPUC remains comfortable with asset pledges and affiliate guarantees where storage facilities: - Operate at market-based rates; - Have no captive customers; and - Can demonstrate that refinancing improves liquidity without increasing operational or safety risk. ### SoCalGas Update: Parties File Opening Briefs in TIMPBA Proceeding URL: https://www.calregulatory.com/socalgas-update-parties-file-opening-briefs-in-timpba-proceeding/ Last updated: 2025-12-17T02:17:39.000Z On December 12, parties filed opening briefs in the proceeding where SoCalGas [requests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K140/565140098.PDF?ref=calregulatory.com) review and recovery of **$173.8 million** of costs recorded in its Transmission Integrity Management Program Balancing Account (TIMPBA). SoCalGas's filing packages five years of transmission-integrity spending into a single reasonableness review, creating a serious test of whether its inspection, remediation, and project-management costs can withstand intervenor scrutiny. For industrial shippers, the outcome will determine how much of the 2019–2023 safety portfolio ultimately flows through into future transportation rates. --- ## **SoCalGas** SoCalGas [defends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K511/590511289.PDF?ref=calregulatory.com) its request by asserting that the challenged TIMP costs were driven by mandatory federal pipeline safety requirements under 49 CFR Part 192, including expanded threat identification, assessment, and remediation obligations that were not fully foreseeable in SoCalGas's Test-Year 2019 General Rate Case. SoCalGas argues" - Its inspections are continuous and cyclical rather than duplicative; - That work on non-HCA segments is required for system integrity; and - That labor, vendor, and related costs are properly attributable to TIMP activities. SoCalGas emphasizes the extensive record it submitted (including thousands of pages of workpapers) and contends that prior Commission approvals, including Resolution G-3600, confirm the compliance-driven nature of TIMP spending. SoCalGas asks the Commission to find the costs just and reasonable, approve full recovery of the $173.8 million undercollection, and authorize a 12-month amortization period. ## **Cal Advocates** Cal Advocatestakes a more granular approach, [recommending](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K904/590904770.PDF?ref=calregulatory.com) partial denial, totaling approximately **$79.0 million** of SoCalGas’s requested recovery. Cal Advocates argues that significant portions of SoCalGas's request lack evidentiary support, are non-incremental to prior GRC funding, or fall outside the scope of TIMP. Recommended disallowances include: - Straight-time labor; - Vacation and sick leave costs already embedded in prior revenue requirements; - Costs associated with Pipeline 235 West that failed to comply with Commission directives; and - Misclassified vendor expenses. Cal Advocates recommends a reduced recovery amount consistent with documented, incremental, and properly scoped expenditures. ## **Indicated Shippers** The Indicated Shippers [call](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K508/590508260.PDF?ref=calregulatory.com) for full denial of SoCalGas’s $173.8 million request, framing it as the second installment of an unprecedented pattern of TIMP overspending during the TY 2019 GRC cycle. The Shippers argue that SoCalGas has exceeded authorized budgets by accelerating discretionary assessments years ahead of federal deadlines, without adequate planning, cost controls, or documentation. The brief emphasizes the disparity between federal cost estimates and SoCalGas’s actual expenditures as evidence of inefficiency and imprudence, and warns that a 12-month recovery would impose severe rate impacts (particularly an estimated **18.7% increase** in Backbone Transportation Service rates). If any recovery is allowed, Indicated Shippers argue it should be amortized over at least 36 months to mitigate rate shock and better align with affordability and long-term gas system planning policies. ## **Small Business Utility Advocates (SBUA)** SBUA [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K417/590417557.PDF?ref=calregulatory.com) that SoCalGas has failed to meet its burden to demonstrate that the $173.8 million in TIMP costs recorded in the TIMP Balancing Account are just and reasonable. SBUA contends the record lacks sufficient project-level justification, workpapers, and cost-effectiveness analysis, particularly for **$62.3 million** in inspection costs incurred within a short time frame. It argues that SoCalGas improperly front-loaded inspections despite long federal compliance timelines, failed to show that federal rule changes directly caused the cost overruns, and failed to establish that the expenditures were incremental or non-duplicative. SBUA urges the Commission to deny the full request, require completion of a previously ordered independent TIMP study before any recovery, and direct SoCalGas to seek any future recovery through its next General Rate Case. At minimum, SBUA requests disallowances and deferral of contested costs to a future proceeding. **INSTANT ANALYSIS:** This case is less about pipeline safety than about execution and cost governance. Federal compliance is not in dispute; the central question is whether SoCalGas can recover costs driven by its own decisions about timing, scope, and pace. Intervenors largely align in arguing that SoCalGas advanced inspections years ahead of federal deadlines, ran far beyond GRC-authorized budgets, and failed to clearly connect that spending to unavoidable regulatory requirements. In their eyes, the Commission is being asked to decide whether the TIMP balancing account is a safeguard for compliance uncertainty or a mechanism that absorbs aggressive program expansion after the fact. For CRI readers, a key implication is how the Commission treats discretion inside federally driven programs. The most likely outcome is not an all-or-nothing ruling but a mix of disallowances, extended amortization, or deferral of recovery to the next GRC to allow a broader review of TIMP scope and controls. A final decision in this proceeding may set an important precedent on how the CPUC expects utilities to document incrementality, pacing, and cost discipline when safety programs exceed authorized levels. *Additional CRI coverage of this proceeding can be found* [*here*](https://www.calregulatory.com/socalgas-updates-timpba-motion-cash-out-rates/)*.* ### MONDAY AGGREGATE: Resource Adequacy; Provider of Last Resort; Wildfire Cost Recovery URL: https://www.calregulatory.com/monday-aggregate-resource-adequacy-provider-of-last-resort-wildfire-cost-recovery/ Last updated: 2025-12-16T19:54:50.000Z Today's roundup covers: - The compression of Resource Adequacy reform into a seven-month Track 1 window; - The formalization of high barriers to Provider of Last Resort competition; and - The placement of **$1.9 billion** in PG&E wildfire cost recovery into full evidentiary review. Other items include the Commission's modification of data-center interconnection economics to protect ratepayers, the rejection of PG&E's request for expedited short-term debt authority, and a denial of two years of PG&E gas Research, Development, and Demonstration spending. ## RESOURCE ADEQUACY President **Alice Reynolds** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K884/590884355.PDF?ref=calregulatory.com) that establishes the framework for the CPUC’s next phase of Resource Adequacy reform, focusing on forward procurement obligations (beginning with the 2027 compliance year) and continued refinement of the Slice-of-Day RA program. The ruling divides the proceeding into two tracks. - Track 1, running through early July 2026, addresses time-sensitive issues for the 2027 RA year, including adoption of 2027–2029 Local Capacity Requirements and 2027 Flexible Capacity Requirements based on CAISO studies, along with such program refinements as accreditation methodologies for long-duration storage, solar and wind resources, development of a final Unforced Capacity framework, transactability issues under Slice of Day, residual unit commitment requirements, and proposals related to energy-only resources. - Track 2 will address system, flexible, and local capacity requirements for later years (2028–2030), potential adjustments to the planning reserve margin informed by Loss of Load Expectation studies, and broader RA refinements, with coordination alongside Integrated Resource Planning where appropriate. Track 1 party proposals are due January 23. **INSTANT ANALYSIS**: This ruling formally launches the CPUC’s next major Resource Adequacy rulemaking for the 2027–2029 timeframe and sets an aggressive Track 1 schedule aimed at resolving time-sensitive capacity requirements by early July 2026\. The Commission is clearly prioritizing near-term reliability mechanics (local capacity, flexible capacity, Slice-of-Day refinements, and accreditation methodologies) over broader reforms, which suggest there is a limited appetite for reopening foundational RA design questions this cycle. For load-serving entities, developers, and traders, the key takeaway is compression risk: multiple consequential RA determinations are being funneled into Track 1, with little margin for delay. Issues that miss this window may slip into later tracks, potentially creating misalignment between procurement obligations and evolving market realities. --- ## PROVIDER of LAST RESORT Commissioner **Darcie Houck** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K884/590884359.PDF?ref=calregulatory.com) establishing a a procedural framework for how non-investor-owned entities may seek designation as a Provider of Last Resort under [Senate Bill 520](https://californiachoiceenergyauthority.com/senate-bill-520-sb-520-provider-of-last-resort-polr/?ref=calregulatory.com), without pre-judging eligibility criteria in the absence of a concrete applicant. (Providers of Last Resort are the load-serving entity designated to supply electricity to customers when their chosen provider fails or exits the market). The PD concludes that, because no non-IOU entity has expressed intent to assume full POLR responsibility for all customer classes in a geographic area, it would be inefficient and speculative for the Commission to resolve detailed substantive issues in advance. Instead, the PD adopts a streamlined, application-driven approach under which any prospective non-IOU Provider of Last Resort must submit a comprehensive application demonstrating compliance with Senate Bill 520’s minimum statutory requirements, including financial security, insurance, procurement compliance, technical and operational capacity, and protections against cost-shifting. The PD: - Clarifies that Provider of Last Resort obligations may not be divided by customer class; - Affirms that IOUs cannot veto a non-IOU Provider of Last Resort application but must participate in a joint filing process where feasible; and - Leaves questions regarding the scope of Commission regulatory authority to be resolved on a case-specific basis. Comments are due **January 2, 2026**. The earliest the Commission will consider this item is **January 15**. **INSTANT ANALYSIS**: A Provider of Last resort is the grid's safety net: boring by design, expensive to run, and essential when markets break. This PD does not open the door to near-term non-IOU POLR competition. The PD instead formalizes a high bar and a case-by-case, application-driven process that effectively preserves IOUs as default Providers of Last Resort unless (and until) a well-capitalized, full-service alternative steps forward. The PD explicitly rejects customer-class-only Provider of Last Resort models, requires universal service capability, and signals that cost recovery, regulatory scope, and affiliate issues will be litigated individually (which raises transaction costs for any prospective applicant). The PD functions as a gating framework rather than an invitation to entry, reinforcing system stability while deferring substantive policy choices until a real applicant emerges. --- ## WILDFIRES Commissioner **Matthew Baker** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K417/590417551.PDF?ref=calregulatory.com) that sets the procedural framework for PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323960.PDF?ref=calregulatory.com) to recover wildfire-related costs from the 2019 Kincade Fire and 2021 Dixie Fire under [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com) (*see our summary of the application* [*here*](https://www.calregulatory.com/wednesday-aggregate-2/),). PG&E seeks a review of costs recorded in its Wildfire Expense Memorandum Account and Catastrophic Event Memorandum Account, including claims paid by the Wildfire Fund, unreimbursed claims and litigation costs, and restoration-related capital and O&M expenses. The proceeding is governed by Public Utilities Code Section 451.1, which requires the CPUC to determine whether PG&E’s conduct related to each fire was reasonable and whether the associated costs are just and reasonable. Intervenor testimony is due **April 13**, with rebuttal testimony due **May 29**. **INSTANT ANALYSIS:** With nearly $1.9 billion at stake (**$1.59 billion** in wildfire claims, litigation, and financing costs plus **$314 million** in restoration expenses), this scoping memo establishes a full prudence and reasonableness review of PG&E’s Kincade and Dixie Fire cost recovery under AB 1054\. All major cost categories (claims, litigation, and restoration) are subject to evidentiary scrutiny, absent settlement. The ruling declines to bifurcate the proceeding for now, keeping both fires on a single procedural track and preserving intervenor leverage while maintaining a November 2026 decision deadline. The case will turn on whether PG&E can defend its pre-ignition conduct and cost management under the Section 451.1 standard, including potential shareholder exposure if any Wildfire Fund-paid claims are found unjustified. --- ## DATA CENTERS The CPUC issued a [draft resolution](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K889/590889612.PDF?ref=calregulatory.com) approving (with modifications) PG&E’s [request ](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7635-E.pdf?ref=calregulatory.com)to energize a new 90-megawatt Microsoft data center in San Jose through transmission-level upgrades, including new 115-kilovolt facilities and dedicated lines. The Draft Resolution finds the agreements necessary but determines that applying the standard [Electric Rule 15](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/electric-reliability/undergrounding-program-description/rule-20/cpuc-rule-20-undergrounding-programs-current-proceeding-r1705010/electric-tariff-rules-15-and-16-distribution-line-and-service-extensions?ref=calregulatory.com) refund framework without adjustment would pose undue risk to ratepayers due to the project’s size, transmission-level interconnection, and uncertainty around long-term revenue realization. To address this risk, the draft resolution modifies the Base Annual Revenue Calculation refund process by limiting annual refunds to 75% of PG&E’s actual net transmission revenues from Microsoft, with an adjustment for the Income Tax Component of Contribution, and extends the refund period from ten to fifteen years. Microsoft must pay actual construction costs and receives no refunds for special facilities it requested. The draft resolution emphasizes that this is an exceptional, non-precedential determination and directs PG&E to file conforming agreements. This item is tentatively scheduled for Commission consideration on **January 15**. **INSTANT ANALYSIS:** This draft resolution approves PG&E’s Microsoft data center energization as an exceptional case but changes the refund mechanics to protect ratepayers. By limiting annual refunds to 75% of actual net transmission revenues (plus Income Tax Component of Contribution) and extending the refund window to 15 years, the draft resolution avoids allowing large, transmission-level loads to recover upfront costs faster than revenues are actually realized. The key takeaway is that large data centers and other hyperscale loads should expect customized refund treatment and slower cost recovery when transmission upgrades are involved. This preserves project viability while making clear that distribution-level refund assumptions will not be applied wholesale where ratepayer exposure could arise, particularly ahead of a final [Rule 30](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-streamlines-electric-grid-connections-for-high-energy-users-like-data-centers-and-ev-chargers?ref=calregulatory.com) framework. --- ## UTILITY FINANCES Commissioner **Darcie Houck** issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K506/590506545.PDF?ref=calregulatory.com) addressing PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K039/583039515.PDF?ref=calregulatory.com) to increase its authorized short-term borrowing by **$2.0 billion**, from $8.5 billion to $10.5 billion. In response to a protest filed by Cal Advocates, PG&E is directed to file a supplemental showing by **January 5**, detailing its intended uses of the additional authority, liquidity and tail-risk needs, interest rates, and whether further increases may be sought. The ruling denies PG&E’s request for expedited treatment, finding no near-term urgency, and adopts a standard schedule with a potential evidentiary hearing and a proposed decision expected in spring 2026. **INSTANT ANALYSIS:** This ruling presses PG&E to more clearly justify why additional short-term debt authority is needed now. By ordering a supplemental filing and rejecting an expedited schedule, the ruling frames this as a transparency and capital-discipline test rather than a routine financing approval, giving intervenors room to probe liquidity assumptions, use of proceeds, and whether existing credit capacity already addresses near-term risk. --- ## RENEWABLE NATURAL GAS PG&E, SoCalGas/SDG&E, and Southwest Gas filed a [joint advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5149-G.pdf?ref=calregulatory.com) to document their 2025 research on the impacts of mercury on natural gas pipeline integrity. - The filing explains that, due to historically limited and largely inapplicable research on mercury impacts outside of cryogenic liquefied natural gas operations, the utilities have continued to rely on an existing mercury trigger level of 0.08 mg/m³ while conducting additional study. - Operational data from renewable natural gas interconnections across dairy, wastewater, food waste, and landfill sources show no mercury exceedances to date, including new landfill RNG injections that began in late 2025\. - The utilities also describe ongoing laboratory research led by Southwest Research Institute under a Gas Technology Institute project, including multi-month exposure tests of pipeline and end-use materials at elevated mercury concentrations. Phase 2 testing is nearing completion, with final results expected in 2026\. The utilities state they will review those results to determine whether sufficient evidence exists to propose updated mercury trigger or action limits for California’s natural gas distribution systems. Protests are due **January 2**. **INSTANT ANALYSIS:** This filing keeps the status quo in place. The utilities again document the absence of mercury exceedances across RNG interconnections and confirm that no changes to mercury trigger or action limits are proposed at this time. The substantive work is occurring off-docket in laboratory testing, with any potential regulatory follow-on pushed into 2026 after Phase 2 results are finalized. --- ## NATURAL GAS RESEARCH The CPUC issued [Draft Resolution G-3618](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K877/590877312.PDF?ref=calregulatory.com), which denies PG&E’s proposed Gas RD&D Investment Plans for 2024 and 2025 and rejects its request to recover **$7.2 million** in RD&D costs from 2023–2024\. Although funding levels were authorized in PG&E’s 2023 General Rate Case, the Commission finds the plans fail to: - Demonstrate ratepayer benefits; - Avoid duplication with other gas and hydrogen programs; - Properly allocate administrative costs; and - Meet reporting and consultation requirements. Consequently, PG&E may not record RD&D expenses for these years. PG&E is directed to resubmit revised 2024 and 2025 plans within 60 days addressing the identified deficiencies. The draft resolution also establishes more prescriptive planning, coordination, and reporting requirements for future Gas RD&D plans beginning in 2026, and requires unspent funds to be returned to ratepayers at the end of the current GRC cycle. The earliest the CPUC will consider this item is **January 15**. **INSTANT ANALYSIS:** The draft resolution makes clear that prior GRC authorization is not a green light to spend. For gas utilities, this sets a higher bar for RD&D filings and narrows the path for hydrogen-related work until the Commission provides clearer guidance on ratepayer funding. ### WEEKEND NEWS CODEX: Climate Disclosure Regulations; L.A. Sues Oil Companies; Coastal Commission Votes to Extend Diablo Canyon URL: https://www.calregulatory.com/weekend-news-codex-6/ Last updated: 2025-12-16T19:55:11.000Z - **America is Losing Power Projects When it Needs Them Most:** "'Battery cannibalization'—where growing capacity drives down the prices batteries earn—is making it harder to build profitable battery projects. Texas battery revenues crashed 70% from $192/kW in 2023 to $55/kW in 2024, while ancillary service prices fell 90%. California saw similar declines, with revenues falling from $103/kW in 2022 to just $53/kW in 2024." [**CLEANVIEW**](https://newsletter.cleanview.co/p/america-is-losing-power-projects?ref=calregulatory.com) - **Analysis Finds "Anytime Electricity" From Solar Available as Battery Costs Plummet:** "In 2024, Texas, California, Arizona, and Nevada all saw significant utility-scale battery growth, with the U.S. adding 10 GW of utility-scale batteries nationally, an 80% increase over the previous year. This growth is accelerating the integration of solar into the grid." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/12/12/analysis-finds-anytime-electricity-from-solar-available-as-battery-costs-plummet/?ref=calregulatory.com) - **Bid Optimization - ERCOT & CAISO Market Outlook, Week of December 10, 2025:** "Market conditions have been quiet in CAISO as net load levels have been low and congestion has been limited, partially due to more limited winter solar production. The day-ahead market is pricing in more congestion than the real-time market. If this continues, expect lower real-time prices in NP15 relative to higher real-time prices in NP15 (relative to day-ahead pricing thresholds). Operators should focus on energy arbitrage and regulation down to grind out additional revenue for the rest of 2025." [**ASCEND ANALYTICS**](https://www.ascendanalytics.com/blog/bid-optimization-ercot-caiso-market-outlook---week-of-december-10-2025?ref=calregulatory.com) - **Blue States, High Rates:** "Instead of trying to expand electricity generation to meet the energy needs of Californians, California is second in the country in [electricity imports](https://www.eia.gov/state/?ref=calregulatory.com), as it embeds policy goals in [electric rates to drive social policy](https://raterealities.com/wp-content/uploads/2025/08/IOU-Bill-Stack-Analysis-06.30.25-FINAL.pdf?ref=calregulatory.com). This is a toxic mix for California’s ratepayers." [ **INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/the-grid/blue-states-high-rates/?ref=calregulatory.com) - **California's Grid Under Pressure – Affordability, AI, and the Future of Electricity Markets:** "While large load growth in California is more modest than in some other states such as Texas or Virginia, the state still expects 2.3 gigawatts of new data center demand by 2030." [**ENERGY GANG**](https://open.spotify.com/episode/5zAvMZDHXP40v6LIyIJNdj?si=29075a0c2f52455b&nd=1&dlsi=dcf842ac9dbb49cc&ref=calregulatory.com) - **California's Last Nuclear Power Plant Faces Renewed Scrutiny as it Gains Latest Permit**: "The commissioners on Thursday were not deciding whether to allow the plant to stay open but were weighing how best to lessen the environmental impacts of its operation. A 2022 state law forced the plant to stay open for five more years past its planned 2025 closure date, which could have led to significant political blowback against the Coastal Commission if it had rejected the permit." [**CAL MATTERS**](https://calmatters.org/politics/2025/12/california-diablo-canyon-permit-approved/?ref=calregulatory.com) - **California Coastal Commission Votes 9-3 to Extend DCPP Operations to 2030**: "This is a big deal. Over the years, the California Coastal Commission has not been a friend of Diablo Canyon Power Plant. Thus, this vote is significant after they tabled the DCPP motion last month. This was a huge team effort involving plant owner PG&E, nuclear power advocates, and concerned political leaders." [ **GREEN NUKE**](https://greennuke.substack.com/) - **California Energy Price Data for November 2025:** "...Cap & Trade costs overall show a gradual rise as activity on the program’s extension has increased, while LCFS costs had been easing before June as the result of data corrections discussed in previous reports but sharply reversed course under the new regulations." [**CALIFORNIA CENTER FOR JOBS & THE ECONOMY** ](https://centerforjobs.org/ca/energy-reports/california-energy-price-data-for-november-2025?ref=calregulatory.com) - **California Keeps Losing Tech Jobs:** " California’s high cost of energy also means that despite the tech industry’s concentration in the Bay Area, [few data centers are planned in the state itself](https://x.com/curious%5Ffounder/status/1978835542839001525?ref=calregulatory.com), pushing more of the AI ecosystem to places like Virginia, Oregon, and Texas." [**APRICITAS ECONOMICS**](https://www.apricitas.io/p/california-keeps-losing-tech-jobs?ref=calregulatory.com) - **California Releases Draft Text for Climate Disclosure Regulations:** "Entities covered by SB 253 — which mandates emissions reporting from companies generating over $1 billion in revenue — will need to submit their scope 1 and scope 2 emissions by Aug. 10, 2026, according to the proposed rule." [**UTILITY DIVE**](https://www.utilitydive.com/news/california-releases-draft-text-for-climate-disclosure-regulations/807601/?ref=calregulatory.com) - **California Support for Crop-Based Biofuels Undermines Clean Fuels Program:** "Recent empirical studies—leveraging satellite imagery, econometric techniques, and improved datasets—show that biofuel-induced land-use change is larger and more carbon-intensive than previously understood, with emissions often exceeding those of petroleum-based fuels." [**BREAKTHROUGH INSTITUTE**](https://thebreakthrough.org/press/release-california-support-for-crop-based-biofuels-undermines-clean-fuels-program?ref=calregulatory.com) - **Congestion Revenue Rights Enhancements – Issue Paper & Straw Proposal on Product Definition:** "With increased renewable generation and battery storage, CAISO’s load shape and generation patterns have shifted. These shifts have changed energy flows and system congestion patterns. Limited product selection may adversely impact market participants’ ability to hedge present congestion risks. The straw proposes three products: peak, midday-peak, and off-peak." [**CAISO**](https://stakeholdercenter.caiso.com/StakeholderInitiatives/Congestion-revenue-rights-enhancements?%5Fgl=1%2Agv58ti%2A%5Fga%2AODAzOTY1ODQ2LjE3NTk2MDc4NDA.%2A%5Fga%5FNDS4B4M2WP%2AczE3NjU1NjAwMjgkbzE4JGcxJHQxNzY1NTYwMDM0JGo1NCRsMCRoMA..&ref=calregulatory.com) - **Crimson Renewable Energy to Pause Production at California Biodiesel Plant:** "Biodiesel producer Crimson Renewable Energy plans to pause production at its 37.3 million gal/year plant in Bakersfield, Calif., President and CEO **Harry Simpson** said on Sunday. After Crimson finishes December production, the company will not produce biodiesel in the first half of 2026, 'because of the continued poor margin environment,' Simpson said. In November, Crimson laid off 'significant numbers of staff' as a result of the decision but also kept a sizeable operations team at the facility so production can be resumed 'with fairly short notice when we get the right market and policy signals,' Simpson said." [ **OPIS**](https://www.opis.com/resources/energy-market-news-from-opis/crimson-renewable-energy-to-pause-production-at-california-biodiesel-plant/?ref=calregulatory.com) - **Eclipse Energy's Microbes Can Turn Idle Oil Wells into Hydrogen Factories:** "The Houston-based startup, which was spun out of Cemvita, demonstrated the technology at an oilfield in California’s San Joaquin Basin last summer. Now, it’s partnering with oilfield services company Weatherford International to deploy the technology around the world..." [**TECH CRUNCH**](https://techcrunch.com/2025/12/11/eclipse-energys-microbes-can-turn-idle-oil-wells-into-hydrogen-factories/?ref=calregulatory.com) - **Gavin Newsom Sticks it to California Ratepayers:** "In January, Pacific Gas & Electric, California’s largest utility, announced it was terminating power purchase agreements it signed 15 years ago, and the plant would be shuttering and dismantling the plant, which is operated, and partially owned by Houston-based NRG. Those contracts were expected to run through 2039\. Ending the contracts, PG&E said, 'will save customers money.' But last week, the California Public Utility Commission [rejected the proposed shutdown](https://www.8newsnow.com/news/local-news/ivanpah-solar-project-at-nevada-california-border-lives-on-as-regulators-reject-plan-to-shut-it-down/?ref=calregulatory.com) and ordered the plant to stay open. Why? Shelving the project would threaten the state’s efforts to achieve its renewable energy targets. The agency also said that the transmission and distribution infrastructure that ratepayers have already paid for would be 'stranded.'" [**ROBERT BRYCE**](https://robertbryce.substack.com/p/gavin-newsom-sticks-it-to-california) - **Geothermal Energy is Attracting More and More Investment:** "When it comes to electricity, geothermal makes up less than 1% of the world’s supply. The U.S. is [the global leader](https://www.canarymedia.com/articles/geothermal/zanskar-claims-geothermal-milestone-nevada?token=GFcN%5FoDdVDMsCTSytD9bSoWTe%5Fwn3nf8&x-craft-preview=5aaff8a784d0b96246bea7700ae79c5325f27c93eea2d0181f53dbfb112206bbzeryzmbzge&ref=calregulatory.com) in terms of geothermal power capacity, with much of it located in California’s steamy [Geysers region](https://www.canarymedia.com/articles/geothermal/california-newsom-veto-bill-environmental-reviews?ref=calregulatory.com). It’s no surprise, then, that America is among the countries investing the most in the energy source, topping the chart this year and last." [**CANARY MEDIA**](https://www.canarymedia.com/articles/geothermal/chart-global-investment-clean-energy?ref=calregulatory.com) - **In Emergencies, Hospitals Are Relying on Microgrids:** "Healthcare provider Kaiser Permanente, which owns and operates 40 hospitals and over 600 medical office buildings across the US, has microgrids at a handful of its California locations. The system’s Ontario, California, hospital hosts its largest microgrid with on-site solar, a fuel cell system, and batteries—which can supply the entire electrical load of the hospital for a limited amount of time. And though the hospital does have a diesel generator for backup power, the microgrid would primarily supply power during an outage." [ **TECH BREW**](https://www.techbrew.com/stories/2025/12/09/hospital-microgrids?ref=calregulatory.com) - **Los Angeles Sues Oil Companies for Well Cleanup and Environmental Damage:** "The County of Los Angeles is [suing](https://file.lacounty.gov/SDSInter/lac/1197540%5FSentinelOilWellComplaintFinal.pdf?ref=calregulatory.com) four oil companies for failing to plug and decommission exhausted oil wells in the Inglewood Oil Field. The lawsuit against Sentinel Peak Resources California LLC, Freeport-McMoran Oil & Gas LLC, Plains Resources, Inc., and Chevron alleges that the wells released 'toxic pollutants into the air, land, and water and present unacceptable dangers to human health, safety, and the environment.'" [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/los-angeles-sues-oil-companies-for?ref=calregulatory.com) - **Racing Against the Storm – Utilities Accelerate Grid Resilience Efforts:** "n 2023, Pacific Gas & Electric [released](https://www.pge.com/assets/pge/docs/about/pge-systems/2025-innovation-pitch-fest-preread.pdf?ref=calregulatory.com) a list of its most challenging technical and operational challenges and urged technology companies to offer solutions and the opportunity to partner with PG&E to develop and implement them. More recently, the utility [hosted](https://investor.pgecorp.com/news-events/press-releases/press-release-details/2025/PGEs-2025-Innovation-Pitch-Fest-Seeks-Breakthrough-Technologies-to-Shape-the-Energy-Future/default.aspx?ref=calregulatory.com) a three-day Innovation Pitch Fest, where technology companies with solutions to reduce wildfire risk and other challenges could present their ideas and compete for up to $25 million in funding, as well as a pathway to co-develop and scale their solutions into PG&E’s systems." [**EPRI JOURNAL** ](https://eprijournal.com/racing-against-the-next-storm-utilities-accelerate-grid-resilience-efforts/?ref=calregulatory.com) - **Sugar Valley Energy, in Partnership with IVEDCC, Awarded California Jobs First Grant Through the Southern Border Coalition:** "California Ethanol + Power and the Imperial Valley Economic Development Corp. announced on Dec. 11 that the planned renewable fuel and energy campus Sugar Valley Energy has been selected to receive a Jobs First Grant through the Southern Border Jobs First Collaborative. The award represents a significant milestone for the project and for Imperial County, one of California’s most economically challenged regions." [**BIOMASS MAGAZINE**](https://biomassmagazine.com/articles/sugar-valley-energy-in-partnership-with-ivedc-awarded-california-jobs-first-grant-through-the-southern-border-coalition?ref=calregulatory.com) ### FRIDAY AGGREGATE: DER Flexible Connections; IRP Procurement; Gas Distribution Cost Data URL: https://www.calregulatory.com/friday-aggregate-der-flexible-connections-irp-procurement-gas-distribution-cost-data/ Last updated: 2026-01-06T04:06:43.000Z Regulatory activity this week ricochets between near-term innovation and longer-term strategic uncertainty. - PG&E's DER flexible connections filing shows the utility examining meter-based workarounds for panel upgrades while the broader ADMS/DERMS modernization remains years away. - CalCCA's continued pushback on additional IRP procurement orders highlights a serious issue now facing the Commission: whether to direct thousands more megawatts of capacity based on unprecedented load forecasts, or wait until 2027 for better visibility on data-center interconnections and import availability. Elsewhere, contract amendments reflect persistent storage-market pressures, routine transmission and ERRA compliance items are in the mix, and tariff clarifications close loops from prior decisions. --- ## DISTRIBUTED ENERGY RESOURCES PG&E filed a [supplemental response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K408/590408853.PDF?ref=calregulatory.com) to an Assigned Commissioner’s Ruling seeking additional information on near-term, DER-enabled flexible connections for single-phase customers in the CPUC's High DER Future docket.\* PG&E says it is developing a suite of approaches (ranging from traditional service upgrades to new [AMI-2.0](https://blog.landisgyr.com/en/us/ami-2.0-playbook?ref=calregulatory.com)\-enabled controls) to help residential customers electrify without immediate panel or service upgrades. - A key part of the work is an [Electric Program Investment Charge](https://www.sce.com/regulatory/regulatory-information/epic?ref=calregulatory.com)\-funded pilot that uses an AMI 2.0 meter running a local DER management application, which communicates with peer meters and customer devices to calculate and enforce real-time dynamic service limits based on local grid capacity. - PG&E describes this as a residential, secondary-system version of [Flex Connect ](https://www.pge.com/assets/pge/docs/clean-energy/electric-vehicles/flexible-service-connection-pilot-overview.pdf?ref=calregulatory.com)intended to minimize or defer upgrades while keeping load within safe limits. - PG&E outlines expected implementation steps, identifies protocols such as [Open Charge Point Protocol](https://en.wikipedia.org/wiki/Open%5FCharge%5FPoint%5FProtocol?ref=calregulatory.com) 1.6J and [UL 3141/Matter](https://www.mayfield.energy/technical-articles/ul-3141-and-power-control-systems-explained/?ref=calregulatory.com) for device coordination, and explains how aggregators or manufacturers could scale multi-customer coordination across shared infrastructure. - PG&E argues that current rules already allow dynamic operating envelopes and opposes mandatory enrollment of these customers into dynamic rate pilots, citing both customer choice and the potential mismatch between operating-envelope constraints and price-response opportunities. The company anticipates early customer testing in **2026** and a broader rollout (contingent on proof-of-concept results) and approval of AMI 2.0 in its General Rate Case. **INSTANT ANALYSIS:** Thisfiling reinforces the broader picture that California is still years away from systemwide, customer-level dynamic envelopes. However, PG&E's exploration of a narrower, meter-based pathway could enable early flexible connections for single-phase residential customers. While PG&E's AMI-2.0 edge-control concept doesn’t eliminate the multi-year runway facing [Advanced Distribution Management System](https://gridmap.gridwise.org/technologies/advanced-distribution-management-system/?ref=calregulatory.com#:~:text=An%20ADMS%20can%20collect%2C%20organize%2C%20display%2C%20and,power%20flows%2C%20maintain%20reliability%2C%20and%20prevent%20overloads.)/[Distributed Energy Resource Management System](https://www.nrel.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com) modernization, it does suggest that limited, local forms of flexible interconnection may emerge sooner for panel-upgrade deferral, even as full circuit-level dynamic operations remain out of reach. --- ## LONG-TERM GAS PLANNING Separately, PG&E [submitted an amended response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K408/590408830.PDF?ref=calregulatory.com) in the Long-Term Gas Planning rulemaking to correct and clarify the gas distribution cost data it [previously filed](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273755.PDF?ref=calregulatory.com) on November 5\. After reviewing PG&E’s original submission, Energy Division requested specific corrections, including fixing an “average” that should have been a “total” in one row and revising the dataset to include only medium-pressure regulator stations to ensure comparability across utilities. The amended filing republishes the data with corrected summary and district-level cost figures for regulator-station replacement work, covering such metrics as per-service and per-meter replacement costs, total recorded work-order expenditures, and planning and construction durations. For SoCalGas/SDG&E's equivalent filing, see our summary [here](https://www.calregulatory.com/wednesday-aggregate-4/). **INSTANT ANALYSIS:** PG&E’s amended filing is a technical correction, but it matters for the Commission’s emerging gas-distribution cost baseline in this proceeding. The main takeaway is that PG&E’s average regulator-station rebuild cost remains extremely high (**$3.0 million** per station; **$1,224** per service) and planning durations remain long (**782** days). These numbers will inform future debates about gas portfolio right-sizing, district-level risk targeting, and long-run rate impacts. --- ## PG&E NATURAL GAS RATES The CPUC issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K070/590070310.PDF?ref=calregulatory.com) in PG&E's 2027 Gas Cost Allocation and Rate Design case ("GCARD"), adjusting the normal 30-day protest window because it would otherwise fall during the year-end holidays. The ruling extends the protest deadline to **January 7, 2026**, with PG&E’s reply due **January 20, 2026.** [As previously noted at CRI](https://www.calregulatory.com/monday-aggregate-pg-es-card-filing-erra-pds-for-pg-e-and-sce-ious-hydrogen-blending-demo-projects/), this filing combines PG&E's historically separate Gas Cost Allocation Proceeding and Gas Transmission & Storage CARD into a single, unified framework. - The proposal recalibrates distribution, transmission, storage, and inventory-management costs using updated 2027–2030 forecasts, a shift to embedded-cost distribution methods, revised backbone path differentials, a new empirical imbalance-cost model, and an increase to the residential minimum monthly charge from $4 to **$15**. - While falling backbone and inventory-management costs look to provide short-term relief (especially for residential customers in 2027) projected increases in storage revenue requirements and class rebalancing drive future upward pressure on rates, with small commercial, industrial, and certain wholesale/noncore groups seeing the largest impacts. **INSTANT ANALYSIS**: This ruling is purely procedural but still relevant: it pushes protest deadlines into January, ensuring parties have a full opportunity to develop substantive objections or proposals rather than rushing through the holiday period. --- ## INTEGRATED RESOURCE PLANNING The California Community Choice Association (CalCCA) [met with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K070/590070320.PDF?ref=calregulatory.com) Commissioner **Matt Baker**’s advisors on December 8 to outline its concerns with issuing another near-term procurement order in the Integrated Resource Planning proceeding. - CalCCA emphasized that ad hoc procurement directives tend to distort markets, elevate developer leverage, and raise costs, noting [Sonoma Clean Power](https://sonomacleanpower.org/?ref=calregulatory.com)’s experience before and after recent procurement mandates. - To mitigate these effects, CalCCA described its proposal to mask individual load-serving entities' net positions in reporting so that procurement orders do not unintentionally shift market power. - CalCCA then presented data comparing historic load forecasts to actual load, arguing that the unprecedented, highly uncertain load growth embedded in the [2024 Integrated Energy Policy Report update](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr/2024-integrated-energy-policy-report?ref=calregulatory.com) warrants a cautious approach. - CalCCA suggested that if the Commission ultimately orders new reliability procurement, it should adopt a phased, flexible structure (2,000 MW in 2029–2030 and another 2,000 MW in 2031–2032) paired with a 2027 reevaluation that could incorporate updated information on large-load interconnections and import availability. CalCCA also recommended several design features for any order: crediting excess procurement toward future compliance, assigning procurement to load-serving entities rather than a central buyer, using generic (not technology-specific) capacity requirements, and applying the extended compliance rules previously adopted in a decision last September ([D.25-09-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K576/581576925.PDF?ref=calregulatory.com)). For details on CalCCA's recent IRP meeting with Commissioners **Darcie Houck** and **Karen Douglas**, see our summary [here](https://www.calregulatory.com/wednesday-aggregate-4/). I**NSTANT ANALYSIS**: CalCCA is urging the Commission to pause before directing any additional procurement, pointing to the 2024 IEPR’s extraordinary load uncertainty and the unresolved questions around future import availability. Their proposed two-tranche framework reflects the central debate in this rulemaking: - Act now to expand clean-firm capacity; or - Wait until the state has a clearer read on load growth, large-load interconnection activity, and Western Resource Adequacy conditions before committing load-serving entities to another large procurement cycle. --- ## MID-TERM RELIABILITY The Commission issued [Draft Resolution E-5432](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K550/590550980.PDF?ref=calregulatory.com), which approves PG&E’s request to further amend its Mid-Term Reliability contract with [Nighthawk Energy Storage, LLC](https://www.nighthawkenergystorage.com/?ref=calregulatory.com) (an [Arevon Energy](https://arevonenergy.com/?ref=calregulatory.com) affiliate) by extending the project’s required online date from June 1, 2025 to **June 1, 2026** and adjusting the contract price to reflect current market conditions. The Nighthawk project, originally approved in 2022 as part of PG&E’s Mid-Term Reliability procurement obligation, has faced successive delays due to interconnection challenges, permitting issues, supply-chain pressures, inflationary cost increases, and higher financing costs. Energy Division finds PG&E’s negotiated amendment reasonable, noting that absent this relief the developer would likely default, jeopardizing a **300-megawatt** storage resource essential to PG&E’s Mid-Term Reliability compliance. The Draft Resolution, which is redacted, concludes that the revised price remains competitive in the current market and that the project (now permitted, financed, and holding a CAISO interconnection agreement) has a credible path to meeting the amended June 1, 2026 delivery date. The earliest the Commission will consider this item is **January 15**. **INSTANT ANALYSIS:** This third amendment reflects the Commission’s preference to preserve a contracted 300-MW storage asset rather than risk losing it to default. The draft resolution finds a one-year delay and higher price less harmful than replacing the project mid-stream. --- ## ERRA COMPLIANCE The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K408/590408806.PDF?ref=calregulatory.com) finding that SCE’s 2022 Energy Resource Recovery Account procurement, generation management, and contract administration were largely compliant with CPUC standards and SCE's Bundled Procurement Plan. The PD authorizes recovery of **$51.442 million** in undercollected balances across five memorandum accounts (mainly tied to the [Emergency Load Reduction Program](https://elrp.sce.com/?ref=calregulatory.com)) resulting in an estimated **$0.45/month** residential bill impact in 2026\. SCE must remove CAISO sanctions from the ERRA/Portfolio Allocation Balancing Account because it failed to justify them and refund **$1.65 million** in double-charged franchise fees to departed customers via a 2026 PABA adjustment. **INSTANT ANALYSIS:** This is a straightforward item. The PD gives SCE a largely clean ERRA compliance review for 2022, authorizing recovery of $51.442 million in undercollections. Additionally, the PD affirms prudent management of utility-owned generation and contracts while imposing targeted corrections for CAISO sanctions and PABA franchise-fee overcollections, which must be refunded to customers. --- ## TRANSMISSION/FERC PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7773-E.pdf?ref=calregulatory.com) to notify the CPUC that it has submitted its annual Transmission Access Charge Balancing Account Adjustment (TACBAA) update to FERC, requesting new transmission rates effective **March 1, 2026**. The TACBAA ensures PG&E’s retail customers either recover or refund the difference between the transmission costs PG&E pays as a load-serving entity and the revenues it earns as a Participating Transmission Owner under the CAISO Tariff. In its December 5 FERC filing, PG&E reports a total 2026 TACBAA revenue requirement of **$591.1 million**, driven by a projected **$20.8 million** credit balance, **$604.0 million** in forecast TACBA costs for the coming period, and **$8 million** in revenue-fee and uncollectible adjustments. The resulting rate of **$0.00908/kWh** would be an increase from the current $0.00770/kWh. PG&E requests authority to automatically update retail-jurisdictional tariffs once FERC authorizes the change, with adjustments typically consolidated into PG&E’s late-February retail rate filings. The rate change will apply to bundled, Direct Access, and Community Choice Aggregator customers. PG&E will later supplement the advice letter once FERC acts on the filing. Protests are due **December 30**. **INSTANT ANALYSIS**: This TACBAA update points to a modest upward pull on March 1 retail transmission rates, driven primarily by higher forecast TACBA costs rather than true-up volatility. While routine, the increase folds into an already crowded March rate stack, meaning bundled, Direct Access, and Community Choice Aggregator customers should expect incremental pressure on total delivered prices. --- ## PURPA The CPUC issued[Draft Resolution E-5425](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K823/588823970.PDF?ref=calregulatory.com), which approves, with modifications, PG&E’s and SDG&E’s proposed [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant export tariffs for customer-generators who lose Net Energy Metering or Net Billing eligibility due to prevailing-wage violations under the Public Utilities Code and a 2023 CPUC decision ([D.23-11-068](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K977/520977266.PDF?ref=calregulatory.com)). The draft resolution concludes that while the filings generally comply with the decision, an explicit 20-megawatt capacity limit must be added to align with PURPA’s mandatory-purchase rules and the 20-MW standard-offer framework in a 2020 Commission decision ([D.20-05-006](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M337/K709/337709639.PDF?ref=calregulatory.com)). PG&E, SDG&E, and SCE must refile their PURPA tariffs accordingly. The earliest the CPUC will consider this item is **January 15**. **INSTANT ANALYSIS:** This draft resolution closes the loop on the wage-violation backstop tariff by standardizing all PURPA export treatment around a 20-MW cap, aligning state practice with federal purchase-obligation limits and eliminating ambiguity that emerged after D.23-11-068\. For developers and large customers, this resolves questions about how oversized NEM/NBT projects would be treated if they fall into PURPA status, while requiring all three utilities to operate from a uniform, legally defensible tariff framework. --- ### FOOTNOTE \*For additional coverage on this DERs matter, see our summary [here](https://www.calregulatory.com/monday-aggregate-diablo-canyon-der-flexible-connections-edison-psps-events/), where the utilities indicated that California is unprepared to operationalize dynamic or customer-level operating envelopes. All three utilities acknowledge that their [Advanced Distribution Management System](https://gridmap.gridwise.org/technologies/advanced-distribution-management-system/?ref=calregulatory.com#:~:text=An%20ADMS%20can%20collect%2C%20organize%2C%20display%2C%20and,power%20flows%2C%20maintain%20reliability%2C%20and%20prevent%20overloads.)/[Distributed Energy Resource Management System ](https://www.nrel.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com)stacks lack the forecasting granularity, telemetry, modeling fidelity, and communications architecture needed to support day-ahead or hour-ahead import/export limits across the polyphase grid. ### SoCalGas Updates: TIMPBA Motion; Cash-Out Rates URL: https://www.calregulatory.com/socalgas-updates-timpba-motion-cash-out-rates/ Last updated: 2025-12-15T21:37:04.000Z ## Transmission Integrity Management SoCalGas, Cal Advocates, the Indicated Shippers, and the Small Business Utility Advocates [filed a joint motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K649/590649102.PDF?ref=calregulatory.com) to admit all prepared testimony, rebuttal testimony, workpapers, and data responses into the evidentiary record of SoCalGas’s Transmission Integrity Management Program Balancing Account (TIMPBA) cost-recovery application for 2019–2023\. The motion lists each exhibit (ranging from SoCalGas’s technical, accounting, and rates testimony to Cal Advocates’, Indicated Shippers’, and SBUA’s operational and cost critiques) along with public links and confidential volumes submitted under seal. The materials cover project execution, balancing-account treatment, revenue requirement calculations, amended workpapers, rebuttal positions, and data-request exchanges, forming the full evidentiary basis for evaluating SoCalGas’s request to recover TIMP expenditures. Recall that SoCalGas filed the [TIMPBA application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M565/K140/565140098.PDF?ref=calregulatory.com) last spring, requesting review and recovery of **$173.8 million** of costs recorded in the TIMPBA. The filing packages five years of transmission-integrity spending into a single reasonableness review, creating a serious test of whether its inspection, remediation, and project-management costs can withstand intervenor scrutiny. For industrial shippers, the outcome will determine how much of the 2019–2023 safety portfolio ultimately flows through into future transportation rates. **INSTANT ANALYSIS**: The TIMPBA case is now entering its evidentiary phase, with parties agreeing to admit the full testimony and workpaper set into the record. With the evidentiary foundation established, the proceeding now moves toward briefing and a proposed decision, meaning cost-recovery outcomes will hinge on the written record rather than any remaining procedural disputes. --- ## Cash-Out Rates SoCalGas filed Advice Letter 6566-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Effective&ref=calregulatory.com)) to update its California Producer Service (G-CPS) Imbalance Cash-Out Rates for November 2025, consistent with previously approved tariff methodology. The filing reflects routine monthly updates required under a Commission-approved framework, later modified in 2017 to rely on Natural Gas Intelligence daily SoCal Border indices and a 7-day averaging method. The revised tariff sheets incorporate the November 2025 cash-out values (covering high, low, and average NGI-based indices) alongside the prior month’s October calculations. Rates are noted below. Protests to this filing are due **December 23**. **INSTANT ANALYSIS**: This is a routine, formula-driven cash-out update under the G-CPS tariff, but the numbers matter: November’s 7-day average cash-out price jumped to $0.289/therm, up from $0.217/therm in October, perhaps reflecting a tightening of SoCal Border conditions. For California producers, this could mean higher imbalance settlement exposure heading into winter. | Cash-Out Rates Using Daily Index – SoCalGas Border | | | | | -------------------------------------------------------------- | ---------------------- | -------------------- | ------------------------ | | Flow Month | 150% High Avg($/therm) | 50% Low Avg($/therm) | Avg Daily Index($/therm) | | Oct 2025 – monthly avg | n/a | n/a | 0.21736 | | Nov 2025 – monthly avg | n/a | n/a | 0.28904 | | Source: SoCalGas Daily Index • All values are monthly averages | | | | ### WEDNESDAY AGGREGATE: Gas Distribution Cost Data; Honor Rancho; Bio-Synthetic Natural Gas URL: https://www.calregulatory.com/wednesday-aggregate-4/ Last updated: 2025-12-12T19:53:55.000Z Below is a consolidated look at notable filings, advice letters, and ex parte meetings from the past few days, spanning Long-Term Gas Planning updates, compressor modernization work, IRP positions, long-duration storage procurement, Diablo Canyon cost tracking, and Rule 30 implementation. --- ## Long-Term Gas Planning Data SoCalGas/SDG&E (the Sempra Utilities) [submitted revised gas distribution cost data](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K533/590533741.PDF?ref=calregulatory.com) in the Long-Term Gas Planning docket after CPUC Staff requested corrections to their [November 5, 2025 filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273772.PDF?ref=calregulatory.com). In this updated package, SoCalGas/SDG&E supply six revised attachments covering average costs per service and per mile of main, program-level expenditures, district-level breakdowns, and planning timelines. - For main and service replacement work, the utilities report average costs of about **$21,000** per service and **$2.5 million** per mile of main, while service-only replacements average **$13,700** per service. - Annual pipeline replacement spending across programs totals approximately **$315 million**, with notable variation by operating district. - Regulator station replacements show an average cost of about **$650,000** per station, affecting approximately 2,200 services per station on average. - The filing also includes updated metrics on planning periods, completion times, and the utility-wide aggregation of cost categories such as internal labor, external labor, materials, and miscellaneous overhead. **INSTANT ANALYSIS:** By forcing SoCalGas/SDG&E to resubmit corrected, granular cost data, the Commission is laying the evidentiary groundwork for a much more disciplined gas-distribution planning regime. With this new approach, replacement costs, planning timelines, and district-level variances are no longer treated as opaque utility estimates but as standardized, comparable inputs to long-term system planning. This data will be used to shape future debates over affordability, asset retirements, and whether current replacement trajectories are economically justifiable. --- ## Compressor Modernization Work SoCalGas filed Advice Letter 6567-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Effective&ref=calregulatory.com)), notifying the CPUC that construction will begin on the [Honor Rancho Compressor Modernization Project](https://www.socalgas.com/sustainability/pipeline-and-storage-safety/storage-facility-safety/honor-rancho-modernization?ref=calregulatory.com), a compliance and reliability upgrade required under [South Coast AQMD](https://www.aqmd.gov/aq-spec/aboutscaqmd?ref=calregulatory.com) Rules 1110.2 and 1100\. - The project replaces five obsolete gas compressors with four new low-NOx gas units and two new electric-driven compressors, supported by a new 27,800-square-foot building, updated cooling and emissions-control systems, and related piping and electrical equipment. To power the electric units, SCE will build a new substation, install loop-in 66-kV lines, and complete breaker and protection upgrades at nearby substations. - Environmental impacts were previously analyzed under South Coast AQMD’s Program Environmental Impact Report and Subsequent Environmental Assessment, with an Addendum underway to cover SCE’s electrical work. - SoCalGas says that construction emissions will be mitigated, and operations are expected to reduce overall pollutant emissions. Since this is an information-only filing, it is not subject to protests. For added context, recall that, in the [2024 decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K485/550485071.pdf?ref=calregulatory.com) addressing the 2024 Test-Year General Rate Case of the Sempra Utilities (SoCalGas/SDG&E), the Commission capped Honor Rancho Compressor Station Modernization work at **$525.2 million**. **INSTANT ANALYSIS:** This filing is procedural but noteworthy: SoCalGas is moving forward with a major compressor overhaul that swaps out legacy engines for a mixed gas-electric configuration, cutting NOx and aligning with AQMD compliance timelines. Although exempt from [General Order 177](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com), the scale of SCE’s associated substation and line work suggests rising electric-load implications at storage fields, which is an emerging operational trend that bears watching. --- ## Bio-Synthetic Natural Gas Earlier this month, SoCalGas [filed a reply](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K915/588915254.PDF?ref=calregulatory.com) defending its [proposed Woody Biomass Pilot Project](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K959/583959234.PDF?ref=calregulatory.com) after protests from the Sierra Club, Cal Advocates, the Bioenergy Association of California, and Small Business Utility Advocates. (See our summary of those protests [here](https://www.calregulatory.com/monday-aggregate-pg-es-card-filing-erra-pds-for-pg-e-and-sce-ious-hydrogen-blending-demo-projects/).) - SoCalGas argues that its proposal to use Cap-and-Trade funds is consistent with Commission precedent (pointing to the [Senate Bill 1383 ](https://www.wm.com/us/en/sb1383?ref=calregulatory.com)dairy pilots) and emphasizes that project-readiness safeguards and statutory deadlines will prevent the construction of stranded infrastructure. - SoCalGas contends that its application provides adequate greenhouse-gas reduction estimates using the 2024 "[Research & Development Greenhouse gases, Regulated Emissions, and Energy use in Technologies](http://energy.gov/cmei/rd-greet-life-cycle-assessment-model?ref=calregulatory.com)" (R&D GREET) model and clarifies that the project’s gasification pathway differs from the biogas-to-biomethane systems criticized by the Sierra Club. - SoCalGas also maintains that detailed emissions-monitoring plans are not required at the application stage, though it is committed to developing reporting templates in coordination with CPUC staff, following the model of earlier biomethane pilots. In response to environmental justice concerns, SoCalGas highlights expected community benefits, job creation, and baseline-to-project emission contrasts, noting that the Sierra Club misinterprets the location and distribution of emissions. **INSTANT ANALYSIS:** SoCalGas’ reply pushes back hard on the Sierra Club’s attempt to knock out the woody-biomass pilot at the outset, leaning on SB 1383 precedent, project-readiness safeguards, and GREET-based emissions estimates to argue the application follows the CPUC's [Rules of Practice and Procedure](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/rules-of-practice-and-procedure-may-2021.pdf?ref=calregulatory.com). SoCalGas frames the remaining disputes (GHG methods, emissions monitoring, and environmental/social impacts) as issues properly handled in discovery and scoping, not as reasons to reject the pilot. --- ## Natural Gas Leak Abatement SDG&E filed Advice Letter 3474-G (available [here](https://tariffsprd.sdge.com/sdge/filings/?utilId=SDGE&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to implement the requirement adopted in [Resolution G-3606](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K066/585066732.pdf?ref=calregulatory.com), which partially approved SDG&E’s 2024 Natural Gas Leak Abatement Compliance Plan (*see our October 30 summary* [*here*](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/)). AL 3474-G updates 2026 gas transportation rates to reflect the approved Natural Gas Leak Abatement revenue requirement of **$2.9 million** for 2025–2026\. This amount is offset by a larger amount currently embedded in rates, which results in a net **$2.6 million** reduction. SDG&E explains that the revenue requirement and associated balancing accounts will be amortized in transportation rates using the Equal Percent of Authorized Margin method, spreading adjustments across customer classes proportional to their base margin shares. As shown in SDG&E's updated rate tables, core customers will see modest decreases, and noncore classes experience slightly smaller reductions, producing a systemwide revenue decrease of about **$8.1 million**. SDG&E requests a **January 1, 2026** effective date. Protests are due **December 29, 2025**. **INSTANT ANALYSIS**: This is a straightforward rate change that will roll into SDG&E's broader year-end consolidation. SDG&E’s updated Leak Abatement revenue requirement is lower than current levels, producing an $8.1 million systemwide reduction. This clean correction flows mostly to core customers. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/iterograph_Mon-Dec-08-2025--1-.png) ## Integrated Resource Planning Below is a look at some recent ex parte communications in the CPUC's Integrated Resource Planning docket. ### California Resources Corporation - California Resources Corporation (CRC) [met with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K802/589802852.PDF?ref=calregulatory.com) the offices of President **Alice Reynolds** and Commissioner **John Reynolds**, emphasizing that the current Transmission Planning Process and busbar mapping process overlooks natural-gas generation paired with carbon capture and sequestration (NGCCS). CRC argued that this technology is already commercially viable and capable of delivering near-term, clean-firm capacity. - CRC highlighted that its Elk Hills [Carbon Terravault I project](https://www.crc.com/carbon-terravault?ref=calregulatory.com) will begin CO₂ injection in Q1 2026, that additional Class VI permits are imminent, and that retrofitting existing plants such as Elk Hills and La Paloma could provide over 1.1 gigawatts of decarbonized capacity using existing interconnections. CRC maintained that NGCCS reduces both carbon and criteria pollutants, offers cost-effective firm power, and should therefore be eligible in any additional reliability procurement the Commission may order. ### California Community Choice Association - On the same day, the California Community Choice Association (CalCCA) held [separate ex parte meetings](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K802/589802865.PDF?ref=calregulatory.com) with advisors to Commissioners **Darcie Houck** and **Karen Douglas**. - CalCCA warned that ad hoc procurement orders create market distortions, shift leverage to developers, and may unnecessarily raise costs. They presented historical load-forecast data showing unprecedented uncertainty in the 2024 [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) forecast and urged the Commission to take a cautious, flexible approach before mandating new procurement. - CalCCA also argued that further study is needed before modifying import assumptions, citing publicly available [Western Electricity Coordinating Council](https://www.wecc.org/?ref=calregulatory.com) data. If the Commission nonetheless orders procurement, CalCCA recommends a two-tranche structure totaling 4,000 megawatts between 2029 and 2032, with a 2027 reassessment to incorporate updated load and import information. - CalCCA further advocated for individual load-serving entity procurement obligations, use of excess procurement toward future requirements, generic capacity (rather than technology-specific) mandates, and the continued application of extended compliance provisions adopted in a decision last September (D.25-09-007) **INSTANT ANALYSIS:** CRC is pushing the Commission to treat NGCCS as a near-term clean-firm resource, arguing it can be deployed quickly at existing gas sites with real Class VI permits in hand, while CalCCA urges caution on any additional procurement. CalCCA points to unprecedented load-forecast uncertainty and the risk of repeating costly, ad hoc procurement cycles. The meetings highlight a core tension in this rulemaking: whether to expand the clean-firm toolkit now or wait for clearer load and import signals before authorizing another statewide procurement mandate. --- ## Long-Duration Storage The CPUC issued [Draft Resolution E-5437](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K929/588929861.PDF?ref=calregulatory.com), which approves PG&E’s long-duration storage contract with the Balsam Project LLC for: - A 225-MW Dirac Battery Energy Storage System; and - An eight-hour lithium-ion facility expected online by **May 20, 2028** and delivering Resource Adequacy beginning **August 1, 2028**. The contract emerged from PG&E’s Long-Lead-Time Mid-Term Reliability solicitation and is intended to satisfy a portion of the utility’s long-duration storage obligations under the following decisions: - [D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com); - [D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com); and - [D.25-06-005](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M569/K671/569671981.PDF?ref=calregulatory.com). The Draft Resolution finds PG&E’s solicitation, bid evaluation, and Independent Evaluator review to be reasonable, concluding that the project represents a competitively selected, cost-effective option for meeting Mid-Term Reliability requirements. Costs will be recovered through the Portfolio Allocation Balancing Account and assigned a 2021 [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) vintage. The draft resolution also affirms that the project meets updated eight-hour dispatch requirements. The earliest the CPUC will consider this item is **January 15**. **INSTANT ANALYSIS:** This draft resolution advances PG&E’s long-duration procurement by approving a vetted 225-MW, eight-hour storage project that satisfies the Commission’s strengthened Mid-Term Reliability requirements. It affirms that PG&E’s solicitation, evaluation, and cost-recovery approach meet CPUC expectations, reinforcing a shift toward genuinely long-duration resources in the 2028 portfolio. --- ## Diablo Canyon PG&E filed Advice Letters 7776-E and 7777-E to provide the CPUC with its latest semiannual reporting on Diablo Canyon–related costs pursuant to a 2022 decision (D.22-12-005). - [AL 7776-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7776-E.pdf?ref=calregulatory.com) reports that the Department of Water Resources (DWR)’s Spring 2025 true-up found all **$193.9 million** in PG&E’s license-renewal and transition costs recorded in the Diablo Canyon Transition and Relicensing Memorandum Account to be eligible, reasonable, and in the public interest. DWR found no reason for disallowances, bringing total allowable loan proceeds approved to date to **$850.9 million**. - [AL 7777-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7777-E.pdf?ref=calregulatory.com) provides the parallel record of Diablo Canyon Extended Operations Balancing Account costs for the same October 2024–March 2025 period. These costs total **$172.6 million** in plant operations, maintenance, projects, fuel procurement, and employee-retention expenses, plus **$14.7 million** in volumetric performance-fee-related hydro expenditures, none of which are subject to DWR review but must be reported semiannually under the same statutory schedule. Protests are due **December 24**. **INSTANT ANALYSIS**: These filings show that Diablo Canyon’s extension continues to move through the cost-tracking framework with no friction. DWR again validated 100% of PG&E’s relicensing and transition spending, while the utility logged nearly $190 million in additional extended-operations and performance-fee costs that will flow through the Diablo Canyon Extended Operations Balancing Account. Financial commitments for continued operation are accelerating cleanly, with no disallowance pressure emerging in the semiannual cycle. --- ## Rule 30 Implementation PG&E filed [Advice Letter 7772-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7772-E.pdf?ref=calregulatory.com) to correct and refile its interim [Electric Rule 30](https://www.pge.com/tariffs/assets/pdf/tariffbook/ELEC%5FRULES%5F30.pdf?ref=calregulatory.com) tariff and associated form agreements after Energy Division rejected its prior filing ([AL 7671-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7671-E.pdf?ref=calregulatory.com)). Recall that a decision last summer ([D.25-07-039](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M574/K875/574875643.PDF?ref=calregulatory.com)) required PG&E to implement Rule 30 on an interim basis and to submit updated tariff language within 15 days. However, when PG&E filed AL 7671-E, Cal Advocates protested, and Energy Division subsequently rejected the filing because it did not clearly require 100% pre-funding of all Transmission Network Upgrades (Facility Type 4) attributable to a customer’s retail-service request. In this new submission, PG&E revises Section F.5 of Rule 30 (and the companion form agreement) to explicitly require applicants to finance the entire cost of Network Upgrades through a pre-funding loan, pay associated [Income Tax Component of Contribution](https://www.lawinsider.com/clause/itcc-income-tax-component-of-contribution?ref=calregulatory.com) (ITCC) taxes, and accept that repayment terms will be determined later in [A.24-11-007](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M547/K155/547155949.PDF?ref=calregulatory.com). PG&E's new filing attaches redlined and clean versions of both documents. Protests are due **December 24**. **INSTANT ANALYSIS:** This filing closes a loophole from PG&E’s earlier submittal and makes explicit what Energy Division already indicated: any large-load customer triggering Transmission Network Upgrades must now finance 100% of those costs upfront, including ITCC. The unresolved repayment framework in A.24-11-007 remains the key variable, but until that decision lands, project developers should assume full capital exposure and plan accordingly. --- ## Public Utility Regulatory Policies Act of 1978 (PURPA) PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7774-E.pdf?ref=calregulatory.com) to propose a small, corrective change to its [E-ELEC tariff](https://www.pge.com/en/account/rate-plans/electric-home.html?ref=calregulatory.com) (PG&E’s Residential Time-of-Use “Electric Home” rate)to address an unintended gap created by the [Net Billing Tariff (NBT)](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/nem-revisit/net-billing-tariff?ref=calregulatory.com) and prevailing-wage enforcement rules. Under current language, an NBT customer who is forced onto the [PURPA](https://en.wikipedia.org/wiki/Public%5FUtility%5FRegulatory%5FPolicies%5FAct?ref=calregulatory.com)\-compliant tariff due to a contractor’s willful prevailing-wage violation could lose eligibility for E-ELEC. PG&E seeks to allow these customers (expected to be very few) to remain on E-ELEC despite not meeting the usual technology requirements, arguing this avoids unnecessary rate changes and administrative confusion during the transition. **INSTANT ANALYSIS:** PG&E proposes a narrow fix to ensure NBT customers forced onto the PURPA-compliant tariff due to their contractor’s wage violations can remain on E-ELEC. This is an administrative cleanup filing that reveals how the Commission’s new prevailing-wage enforcement is beginning to interact with existing electrification rate design. ### December 18, 2025 CPUC Voting Meeting Preview URL: https://www.calregulatory.com/december-18-2025-cpuc-voting-meeting-preview/ Last updated: 2025-12-11T05:08:25.000Z On **December 18**, the CPUC will convene for its final business meeting of the year. The [agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M590/K419/590419905.pdf?ref=calregulatory.com) is jam-packed with consequential items, spanning wildfire accountability, capital-structure discipline, long-term gas planning, procurement volatility, and the sunset of underperforming clean-energy programs. Several items crystallize regulatory themes that have taken shape over the past 12 months: greater cost-effectiveness scrutiny, more prescriptive planning frameworks, and a willingness to retire legacy programs that no longer justify ratepayer funding. Below is a fast, item-by-item preview of what’s on deck. ### COST of CAPITAL - **SUMMARY**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) establishes the 2026 cost of capital for PG&E, SoCalGas, SCE, and SDG&E by maintaining each investor-owned utility’s existing capital structure and authorizing ROEs between 9.73% and 9.98%. The PD rejects efforts by utilities to raise equity layers or boost ROEs based on wildfire exposure, cash-flow pressures, or [Empirical Capital Asset Pricing Model](https://test.shareok.org/items/9b284c0f-7a95-4bf7-bb7b-22f3fa3af6f6?ref=calregulatory.com)/[After-Tax Weighted Average Cost of Capital](https://www.atlas.org/spaces/solve/after-tax-wacc-calculation-guide-7aFFDDJdm1wGQrnLyqataG?ref=calregulatory.com) adders, finding the evidentiary support insufficient. Intervenor arguments regarding high equity ratios, statutory protections, and national comparables carry more weight, leading the PD to conclude that current structures adequately support credit quality while limiting ratepayer burdens. - **INSTANT ANALYSIS**: The PD freezes all four IOUs at their existing 52% equity structures and authorizes ROEs just under 10%, rejecting PG&E’s yield-spread adjustment and every utility request for higher equity buffers. If ratepayers want some good news, it's worth noting that, in recent years, the CPUC has been paying close attention to the Cost of Capital issue, with [**Commissioner Darcie Houck**](https://www.cpuc.ca.gov/about-cpuc/commissioners/page-content/profile-list/commissioner-darcie-houck?ref=calregulatory.com) citing **Alfred Kahn**'s seminal book [*The Economics of Regulation*](https://www.amazon.com/Economics-Regulation-Institutional-Principles-Institutions/dp/0471454311/ref=sr%5F1%5F4?dib=eyJ2IjoiMSJ9.HjlEozgmaFkLUagMeY0l2lYBXQ0WUaFRd9ATj-PsR1tdQOHVHlIlVD42QSIPS%5FHqS3i6V2ZouGLVHbJ9fQfIdfUz9gJf9wLteFyVIT8HagE0ZfPlgmcNgUppLIxDWFAPHQFUAr4bZVeSmslt645grzA0BftG3w08bUMv1GWZiooJozYmWMTx65aYDY3CV3ZduCS9JiymyQle7wEPyk0Seu-HCGwWxFE20jUxZZHAiaA.cOGpLbxUvZoL1B-K2ykU-McqAlm338pqfeIW%5FJtDCNA&dib%5Ftag=se&qid=1729633764&refinements=p%5F27%3AAlfred+E+Kahn&s=books&sr=1-4&ref=calregulatory.com) in a 2024 dais conversation. That exchange preceded a decision where the CPUC [reduced the IOUs' routine Cost-of-Capital Mechanism adjustment](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K150/544150643.PDF?ref=calregulatory.com) from 50% to 20%, effective January 1, 2025. ### LONG-TERM NATURAL GAS PLANNING - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K210/587210797.PDF?ref=calregulatory.com) in the Long-Term Gas Planning docket implements [Senate Bill 1221](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB1221&ref=calregulatory.com) by designating initial neighborhood decarbonization zones—areas where gas utilities may pilot cost-effective electrification tied to upcoming gas line replacement work. Using criteria centered on community support, foreseeable pipeline replacement needs, and environmental-justice considerations, the PD identifies 142 census-tract-level zones and requires utilities to update their maps within 15 days. The PD also directs PG&E, SoCalGas, and SDG&E to conduct structured outreach and host public sessions ahead of a **March 15, 2026** refinement process. - **INSTANT ANALYSIS**: This PD takes a middle path by designating 142 census-tract-level decarbonization zones based on local support, gas-main replacement concentration, and environmental/social metrics. It rejects the utilities’ push for extremely broad, non-informative designations while explicitly committing to revisit and refine the map once SB 1221 outreach and pilot structures mature. The PD's accompanying attachments (a [statewide zone map](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K122/587122329.PDF?ref=calregulatory.com) and [detailed appendix](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K231/587231604.PDF?ref=calregulatory.com) of tract-level metrics), make clear how heavily the Commission is leaning on granular gas-infrastructure data, service-density profiles, and community-initiated requests in selecting the initial 2025 zones. ### NATURAL GAS ADVANCED METERING INFRASTRUCTURE - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K833/584833313.PDF?ref=calregulatory.com) approves a [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) between PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates that resolves PG&E’s request to recover costs for its large-scale replacement of failing Gas Advanced Metering Infrastructure modules. - PG&E had sought a revenue requirement of **$143.3 million** and nearly **$500 million** in forecasted costs for 2023–2026, but intervenors challenged the adequacy of PG&E’s showing and raised concerns about premature module failures and stranded costs. - Through negotiation, the parties [agreed](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) to reduced cost recovery: **$4 million** in adopted expenses, **$420 million** in adopted capital expenditures, and an **$88.6 million** total revenue requirement, representing a 38% reduction from PG&E’s original request. - The parties' [settlement](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K838/584838849.pdf?ref=calregulatory.com) also removes PG&E’s return on undepreciated assets tied to early module failures and limits additional upgrade-related spending after 2026\. The Commission finds the deal reasonable and in the public interest, concluding it reflects meaningful concessions, resolves disputes over responsibility for failures, and avoids health, safety, or environmental justice concerns. The decision adopts the settlement in full and closes the proceeding. - **INSTANT ANALYSIS**: The settlement trims PG&E’s Gas AMI replacement program to a more defensible scope, cutting the utility’s original ask down to $88.6 million, while locking PG&E into a $420 million capital cap and denying any return on $9.8 million of prematurely failed modules. ### WOOLSEY FIRE - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K598/586598163.PDF?ref=calregulatory.com) approves a [major settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K376/586376853.PDF?ref=calregulatory.com) reducing SCE’s requested recovery for the 2018 Woolsey Fire, allowing only 35% of its $5.6 billion Wildfire Event Mitigation Account balance and 85% of its Catastrophic Event Memorandum Account costs. This leaves **$3.7 billion** in wildfire-related claims and legal expenses permanently disallowed, with the approved WEMA portion to be financed through securitization and CEMA recovery handled through standard ratemaking. The settlement also resolves trailing claims issues, applies a **$250 million** Administrative Consent Order waiver, and includes SCE’s agreement not to pursue **$157 million** tied to other pre-2019 fires. - **INSTANT ANALYSIS:** If adopted, this PD would result in one of the largest wildfire-related disallowances ever imposed on a California IOU. The settlement itself does most of the hard work. It: - Pre-negotiates the massive Woolsey disallowance; - Fixes WEMA/CEMA recovery levels; - Commits all parties to a future securitization application, effectively eliminating prudence litigation and establishing a durable template for the resolution of legacy wildfire accounts; and - Binds SCE to specific governance reforms, giving intervenors ongoing leverage in future Wildfire Mitigation Plan and audit proceedings - Signatories were SCE, [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com), the Energy Producers and Users Coalition, and the [Small Business Utility Advocates](https://www.utilityadvocates.org/?ref=calregulatory.com). ### SDG&E's WILDFIRE MITIGATION COSTS - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) addresses SDG&E’s request to recover wildfire-mitigation costs recorded in its Wildfire Mitigation Plan Memorandum Accounts from May 2019 through 2022\. SDG&E sought approval to recover more than **$1.47 billion** in wildfire-mitigation spending from 2019–2022, but the PD disallows **$192.6 million** in O&M and **$242.4 million** in capital due to insufficient justification and cost-effectiveness concerns. - The PD ultimately approves **$90.6 million** in O&M and **$945.2 million** in capital as reasonable, and authorizes an additional **$430.9 million** in undercollected revenue requirement to be amortized over three years. - TURN’s request to require SDG&E to refile the application is rejected, though the utility must include cost-benefit ratios in future wildfire-cost filings. - **INSTANT ANALYSIS**: The PD slashes SDG&E’s wildfire-mitigation cost recovery request, disallowing $435 million across O&M and capital while still approving nearly $1 billion in hardened-grid investments as “reasonable” under the post-SB 901 regime. The PD expects SDG&E to deliver far better cost-effectiveness showings going forward, even as it authorizes a $430.9 million net revenue requirement and a three-year amortization to temper near-term bill impacts. Four accompanying appendices translate the PD's findings into hard numbers, detailing: - Capital and O&M disallowances (Appendices [B](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323961.PDF?ref=calregulatory.com) & [C](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328303.PDF?ref=calregulatory.com)); - The revised authorized revenue requirement and undercollection balance ([Appendix A](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K016/587016019.PDF?ref=calregulatory.com)); and - The bill-impact consequences of 3- vs. 6-year amortization scenarios ([Appendix D](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K371/587371219.PDF?ref=calregulatory.com)). ### UTILITY FINANCES - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472615.PDF?ref=calregulatory.com) authorizes SoCalGas to issue up to **$3.3 billion** in new long-term debt to fund capital investments, reimburse prior expenditures, and maintain financial flexibility. - The PD permits SoCalGas to use a wide range of instruments (first mortgage bonds, debentures, foreign debt, long-term loans, and receivables financing) as well as standard hedging tools and debt enhancements to reduce financing costs. - The PD emphasizes that authorizing debt issuance does not guarantee project approval or cost recovery, which will be assessed in future proceedings. - **INSTANT ANALYSIS**: The PD gives SoCalGas a clean, uncontested authorization to issue new debt with the full suite of modern hedging and derivative tools, reinforcing the CPUC’s continued practice of granting broad financing flexibility so long as cost recovery is litigated later. This is a straightforward financing approval (no policy pivots, no protests, and no constraints beyond standard GO-24-C reporting and the 20% hedging cap), which better positions SoCalGas to manage rising capital needs and market volatility without procedural friction. ### ERRA PROPOSED DECISIONS for PG&E and SCE - **SUMMARY:** Respective proposed decisions for the 2026 Energy Resource Recovery Account Forecast filings of [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781381.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K647/588647619.PDF?ref=calregulatory.com) approve the utilities' forecasts: SCE’s **$4.689 billion** revenue requirement and PG&E’s $**4.511 billion** gross requirement. - Both PDs incorporate updated fuel, purchased-power, Resource Adequacy, GHG, and balancing-account true-ups, including very large year-end corrections such as PG&E’s **$700 million** overcollection and major ERRA/Portfolio Allocation Balancing Account (PABA) swings for SCE. - The PDs affirm updated sales forecasts, adopt 2026 [Climate Credit ](https://www.cpuc.ca.gov/climatecredit/?ref=calregulatory.com)distributions, and note that bundled generation rates will fall (despite higher procurement revenue requirements) due to accounting-driven adjustments. - Each PD also updates [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) (PCIA) vintages, increasing charges for all unbundled customers. - **INSTANT ANALYSIS**: These PDs authorize notable increases in gross revenue requirements, yet each produces double-digit bundled generation rate decreases on January 1 due to outsized year-end balancing-account credits, even as PCIA charges rise across customer vintages. The PDs highlight the CPUC’s growing dependence on annual true-up mechanics (large ERRA overcollections for PG&E and volatile ERRA/PABA balances for SCE) to offset procurement-cost escalation and stabilize bundled customer bills in the near term. ### PG&E TRANSMISSION COSTS - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K016/587016018.PDF?ref=calregulatory.com) authorizes PG&E to recover **$338.2 million** in recorded costs from its Transmission Revenue Requirement Reclassification Memorandum Account (TRRRMA), reflecting reclassified plant costs and two facilities shifted from CAISO to non-CAISO control. - After reviewing ledgers, sample invoices, and allocation records, the PD finds that PG&E adequately proved the costs were incurred and correctly calculated under the Transmission Owner 18 settlement, net of a **$42.6 million** refund to distribution customers. - The PD also directs PG&E to file a Tier 2 advice letter to evaluate whether older asset misclassifications dating back to 2006 caused improper charges and to propose remedies, along with a 45-day compliance report on implementation and FERC refunds. - **INSTANT ANALYSIS**: The PD grants PG&E recovery of its reclassified transmission-to-distribution costs, finding the company's evidentiary showing sufficient despite Cal Advocates’ objections, and moves all recovery to prospective rates beginning **January 1, 2026**. The PD also orders a Tier 2 Advice Letter on nearly two decades of asset misclassification, an unusual backward-looking review that could expose PG&E to additional corrections or refunds in a future phase. ### DISTRIBUTION PLANNING - **SUMMARY:** [Draft Resolution E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K748/585748983.PDF?ref=calregulatory.com) approves with modifications a joint proposal submitted by PG&E, SCE, and SDG&E to create a "pending loads" category in the utilities' distribution planning process. The proposal establishes a uniform statewide framework with four categories (A, B1, B2, and C) that classify pending loads by data quality and confidence, and introduces “hot spots” where certain projections may exceed [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) (IEPR) forecasts to justify proactive upgrades. Utilities must adopt common criteria beginning in the 2025–2026 cycle and provide detailed annual reporting on pending loads, hot-spot designations, and planning accuracy. - **SUMMARY:** Separately, [Draft Resolution E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850473.PDF?ref=calregulatory.com) implements a standardized scenario-planning framework for PG&E, SCE, and SDG&E beginning in the 2025–2026 cycle, requiring each utility to model Low, Base, and High load futures using IEPR forecasts and pending-load categories. Utilities must then translate these scenarios into a single investment plan using a common, CPUC-directed decision-logic structure that dictates when to advance, defer, or resize projects based on scenario-driven needs. All planned projects must be tied to a scenario and justified in the [Distribution Upgrade Project Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K519/576519221.PDF?ref=calregulatory.com), with associated grid-needs reporting in the [Grid Needs Assessment](https://www.pge.com/assets/pge/docs/about/doing-business-with-pge/GNA.pdf?ref=calregulatory.com). - **INSTANT ANALYSIS**: Draft Resolutions E-5413 and E-5414 establish a unified architecture for distribution-system forecasting, pairing a single pending-loads framework with a mandatory Low/Base/High scenario model that exposes when speculative or high-growth assumptions shape actual project sizing. Utilities now have room to plan proactively, but only within a shared set of categories, scenarios, and reporting rules that make every IEPR exceedance or High-scenario investment choice explicitly traceable. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/iterograph_Mon-Dec-08-2025--2--1.png) ### AFFORDABILITY - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K598/586598168.PDF?ref=calregulatory.com) updates the CPUC’s Affordability Framework by narrowing where affordability metrics must be filed, strengthening contextual requirements, and moving toward a more streamlined, web-based reporting system. - Mandatory metric filings will now be limited to General Rate Cases, where utilities must provide clearer context on rate and revenue growth relative to inflation and distinguish operational from capital spending. - The PD also eliminates abbreviated Quarterly Revenue Reports and resolves pending confidentiality motions, granting SDG&E’s request and denying SCE’s. - **INSTANT ANALYSIS:** The PD reshapes the CPUC’s affordability framework by limiting metric requirements to GRCs, adding inflation-indexed context graphs, and requiring utilities to highlight impacts on vulnerable customers. This turns the framework into a more targeted tool for evaluating long-term rate and capital pressures. The PD also shifts annual affordability reporting to a continuously updated online format. This move is intended to create a more adaptive structure for tracking cost burdens over time. ### CLEAN-ENERGY FINANCING - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K815/585815581.PDF?ref=calregulatory.com) approves with modifications SCE’s Tariff On-Bill financing pilot, while rejecting proposals from SDG&E, SoCalGas, and [Silicon Valley Clean Energy](https://svcleanenergy.org/good-energy/?source=google&medium=cpc&campaignid=23096254737&adgroupid=&keyword=&gad%5Fsource=1&gad%5Fcampaignid=23102189645&gbraid=0AAAAACoZMK5vpvdke62Yk9N4H6EZO-p2H&gclid=CjwKCAiA0eTJBhBaEiwA-Pa-hQvEmdOfaRT%5FajNVGdXubI5Dg641LgIAUlxc%5FlcbXbJUI5m3W9x%5FIxoCV1EQAvD%5FBwE) (SVCE). - [Tariffed on-bill financing](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-expands-on-bill-financing-options-for-non-residential-energy-utility-customers-2023?ref=calregulatory.com) allows customers to install clean-energy upgrades with no upfront cost, repaying through a fixed charge tied to the property rather than the individual. - The PD deems Edison’s design the only sufficiently developed proposal and limits it to about 200 residential sites with strict bill-neutrality, customer protections, and savings-verification requirements. - **INSTANT ANALYSIS**: The PD authorizes SCE’s Tariff On-Bill pilot (tightly constrained and capped) while rejecting SDG&E’s, SoCalGas’s, and SVCE’s proposals, showing that the Commission is willing to test Tariff On-Bill mechanics, but only under a disciplined, bill-neutral structure that minimizes customer and program risk. In effect, the PD turns SCE’s 200-site pilot into the sole proving ground for whether Tariff On-Bill can function at scale without drifting into debt-like territory or creating affordability concerns. ### SELF-GENERATION INCENTIVE PROGRAM - **SUMMARY:** [Draft Resolution E-5430](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K033/587033186.PDF?ref=calregulatory.com) updates the Self-Generation Incentive Program (SGIP) by approving new third-party-ownership consumer protections and revising how federal tax credits interact with SGIP incentives. - In response to federal changes that phase out the residential tax credit after 2025 and the solar portion of the third-party ownership/non-residential credit after 2027, the CPUC now requires any project claiming less than a 30% tax-credit contribution to show why it is ineligible and why it could not be structured as third-party ownership. - The draft resolution closes loopholes that allowed residential host-owned projects to bypass federal credits, rejects using domestic-content or foreign-entity constraints as exemption grounds, and directs SGIP administrators to update the [SGIP Handbook](https://sgiphandbook.com/?ref=calregulatory.com#/welcome) by **January 1, 2026**. - **INSTANT ANALYSIS**: This draft resolution imposes cost-sharing discipline by presuming a 30% federal tax credit unless a project can prove ineligibility and explain why it cannot be third-party-owned. This is meant to close the loophole that allowed residential systems to bypass that threshold. The draft resolution also adopts third-party ownership consumer protections and rejects using domestic-content or prohibited-foreign-entity rules as blanket exemptions. This is meant to stop SGIP from backfilling lost federal value with ratepayer funds. ### BIOENERGY MARKET ADJUSTING TARIFF - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) (BioMAT) program through **December 31, 2025**. - With only about 21% of its 250 MW target subscribed and numerous terminated projects, the PD finds that BioMAT’s performance does not justify continued ratepayer funding, especially given cheaper and more flexible alternatives such as Renewables Portfolio Standard solicitations, [ReMAT](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), Qualifying Facility standard offers, Integrated Resource Planning procurement, and [BioRAM](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-bioram?ref=calregulatory.com). - Citing both its authority to retire ineffective programs and the [Governor’s 2024 affordability directive](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com), the PD allows BioMAT to sunset and rejects all requested program changes. - **INSTANT ANALYSIS:** This PD shuts the door on BioMAT’s future by denying the Bioenergy Association of California request to extend or revise the program. The PD cites persistent under-subscription, high above-market costs, and ample alternative procurement tools. The PD frames sunsetting the tariff on December 31, 2025 as an affordability action aligned with the Governor’s N-5-24 directive and a necessary reallocation of Commission and utility resources. ### RENEWABLES PORTFOLIO STANDARD - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328286.PDF?ref=calregulatory.com) adopts, with select modifications, the 2025 [Renewables Portfolio Standard Procurement Plans](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-plans?ref=calregulatory.com) submitted by California’s retail sellers, finding that nearly all entities remain on track to meet long-term contracting requirements. - The PD emphasizes the importance of early risk-buffered procurement given project delays, load uncertainty, interconnection congestion, and intensifying Renewable Energy Credit competition. - While granting the utilities broad flexibility across long- and short-term contracting, bilateral deals, renegotiations, and REC sales, the PD again rejects their request to remove Tier 1 review of short-term REC transactions. - **INSTANT ANALYSIS**: The PD adopts all 2025 RPS Plans with targeted corrections while keeping firm Commission oversight in place (especially by denying, again, IOU attempts to bypass Tier 1 review for short-term REC deals). The PD gives the utilities broad procurement flexibility (including REC sales, bilateral deals, Low Carbon Fuel Standard retirements, and long-term contracting authority) but ties that flexibility to Integrated Resource Planning-aligned justification and continued advice-letter scrutiny. ### UNION ISLAND PIPELINE - **SUMMARY:** A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD concludes that the company no longer holds valid franchise rights in Antioch and Brentwood and ceased transporting gas in 2023\. - The PD concludes further that ongoing litigation over alleged pipeline abandonment means CRPC cannot demonstrate clear ownership or operational control of the full line, preventing it from dedicating the system to public use. - The PD rejects CRPC’s attempt to substitute a subsidiary and denies the cities’ request for a procedural pause, though it grants CRPC’s motion to keep financial records sealed for three years. - **INSTANT ANALYSIS:** The PD rejects CRPC’s bid for public-utility status and a CPCN, finding that CRPC lacks the present legal rights to operate key pipeline segments and therefore cannot meet the statutory definitions required for Commission oversight. The PD also denies CRPC’s amendment request, establishing that – in the eyes of the Commission – unresolved franchise disputes and ongoing litigation render the proposal too uncertain to authorize. ### MID-WEEK NEWS CODEX: Ethanol; CAISO Year in Review; Affordability URL: https://www.calregulatory.com/mid-week-news-codex-ethanol-caiso-year-in-review-affordability/ Last updated: 2025-12-10T16:37:58.000Z - **BayWA r.e. Secures $416 Million for San Diego Solar and Storage Project:** "BayWa r.e. announced it has closed financing for Jacumba Valley Ranch Energy Park, a project in southeastern San Diego County, California that includes 90 MW of solar and 70 MW / 280 MWh of battery energy storage. The facility, expected to be operational in fall of 2026, is planned to deliver electricity to roughly 57,000 homes through San Diego Community Power." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/12/09/baywa-r-e-secures-416-million-for-san-diego-solar-and-storage-project/?ref=calregulatory.com) - **California's Oil and Gasoline Conundrum:** "The currently mandated total phaseout of in-state oil production by 2045 is increasingly implausible and irresponsible given these structural realities and the fact that oil and gas provides 8% of California’s GDP. California will still need its oil pipeline and refinery infrastructure well into the latter part of the 21st century to remain a viable economy. Ending all California drilling and oil production by 2045 is increasingly unlikely and impractical. Jets require fuel, roads are made of asphalt, and touch screens use hydrocarbon molecules." [**CALIFORNIA GLOBE**](https://californiaglobe.com/wp-content/uploads/2025/12/Blueprint-Soluition-Defin-Final.pdf?ref=calregulatory.com) - **California Now Allows More Ethanol in Gasoline – is This Going to Save Drivers Money?** "The outcomes of California’s new E15 law will depend on how CARB chooses to regulate E15 under the new law. If it adds an alternative fuel specification for ethanol, as seems most likely, then I expect the results to be the same as in other states when the EPA allowed summer E15\. Few gas stations will offer it and few drivers will buy it. Consumers don’t understand it and may be wary of it; gas stations will be averse to paying for the labeling and new fuel dispensers." [**ENERGY at HAAS**](https://energyathaas.wordpress.com/2025/12/08/california-now-allows-more-ethanol-in-gasoline-is-this-going-to-save-drivers-money/?ref=calregulatory.com) - **California Regulators Prioritize Keeping Electric Bills Affordable Over Increasing Utility Shareholder Profits:** "In the last 12 months, there has been a noticeable downwards shift in utilities’ return on equity nationally. California’s regulators are proposing to follow this downward trend, and the cut to the authorized utility profits (their return on equity) will all be below 10% for the first time in a generation." [**ENVIRONMENTAL DEFENSE FUND**](https://blogs.edf.org/climate411/2025/12/04/california-regulators-prioritize-keeping-electric-bills-affordable-over-increasing-utility-shareholder-profits/?ref=calregulatory.com) - **CPUC Approves "First-Ever" Statewide Energy Efficiency Market Transformation Initiative:** "The Decision authorizes CalMTA to immediately implement the Room Heat Pumps MTI, which CalMTA argues is projected to deliver $480 million in benefits to California ratepayers over the initiative’s lifetime. Those benefits include the value of energy savings, greenhouse gas reductions, and increased demand flexibility to help keep the electric grid healthy. The Room Heat Pumps MTI are meant to accelerate market adoption of a 120-Volt (V) plug-in room heat pump air conditioner. This emerging technology provides both heating and cooling for small single-family and multifamily households while avoiding some costly electrical upgrades. A $41 million budget was approved to fund this initiative over the next six years." [**RENEWABLE ENERGY WORLD**](https://www.renewableenergyworld.com/power-grid/cpuc-approves-first-ever-statewide-energy-efficiency-market-transformation-initiatives/?ref=calregulatory.com) - **Forecasting Large Loads in the Age of AI and Data Centers:** "...Microsoft’s San Jose data center uses its RNG microgrid to power facility operations when it participates in California’s Base Interruptible Protocol events." [**E3**](https://www.ethree.com/wp-content/uploads/2025/12/E3Whitepaper%5FDataCenterForecasting.pdf?ref=calregulatory.com) - **How California is Failing its Latino Population:** "Manufacturing has lost [one-third of its jobs](https://www.nytimes.com/2022/08/01/business/economy/smithfield-california-factory.html?ref=calregulatory.com) in California since 1990, one reason [few new electric vehicle plants](https://www.greencars.com/news/us-flexes-industrial-muscle-as-ev-battery-production-set-to-double?ref=calregulatory.com), [semiconductor](https://www.z2data.com/insights/where-are-all-the-north-american-semiconductor-fabs-being-built-2024?ref=calregulatory.com) and [other new industrial facilities](https://www.etq.com/blog/states-where-manufacturing-jobs-are-projected-to-grow-the-most/?ref=calregulatory.com) locate in California. This matters particularly to Latinos, who represent [the vast majority](https://www.ppic.org/blog/californias-workforce-is-diverse-but-many-occupations-are-not/?ref=calregulatory.com) of Californians in 'carbon economy' jobs from production workers to material handling and truck driving — all industries in the crosshairs of state climate policy." [**NEW GEOGRAPHY** ](https://www.newgeography.com/content/008742-how-california-failing-its-latino-population?ref=calregulatory.com) - **ISO 2025 Year in Review:** "Adding more resources to the grid in 2025 has made the system stronger and improved reliability. The 5,713 MW of additional capacity onboarded this year is enough power to serve about five million homes. Working closely with our partners in state government, the summer of 2025 marked the third in a row that grid operators kept the system balanced during heat waves and wildfires without a single Flex Alert asking consumers to 'flex' when and how they use electricity to balance supply and demand." [**CAISO**](https://www.caiso.com/about/news/energy-matters-blog/california-iso-2025-year-in-review?ref=calregulatory.com) - **Newsom Sparks Rebellion in Bay Area Town:** "A small city perched on San Francisco Bay poses a big obstacle to California Governor **Gavin Newsom**'s plans to prevent gasoline price spikes. Valero Energy Corp. plans to shut its refinery in Benicia in April, part of a wave of refinery closures across California as the state shifts away from fossil fuels. Newsom is counting on increased imports to ensure gas prices don’t soar, and his administration is exploring the Valero site — which is connected to a marine port — as a potential storage hub, said Benicia Mayor [**Steve Young**](https://www.ci.benicia.ca.us/citycouncil?ref=calregulatory.com#628B0680-462B-4586-9E23-F936796F1F19). The idea, however, doesn’t sit well with Young or other leaders in this community of 27,000, which relies on the refinery for jobs and taxes." [**RIGZONE**](https://www.rigzone.com/news/wire/newsom%5Fsparks%5Frebellion%5Fin%5Fbay%5Farea%5Ftown-08-dec-2025-182479-article/?rss=true&ref=calregulatory.com) - **Report Shows Newsom Prioritizes Beijing Over Bakersfield as California Drifts Toward Full-Blown Energy Crisis:** "If you’re a driver in the Golden State, watch out. California could be months away from what a [new analysis from USC and UC Berkeley professors](https://californiaglobe.com/fl/new-report-warns-consequences-of-an-oil-pipeline-shutdown-would-cascade-across-the-state/?ref=calregulatory.com) describe as the most severe breakdown of the state’s fuel infrastructure in modern history." [**ENERGY IN DEPTH** ](https://www.energyindepth.org/report-shows-newsom-prioritizes-beijing-over-bakersfield-as-california-drifts-toward-full-blown-energy-crisis/?ref=calregulatory.com) - **Sable Requests Transfer of Las Flores Pipeline Oversight from State Fire Marshall to Federal Regulator**: "Sable Offshore Corp. requested that the federal government take regulatory oversight of the pipeline system critical to its restart of oil production in the Santa Ynez Unit. The California Office of the State Fire Marshal currently has oversight of the pipeline. In an 8-K [filing](https://d18rn0p25nwr6d.cloudfront.net/CIK-0001831481/246d7539-a787-4645-b69e-3abe6926344c.html?ref=calregulatory.com) on November 26, 2025, Sable stated that it determined that the 122-mile Las Flores Pipeline System, which connects the Santa Ynez Unit to the Pentland Station terminal in Kern County, was an interstate pipeline under the Pipeline Safety Act. The federal Pipeline and Hazardous Materials Safety Administration would then have regulatory oversight over the pipeline. Sable did not state its reasoning for its determination." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/sable-requests-transfer-of-las-flores?ref=calregulatory.com) - **The High Cost of Electricity in California:** "In 2019, the bundled system average rate for all three large investor-owned utilities was 19.8 cents per kWh. In 2023, it was 30.8 cents per kWh, an increase of 55 percent—outpacing the 38 percent increase in the total revenue requirement during this same period. Moreover, the revenue requirement for 2025 is projected to be between five and nine percent higher than 2024 according to the CPUC, meaning bills will continue to rise barring a significant change in rates policy." [ **LITTLE HOOVER COMMISSION**](https://lhc.ca.gov/wp-content/uploads/LHC-Report-290-The-High-Cost-of-Electricity-in-California-Final-Draft-Prior-to-Publication-10.31.25.pdf?ref=calregulatory.com) ### Ratepayer Parties Meet with Commissioner John Reynolds' Office in Cost of Capital Proceeding URL: https://www.calregulatory.com/ratepayer-parties-meet-with-commissioner-john-reynolds-office-in-cost-of-capital-proceeding/ Last updated: 2025-12-10T16:10:05.000Z On December 2, the following parties gathered to [meet with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K070/590070246.PDF?ref=calregulatory.com) **Commissioner John Reynolds**' office at the CPUC. - Cal Advocates; - Energy Producers and Users Coalition (EPUC); - Environmental Defense Fund (EDF); - Indicated Shippers (IS); and - TURN Collectively, the parties argued that the [pending proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) addressing the investor-owned utilities' 2026 Cost of Capital applications appropriately lowers IOU return on equity levels but fails to address several structural issues that could erode those affordability gains. EDF emphasized that California IOUs have maintained unusually high ROEs relative to national peers despite declining national averages, and noted that the PD’s reductions (supported by record evidence) would save ratepayers roughly **$300 million** annually compared to current ROEs and **$1.3 billion** compared to utility proposals. However, the group warned that these benefits may be offset by other PD elements: - The continued disconnect between authorized and actual capital structures at PG&E and SCE, which they argue saddles customers with unnecessary “phantom equity” costs; - PG&E’s Yield Spread Adjustment, which they said lacks adequate explanation and would shift tens of millions in carrying-cost burdens onto ratepayers due to PG&E’s own overleveraged balance sheet; and - Continuation of the existing Cost of Capital Mechanism without a pathway for ratepayers to challenge automatic ROE increases, even though utilities may contest adjustments that disfavor them. The parties urged revisions to address these concerns so that affordability improvements from ROE reductions are real rather than illusory. **INSTANT ANALYSIS**: This broad-based ex parte intervention shows an unusual level of alignment among parties, indicating that the PD's ROE cuts are widely viewed as credible and directionally correct but also incomplete. The intervenors' key message is that affordability gains will evaporate unless the Commission confronts three pressure points: - PG&E and SCE’s persistent mismatch between authorized and actual capital structures, which quietly inflates equity costs; - PG&E’s Yield Spread Adjustment, which could shift tens of millions in financing burdens onto customers due to PG&E’s own leverage problem; and - A Cost of Capital Mechanism that allows utilities (but not ratepayers) to challenge automatic ROE adjustments. ### Parties File Post-Prehearing Conference Statements in CPUC's New Climate Credit OIR URL: https://www.calregulatory.com/parties-file-post-prehearing-conference-statements-in-cpucs-new-climate-credit-oir/ Last updated: 2025-12-10T06:26:22.000Z On December 8 the California Community Choice Association (CalCCA), SoCalGas, and TURN submitted post-prehearing conference (PHC) statements following this proceeding's November 21 PHC. The CPUC opened this rulemaking to redesign how the [California Climate Credit](https://www.cpuc.ca.gov/climatecredit?ref=calregulatory.com) is structured, calculated, and delivered to customers. As **ALJ Sotero** stated on the record, the rulemaking was initiated to consider ways to make the climate credit more effectively support customer affordability and to implement newly enacted statutory requirements that the credit be disbursed in no more than four high-bill months rather than the current spring/fall pattern. In their post-PHC statements, parties lay out ideas for how the Commission should structure and sequence the docket. ### Parties' Post-PHC Statements - TURN [calls for](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800549.PDF?ref=calregulatory.com) a limited Phase 1A, aimed solely at adopting changes to the timing and number of 2026 disbursements (specifically to ensure the fall 2026 credit can be advanced without entanglement in broader eligibility or methodological issues). TURN recommends placing more expansive policy questions into a concurrent Phase 1B and a Phase 2 triggered by the California Air Resources Board’s forthcoming Cap-and-Invest regulations.\* TURN also presses for a shared modeling tool or, secondarily, a coordinated scenario-analysis process to ensure consistent distributional impact analysis across parties. - SoCalGas [also supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K408/590408797.PDF?ref=calregulatory.com) phasing the rulemaking. It centers its advocacy on protecting gas-customer bill impacts, adding decarbonization (not electrification) to the proceeding’s guiding principles, and clarifying that more complex eligibility or volumetric-allocation changes may require new memorandum accounts and cannot be implemented before CARB completes its rulemaking. SoCalGas also proposes moving the gas Climate Credit from April to February beginning in 2027, while keeping April 2026 unchanged. - CalCCA [opposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M590/K417/590417480.PDF?ref=calregulatory.com) a narrowly focused Phase 1A, arguing that modifying the fall 2026 credit in isolation (before simultaneously evaluating timing, eligibility, frequency, and outreach) risks harming winter-peaking customers and generating customer confusion. CalCCA prefers a unified Phase 1 that evaluates all timing-related questions together, paired with standard Commission processes (workshops, staff reports) and development of a modeling tool to assess bill impacts. **INSTANT ANALYSIS:** This proceeding is on the verge of becoming a full-scale redesign of the Climate Credit rather than a simple timing adjustment. [Assembly Bill 1207](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260AB1207&ref=calregulatory.com) deadlines, [Energy Resource Recovery Account](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com) constraints, and pending CARB regulations are forcing the CPUC into an unusually compressed decision cycle. --- ### FOOTNOTE *\*CARB is conducting a required update to its Cap-and-Trade (now called Cap-and-Invest) regulations under AB 1207, and the CPUC cannot finalize long-term Climate Credit reforms until CARB completes this rulemaking.* ### Parties Comment on Track 2 PD in SDG&E's 2024 General Rate Case URL: https://www.calregulatory.com/parties-comment-on-track-2-pd-in-sdg-es-2024-general-rate-case/ Last updated: 2025-12-10T16:35:58.000Z On December 4, parties filed comments in response to an **ALJ John Larsen** [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328302.PDF?ref=calregulatory.com) in Track 2 of SDG&E's Test Year 2024 General Rate Case submission. The PD addresses SDG&E's request to recover recorded Wildfire Mitigation Plan Memorandum Account costs for 2019-2022 (*see our November 17 summary of the PD* [*here*](https://www.calregulatory.com/monday-aggregate-cost-of-capital-affordability-senate-bill-1221/)). The PD marks the CPUC's first full reasonableness review of SDG&E's wildfire-mitigation spending since [Senate Bill 901](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=201720180SB901&ref=calregulatory.com) and [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com) reshaped the wildfire regulatory framework. It substantially reduces SDG&E's requested cost recovery, disallowing approximately **$192.6 million** in O&M and **$242.4 million** in capital costs. Parties' comments reflect a tension between SDG&E's claim that the PD unlawfully disavows previously-authorized wildfire-mitigation programs and intervenors, who argue that SDG&E's record is incomplete, inconsistent, and insufficient to justify the scale of spending it seeks to recover. ### Party Comments - SDG&E [contends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800333.PDF?ref=calregulatory.com) that the PD commits a fundamental legal error by: second-guessing programs prospectively approved in SDG&E's Wildfire Mitigation Plans, intruding on Energy Safety’s jurisdiction, and misapplying incrementality standards. SDG&E also contends that the PD disallows major cost categories (including drones, Public Safety Power Shutoff communications, vegetation management, data governance, and covered conductor installations) despite prior CPUC ratification and the utility’s 18-year record without a catastrophic fire. - The Utility Consumers' Action Network [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800430.PDF?ref=calregulatory.com) the PD’s substantial disallowances, emphasizing that SDG&E has not demonstrated that its spending is incremental, cost-effective, or reasonably incurred. Utility Consumers' Action Network also draws attention to especially high unit costs for covered conductor installation relative to PG&E and SCE, while arguing they lack any meaningful justification. - Cal Advocates argues that the PD errs, but only where it is too lenient, specifically by allowing labor and grid-hardening costs that SDG&E has not shown to be incremental or tied to High Fire-Threat Districts. Cal Advocates reiterates that SDG&E has failed to prove new hires or demonstrate that work was not performed by already-funded staff. - TURN [criticizes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800334.PDF?ref=calregulatory.com) the PD for not imposing stronger consequences for what all intervenors describe as SDG&E’s inadequate or nonexistent cost-effectiveness showing. TURN asserts that the PD should've adopted deeper disallowances or should've required a resubmission, because cost-effectiveness is an indispensable element of any reasonableness review under the prudent-manager standard. - Protect Our Communities Foundation [goes further](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K800/589800659.PDF?ref=calregulatory.com), arguing that the PD improperly approves large swaths of wildfire-mitigation spending despite: - Contradictory cost data SDG&E submitted to the [Office of Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) and to the CPUC; - Widespread documentation deficiencies that trigger mandatory disallowance under the Public Utilities Code; and - Unresolved discrepancies regarding undergrounding, covered conductor, and overhead-hardening expenditures. Protect Our Communities Foundation contends that accepting SDG&E’s testimony over its [Office of Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com) filings undermines statutory requirements for accurate records and inter-agency coordination. **INSTANT ANALYSIS:** This PD takes wildfire oversight into stricter territory, indicating that Wildfire Mitigation Plan approval should not be construed as a rubber stamp for cost recovery. Parties' comments telegraph that the evolving regulatory posture on wildfires means cost recovery now depends on demonstrable incrementality, verifiable documentation, and credible cost-effectiveness. From a utility perspective, the rules of the game are being rewritten midstream. But to [steelman](https://en.wikipedia.org/wiki/Straw%5Fman?ref=calregulatory.com#Steelmanning) the regulator's apparent view: WMP approval ≠ a blank check. ### CPUC Meeting Master List URL: https://www.calregulatory.com/cpuc-meeting-master-list/ Last updated: 2025-12-10T16:36:20.000Z A quick housekeeping matter: we have started a master list of CPUC voting meetings and their results [here](https://www.calregulatory.com/cpuc-voting-meeting-results/). This will be a continuously updated, living document to help parties track decision-making chronologies. Additionally, you can search for information by category with our new [topical index](https://www.calregulatory.com/categories-topics/). ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/iterograph_Mon-Dec-08-2025--9-.png) ### December 4, 2025 CPUC Voting Meeting Results URL: https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-results/ Last updated: 2025-12-18T16:27:59.000Z On December 4, the CPUC's [business meeting agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M589/K516/589516089.pdf?ref=calregulatory.com) included attempts to impose methodological discipline on expensive capital programs even as procurement costs surge beyond forecast: - [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) deliberately slows undergrounding deployment to tighten cost-benefit standards; - Diablo Canyon's **$382 million** revenue requirement prompts procedural discomfort despite statutory compliance; and - SDG&E's 2026 procurement revenue requirement jumps from $122 million to **$824 million**, driven almost entirely by volatile market benchmarks. Meanwhile, the Commission is executing a controlled shutdown of ratepayer-funded clean-energy incentive programs while politically preserving underperforming assets like Ivanpah, whose economics remain weak but whose megawatts are too valuable for the Commission to relinquish (it seems). Three significant items were delayed to **December 18** (including tariff on-bill financing and BioMAT extension decisions) suggesting commissioners need additional time to reconcile cost-containment goals with decarbonization mandates and stakeholder pressure. ## Undergrounding of Electrical Equipment [Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) updates the CPUC’s [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) by expanding and tightening review, cost-justification, and audit requirements. These requirements were established under [Resolution SPD-15 ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com)and aligned with [Energy Safety](https://energysafety.ca.gov/?ref=calregulatory.com)’s 2025 guidelines for [10-year Electric Undergrounding Plans](https://energysafety.ca.gov/news/2025/02/20/energy-safety-adopts-10-year-electrical-undergrounding-plan-guidelines/?ref=calregulatory.com). The resolution standardizes: - Project data submissions; - Revenue-requirement models; and - Decision-making metrics. The resolution also requires utilities to justify work outside high-fire-threat areas and limits eligibility to projects with benefit-cost ratios of at least 1 that meet defined risk thresholds. Additionally, Draft Resolution SPD-37 conditions cost recovery on: - Outperforming alternative mitigations; - Adhering to approved cost and benefit limits; and - Meeting Energy Safety performance standards... ...while introducing annual Electric Undergrounding Plan audits and a cumulative memorandum-account cap to guard against uncontrolled cost transfers. ### Commissioner Remarks from the Dais Commissioner **John Reynolds** added the following remarks prior to the resolution carrying 5-0. > ...the hard truth is that the only way out is through. There are investments we need to make. There is physical risk reduction today to reduce the risks of catastrophic costs tomorrow. Delay ultimately doesn't save money, it just shifts the risk forward. Because the stakes are so high, we spent years working on how to mitigate wildfire risk strategically and cost effectively. Many proceedings tackle these issues, including General Rate Cases, wildfire and catastrophic event applications, and this resolution. And the Risk-Based Decision-Making rulemaking (or RDF) also set new rules for how utilities measure, report and plan risk mitigation. I was honored to lead that proceeding, and that we've come to develop this risk-based policy. In building that framework, we've been guided by a fundamental principle: utilities need to make smart decisions with customer dollars to mitigate risk. Ultimately, it's the utility that has to operationalize the policy and funding levels we set. > ...some may wonder: 'Why add another step to an already compressed timeline?' and I'll be direct about the reasoning – the costs here are enormous. We are potentially going to be evaluating 10 or 11 figures in capital costs with average monthly customer bill impacts estimated as high as **$25**. > With stakes that high for a single capital program, we need to get the methodology right. There are multiple methods for reducing wildfire risk, and no party thinks we should underground the entire electric grid. Yet we need further refinement of our funding standard to evaluate which projects justify ratepayer funding, the policy goals haven't changed. We want utilities to make smart, cost effective decisions that genuinely reduce wildfire risk, but the specific metrics and thresholds that will govern billions of dollars in spending deserved for our development with full stakeholder input. _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: PG&E ERRA Forecast; Demand Response; Energy Efficiency URL: https://www.calregulatory.com/wednesday-aggregate-3/ Last updated: 2025-12-03T18:50:08.000Z Wednesday's offering takes a look at: - Opening comments on the [proposed decision addressing PG&E's 2026 ERRA Forecast](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781381.PDF?ref=calregulatory.com), which feature a divide over banked Renewable Energy Credit valuation that carries immediate [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rate implications for Community Choice Aggregator customers; - An Energy Efficiency [staff proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K479/589479620.PDF?ref=calregulatory.com) to significantly expand the gas measure phase-out beyond new construction into retrofits and equity segments; - More [ex parte communications between the investor-owned utilities and CPUC personnel](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K915/588915268.PDF?ref=calregulatory.com), where the IOUs argue that the Commission's [pending Cost of Capital PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) sets ROEs too low given current wildfire risk and rising interest rates; and - Reply comments in the Commission's Demand Response rulemaking, which reveal tensions over scope, cost-effectiveness authority, and Virtual Power Plant integration. --- ## PG&E Electric Rates PG&E and CalCCA recently responded to the CPUC's [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781381.PDF?ref=calregulatory.com) addressing PG&E's 2026 Energy Resource Recovery Account Forecast. As currently drafted, the PD would authorize PG&E’s $**4.511 billion** gross requirement. ### PG&E's Comments PG&E [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K486/589486914.PDF?ref=calregulatory.com) the PD but requests several clarifications and corrections. Its primary concern is the PD’s adoption of SCE's Slice-of-Day methodology for Resource Adequacy valuation in the Power Charge Indifference Adjustment framework. PG&E asks the CPUC to explicitly state that Slice of Day applies only to energy storage resources for 2026 ratesetting, arguing that the record does not support extending the method to other resource types. PG&E argues further that the proper valuation for pre-2019 banked Renewable Energy Credits is zero, and that the PD should adopt this permanently rather than on an interim basis. PG&E contends that: - These Renewable Energy Credits have already been fully valued under historical ratemaking; - Compensating them again would violate bundled-customer indifference and the company’s approved tariffs; and - Treating them as having value would undermine the affordability benefits of selling Renewables Portfolio Standard resources. ### CalCCA's Comments CalCCA’s [comments](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K915/588915265.PDF?ref=calregulatory.com) oppose several elements of the PD, particularly the PD’s acceptance of PG&E’s zero-valuation for pre-2019 banked Renewable Energy Credits. - CalCCA asserts that the PD violates Public Utilities Code, which requires that departed load customers receive the value of benefits associated with PCIA-eligible resources. CalCCA argues that PG&E’s proposal impermissibly shifts costs to Community Choice Aggregator customers by denying them compensation for Renewable Energy Credits they originally funded and that PG&E now uses for bundled RPS compliance. - CalCCA notes that the PD reverses recent Commission precedent (including the [2025 PG&E ERRA decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K288/550288170.PDF?ref=calregulatory.com)) without explanation, and that the “interim” nature of the PD does not cure the legal defect or protect customers from significant near-term bill increases. - CalCCA proposes that the Commission require PG&E to continue valuing banked Renewable Energy Credits under the long-standing RPS Adder approach, to exhaust post-2019 banked RECs before using pre-2019 RECs, and to track all 2025 and 2026 REC usage so future PCIA guidance can apply consistently. - CalCCA also raises concerns with the PD’s adoption of the Slice-of-Day methodology. While CalCCA does not oppose implementing SCE’s Slice-of-Day method on an interim basis, it requests that PG&E be required to file ann advice letter showing how it will implement SCE’s method, given PG&E’s reluctance to operationalize it and the absence of presented outputs. - CalCCA also asks the Commission to memorialize an uncontested point from discovery: namely, that data-center load located in CCA territory defaults to CCA service unless already served by an Electric Service Provider. **Instant Analysis:** These comments showcase a significant divide over indifference, valuation, and interim methodology. PG&E seeks targeted clarifications to narrow the PD (especially limiting Slice-of-Day to storage and locking in a zero-dollar value for pre-2019 banked Renewable Energy Credits), a change that benefits bundled customers and stabilizes its Renewables Portfolio Standard strategy. CalCCA counters that the PD’s REC treatment constitutes an unlawful cost shift, reverses recent precedent without explanation, and would drive significant PCIA increases for CCA customers. CalCCA also presses for enforceable implementation of SCE’s Slice-of-Day method and asks the Commission to preserve the longstanding REC-valuation framework pending the PCIA rulemaking. The Commission must now decide whether to preserve the PD’s bundled-leaning structure or adopt CalCCA’s corrections to avoid immediate cost impacts on departed load. (Below are sample rate impacts projected by CalCCA if the PD were to be adopted as-is.) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/banos.png) --- ## Energy Efficiency A new [ALJ ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K486/589486895.PDF?ref=calregulatory.com) in the CPUC’s Energy Efficiency rulemaking invites party comments on a [staff proposal](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K479/589479620.PDF?ref=calregulatory.com) that would significantly expand the phase-out of ratepayer-funded incentives for natural gas energy efficiency measures. - The proposal builds on a 2023 decision ([D.23-04-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M505/K808/505808197.PDF?ref=calregulatory.com)), which already ended incentives for many new-construction gas appliances, and recommends extending this phase-out to retrofits and the equity segment, while tightening the conditions under which any gas-burning measures remain eligible. - Staff propose defining a "Viable Electric Alternative" as an electric measure that provides the same function as a gas measure and is cost-effective for the customer. To determine this, they recommend using the "Participant Cost Test," which captures bill impacts, upfront costs, and panel-upgrade needs—instead of relying solely on the broader Total Resource Cost Test. The proposal incorporates findings from a statewide market study showing how often electrification requires panel upgrades and how much those upgrades cost. - Developers seeking EE incentives would need to follow [Title 24](https://www.nebb.org/blog/why-we-all-need-to-pay-attention-to-title-24/?ref=calregulatory.com) prescriptive baselines, which generally require heat pumps for HVAC and water heating. If a Viable Electric Alternative exists, incentives for that gas measure would end in new construction regardless of Total Resource Cost Test results, and in retrofits if the gas measure is not cost-effective. Exempt “non-burning” gas-saving measures remain eligible. Staff also propose new pilot programs to reduce refrigerant emissions and recommend allowing separate incentives for electrification-enabling infrastructure. **Instant Analysis:** This move would reorient energy efficiency toward electrification, customer economics, and long-term decarbonization. If adopted, the proposal would reshape measure eligibility, program design, and administrator incentives across the next decade. Utilities, Regional Energy Networks, Community Choice Aggregators, and implementers will need to prepare for rapid measure-package updates, more electrification-oriented portfolios, and a shrinking runway for gas EE programs. --- ## Demand Response Parties recently submitted reply comments in response to the Commission's new Demand Response docket. Below is a summary of select parties' filings. Across this sample, parties largely agree that California's DR framework must modernize to support reliability, electrification, and affordability, but they diverge on scope and policy priorities. - [CalCCA](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K524/589524306.PDF?ref=calregulatory.com), [SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K915/588915255.PDF?ref=calregulatory.com), [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K933/588933141.PDF?ref=calregulatory.com), [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K933/588933142.PDF?ref=calregulatory.com), [Olivine](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K625/589625133.PDF?ref=calregulatory.com), the [California Solar & Storage Association](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K152/589152899.PDF?ref=calregulatory.com) (CALSSA), and others emphasize that DR must expand beyond legacy summer event programs toward multi-hour, multi-season load flexibility integrated with dynamic rates, Virtual Power Plants, electric-vehicle charging, Behind-the-Meter storage, and CAISO market participation. Many (including CalCCA, Olivine, and SDG&E) urge coordination with the [CAISO’s Demand & Distributed Energy Market Integration initiative](https://stakeholdercenter.caiso.com/StakeholderInitiatives/Demand-Distributed-Energy-Market-Integration?ref=calregulatory.com), the Resource Adequacy rulemaking, and statewide planning ([Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com), Integrated Resource Planning, transmission). - Several parties (CalCCA, Olivine, CALSSA, and PG&E) call for reforms to dual-participation rules, better data access, standardized telemetry, and clearer customer-experience improvements to unlock broader DR enrollment. Virtual Power Plant enablement is widely supported, with requests for a flexible policy framework allowing DR/VPP portfolios to stack services and offer grid-responsive capacity. - [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M589/K527/589527032.PDF?ref=calregulatory.com) and [TURN](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K933/588933145.PDF?ref=calregulatory.com) push back on expanding the proceeding's scope, especially around cost-effectiveness policy, arguing that DR cost-effectiveness rules (including Total Resource Cost Test vs Ratepayer Impact Measure debates) must remain in the Distributed Energy Resources cost-effectiveness rulemaking. They caution against weakening cost-effectiveness screens or diluting protections intended to prevent uneconomic DR programs. - PG&E and SDG&E emphasize system-integration and implementation complexity. SCE seeks to silo dynamic-rate system upgrades into rate-design applications and limit the breadth of guiding-principle revisions. CALSSA and other DER providers argue the opposite, warning that separating dynamic-rate infrastructure from DR policy will hobble load-flexibility deployment. **Instant Analysis**: CCAs, aggregators, DER providers, and even the utilities push for this rulemaking to modernize DR into a flexible, Virtual Power Plant-aligned, multi-service grid asset integrated with dynamic rates, the CAISO’s [Demand & Distributed Energy Market Integration](https://stakeholdercenter.caiso.com/StakeholderInitiatives/Demand-Distributed-Energy-Market-Integration?ref=calregulatory.com) work, and Resource Adequacy reform. Parties emphasize better telemetry, dual-participation updates, and customer-experience improvements. Cal Advocates and TURN act as procedural brakes, insisting the proceeding avoid cost-effectiveness changes. The utilities support modernization conceptually but caution against broad scope expansion. The filings frame a policy crossroads: whether the CPUC uses this docket to align Demand Response with the state’s evolving DER/VPP ecosystem, or constrains it to prevent uneconomic expansion, even as legacy event-based DR becomes increasingly mismatched to California’s emerging grid realities. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/IMG_4614.JPG) ## Cost of Capital PG&E, SCE, SDG&E, and SoCalGas recently [met again](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K915/588915268.PDF?ref=calregulatory.com) with CPUC personnel regarding the Commission's [pending Cost of Capital PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com). (Recall that we also reported on a November 13 meeting [here](https://www.calregulatory.com/wednesday-aggregate-2/).) - The investor-owned utilities’ CEOs and senior regulatory executives argued that the PD sets authorized returns on equity below the levels needed to attract sufficient investment in California’s increasingly risky utility environment. They emphasized that catastrophic wildfire exposure (including recent events like the [Palisades](https://www.fire.ca.gov/incidents/2025/1/7/palisades-fire?ref=calregulatory.com) and [Eaton](https://en.wikipedia.org/wiki/Eaton%5FFire?ref=calregulatory.com) fires) continues to elevate financial and operational risk, and that even after [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com), investor uncertainty surrounding inverse condemnation and potential Wildfire Fund depletion remains high. - The utilities stressed that interest rates have risen materially since the 2023 Cost of Capital case, national average ROEs have increased, and shareholder contributions to the Wildfire Fund now further elevate required returns. The utilities provided the following graphic. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/ROEs.png) - The utilities warned that the PD’s proposed ROEs would worsen the IOUs’ already fragile credit positions, citing recent downgrades and investor reactions, which could increase borrowing costs and ultimately undermine long-term affordability for customers. The utilities asked the Commission to, at minimum, maintain current authorized ROEs rather than reduce them. An accompanying slide deck details rising market yields, deteriorating credit metrics, elevated wildfire-related financial uncertainty, and analyst commentary describing the PD as surprising, negative, and misaligned with California’s risk profile. **Instant Analysis**: At minimum, two major interpretations frame the current Cost of Capital debate. - Current and emerging risks (many of them California-specific and shaped by the state’s regulatory environment) justify higher ROEs to prevent long-term financing cost increases. - Persistent rate pressures warrant holding the line or reducing returns, especially amid heightened public affordability concerns. The central question is then whether the IOUs’ coordinated position reflects a legitimate risk-pricing gap that could elevate long-term costs, or a strategic effort to secure stronger financial conditions under the banner of risk. --- ## Nuclear Decommissioning SDG&E filed an advice letter (AL 4764-E, available [here](https://tariffsprd.sdge.com/sdge/filings/?utilId=SDGE&bookId=ELEC&flngStatusCd=Effective&ref=calregulatory.com)) to report an upcoming vacancy on its Nuclear Decommissioning Trust Fund Committee. SDG&E explains that the term of committee member [**Estela de Llanos**](https://www.linkedin.com/in/estela-de-llanos-65b98836/?ref=calregulatory.com) ended on October 31, 2025, following her resignation from SDG&E. SDG&E's Board of Directors has selected [**April Robinson**](https://www.linkedin.com/in/april-robinson-7751343/?ref=calregulatory.com), the company’s Chief Risk and Compliance Officer, as the nominee. In parallel, SDG&E has now submitted an advice letter (AL 4576-E-A) formally requesting CPUC approval of Robinson’s appointment. **Instant Analysis:** This matter is a routine housekeeping item, but governance of nuclear decommissioning trust funds is becoming more sensitive as decommissioning timelines accelerate, investment rules evolve, and market volatility raises the stakes for long-duration liabilities. This process also lands against the broader backdrop of a system pursuing large-scale decommissioning while simultaneously tightening its reliability standards. This unresolved tension continues to surface across multiple CPUC proceedings. ### MID-WEEK NEWS CODEX: Interconnection Urgency; Vehicle-to-Microgrid; Moss Landing Fallout URL: https://www.calregulatory.com/mid-week-news-codex-interconnection-urgency-vehicle-to-microgrid-moss-landing-fallout/ Last updated: 2025-12-03T23:29:40.000Z - **California Lawmakers Urge CPUC to Enforce Utility Interconnection Timelines**: "The legislators, led by Assemblymember **Dawn Addis** (D-Morro Bay), submitted a formal letter to the commission demanding accountability for Pacific Gas & Electric and Southern California Edison, citing consistent failures to meet state-mandated timelines. The core issue centers on 'Rule 21,' a standardized tariff that establishes the process and deadlines for utilities to approve and activate distributed energy resources. Data presented to the commission indicates that both PG&E and SCE have frequently failed to comply with these rules." [**PV MAGAZINE**](https://www.pv-magazine.com/2025/12/02/california-lawmakers-urge-cpuc-to-enforce-utility-interconnection-timelines/?ref=calregulatory.com) - **Energy News Roundup:** "The Los Angeles Board of Water and Power Commissioners on Oct. 28 approved a **$195 million** investment to expand demand-response opportunities for the Los Angeles Department of Water & Power beginning in 2026\. The funds will increase LADWP’s current demand-response resource capacity from 80 MW to 340 MW via residential and commercial demand-response and managed electric-vehicle-charging programs. LADWP is also investing in a centralized demand-response management system to optimize LADWP’s DR portfolio and support Los Angeles’ transition to 100-percent clean energy, the utility said in a news release." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/news%5Fin%5Fbrief/quick-bites-energy-news-roundup-for-nov-25-2025/article%5Fc086cfea-cd47-46ee-afc2-98da7f9c418a.html?ref=calregulatory.com) - **EVs and California's Future Demand for Electricity:** "...we may estimate with some confidence that it will take somewhere between 115,000 and 130,000 GWh per year to electrify 100 percent of California’s wheeled, on-road vehicles. Is that estimate too rough? Too speculative? Perhaps. But I’d be surprised if it differs significantly from what may ultimately be the case. The big question – along with just how rapidly Californians will be willing to exchange their gas and diesel powered cars and trucks for EVs, or how rapidly the distribution infrastructure could be built – is where all this additional electricity is going to come from." [**WHAT'S CURRENT**](https://mailchi.mp/calpolicycenter/whats-current-issue-7861106?e=17c3a84ab7&ref=calregulatory.com) - **Ionna Plans $250M Investment in EV Charging Infrastructure in California:** "Despite the Dept. of Transportation’s [revised guidance for the distribution of federal funding](https://www.wardsauto.com/news/archive-auto-dot-issues-revised-ev-charger-funding-guidance-for-states/757814/?ref=calregulatory.com) to construct public EV charging infrastructure in the U.S., Ionna continues to expand its network. The company is not reliant on federal funds to construct its charging sites. Instead, its funding comes from private capital." [**UTILITY DIVE**](https://www.utilitydive.com/news/ionna-jv-plans-250M-investment-california-ev-charging-network-rechargeries/806661/?ref=calregulatory.com) - **Newsom Finally Addresses the Duck Curve (or Tries To):** "[Governor Newsom signed legislation](https://www.sfgate.com/tech/article/california-solving-solar-power-problems-21207873.php?sid=682d624c4f2690bb1c07fbe2&utm%5Fsource=newsletter&utm%5Fmedium=email&utm%5Fterm=briefing&utm%5Fcampaign=sfgt%20%7C%20the%20daily&stn=nf) to try to relieve the Duck Curve and halt wasteful curtailment by creating a 'day-ahead energy trading market' (instead of a 'spot market' of minutes) to give more time for grid balancing authorities like the huge California Independent System Operator to sell excess solar power across state lines instead of switching desert solar projects off. (And buying baseload/on-demand natural gas generation and hydro power)." [**BASIN & RANGE**](https://basinandrangewatch.substack.com/p/newsom-finally-addresses-the-duck) - **PG&E Finds Value in Excess Solar with Vehicle-to-Microgrid Project at Redwood Coast Airport in Northern Cal:** "In what they are saying is a first for vehicle-to-microgrid technology, Schatz Energy Research Center researchers, along with PG&E and Fermata Energy, have demonstrated how to use EV chargers to control solar overgeneration, boost resilience and support the main grid." [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/electric-vehicles/article/55335623/pge-starts-vehicle-to-microgrid-pilot-at-the-redwood-coast-airport-in-northern-cal?ref=calregulatory.com) - **Startup Raya Power Poised to Offer its Plug-In Solar and Storage Solution in Puerto Rico and California:** "Pre-orders for the Raya Power system [are available](https://rayapower.com/products/raya-solar-system-deposit?ref=calregulatory.com) now in Puerto Rico and California with a refundable deposit. The total cost of the system is listed as $6,790, or about $5 per watt." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/12/02/startup-raya-power-poised-to-offer-its-plug-in-solar-and-storage-solution-in-puerto-rico-and-california/?ref=calregulatory.com) - **State Commission Makes Recommendations to Reduce Utility Retail Rates:** "California should take a series of steps toward reducing the pace of retail electricity price hikes, an independent state commission said. The Golden State is second only to Hawaii on the list of states with the highest retail electric rates, with residential rates at about twice the national average and commercial/industrial rates about 2.5 times higher than average, according to the report from the Little Hoover Commission. Aside from the obvious strain this places on homeowners, many businesses, schools and hospitals, it affects the desire and ability of businesses to come to California, [the report](https://lhc.ca.gov/wp-content/uploads/LHC-Report-290-The-High-Cost-of-Electricity-in-California-Final-Draft-Prior-to-Publication-10.31.25.pdf?ref=calregulatory.com) says. Prices for customers of investor-owned utilities have risen at a faster clip than for customers of publicly owned utilities and have significantly outpaced the rate of inflation." [**CALIFORNIA ENERGY MARKETS**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/bottom%5Flines/state-commission-makes-recommendations-to-reduce-utility-retail-rates/article%5Fa37bc37a-0006-49d3-b656-905c395e7b75.html?ref=calregulatory.com) - **Trump Includes California in Draft Offshore Lease Plan:** "According to the [Los Angeles Times](https://www.latimes.com/environment/story/2025-11-11/trump-wants-oil-drilling-off-the-coast-of-california-but-no-one-else-does?ref=calregulatory.com), California still has roughly two dozen active oil platforms in state and federal waters, some of them easily spotted from beaches in Southern California. But the industry has been largely frozen in place for decades: no new federal offshore leases have been issued since 1984, a legacy of political resistance that hardened after the 1969 Santa Barbara oil spill. Even so, significant untapped reserves remain." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/fossil-fuels/trump-includes-california-in-its-draft-offshore-lease-plan/?ref=calregulatory.com) - **Utilities, Regulators Look to Accelerate Pilots to Achieve Speed-to-Innovation:** "To meet its quickly growing electric vehicle penetration, Pacific Gas and Electric’s [managed charging program for 1,000 ](https://investors.itron.com/news-releases/news-release-details/itron-and-pge-collaborate-enable-real-time-control-electric?ref=calregulatory.com)[customers](https://investors.itron.com/news-releases/news-release-details/itron-and-pge-collaborate-enable-real-time-control-electric?ref=calregulatory.com), launched in January, is already nearing its next phase, said **Marina Donovan**, vice president of global marketing for smart meter provider Itron. 'That shows the speed the utility wants to move at,' she said." [**UTILITY DIVE**](https://www.utilitydive.com/news/regulatory-sandbox-dcflex-vpp-pura-pilot-project/806454/?ref=calregulatory.com) - **When the World's Largest Power Plant Caught Fire, Toxic Metals Rained Down – Wetlands Captured the Fallout:** "Metals from the Moss Landing battery fire still linger in the region’s sediments and food webs. These metals bioaccumulate, building up through the food chain: The metals in marsh soils can be taken up by worms and small invertebrates, which are eaten by fish, crabs or shorebirds, and eventually by top predators such as sea otters or harbor seals." [**THE CONVERSATION**](https://theconversation.com/when-the-worlds-largest-battery-power-plant-caught-fire-toxic-metals-rained-down-wetlands-captured-the-fallout-268848?ref=calregulatory.com) - **Why California's Coastal Commission Should Let Diablo Canyon Keep Operating:** "Currently, the California Coastal Commission poses the most serious impediment to the state’s efforts to extend operations at Diablo Canyon—largely over the issue of fish larvae. Established in [1976](https://www.coastal.ca.gov/laws/?ref=calregulatory.com), the California Coastal Commission is tasked with considering whether coastal developments align with the [California Coastal Act’s](https://www.coastal.ca.gov/laws/?ref=calregulatory.com) policies for marine ecosystem protection. While the Commission is also [considering other factors](https://documents.coastal.ca.gov/reports/2025/11/Th8a-Th9a/Th8a-Th9a-11-2025-report.pdf?ref=calregulatory.com), a primary issue before the Commission is the power plant’s impact on small marine organisms that pass through the seawater cooling system’s intake filters." [ **ECOMODERNIST**](https://www.breakthroughjournal.org/p/why-californias-coastal-commission?ref=calregulatory.com) ### SCE General Rate Case Phase 2: Reply Briefs URL: https://www.calregulatory.com/sce-general-rate-case-phase-2-reply-briefs/ Last updated: 2025-12-02T07:17:57.000Z On November 7, [we reported on parties' opening briefs](https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/) in SCE's General Rate Case Phase II ([A.24-03-019](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M528/K409/528409332.PDF?ref=calregulatory.com)), which addressed three main issues: - SCE’s proposed TOU-D-PRIME Plus rate; - Baseline allowance treatment; and - Transmission marginal costs. Opening briefs demonstrated that SCE is pushing PRIME Plus as a new form of residential pricing (with a higher fixed charge, demand charge, and lower volumetric rates). Cal Advocates and the Solar Energy Industries Association (SEIA) both argued the proposal is misaligned with real grid stress, is unsupported by customer data, and is potentially unlawful due to the inclusion of non-marginal distribution costs in the fixed charge. TURN injected NEM into the discussion, with another variation of the ongoing [cost-shift](https://www.canarymedia.com/articles/solar/californias-rooftop-solar-is-a-benefit-not-a-cost-to-the-state?ref=calregulatory.com) argument. --- With reply briefs, parties continue to diverge over the proposed TOU-D PRIME Plus rate, the adoption of marginal transmission capacity costs (MTCC), and a proposed [Vehicle-to-Grid Resource Proposal settlement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M579/K066/579066253.PDF?ref=calregulatory.com).\* - SCE [defends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K684/588684805.PDF?ref=calregulatory.com) PRIME Plus as an optional, cost-based rate aligned with Commission policy, arguing that residential customers can understand the peak-usage demand feature, that the fixed charge properly recovers non-marginal distribution costs, and that the rate improves cost causation and load-shifting incentives, while also rejecting TURN’s baseline allowance proposal and SEIA’s MTCC proposal. - SEIA [urges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K647/588647706.PDF?ref=calregulatory.com) the Commission to reject PRIME Plus entirely, arguing it violates [D.24-05-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K686/531686019.PDF?ref=calregulatory.com),\*\* is not cost-based, creates perverse incentives by weakening volumetric price signals after a single peak-hour spike, and lacks any demonstrated evidence of customer comprehension, while also asserting that adopting MTCC for SCE is proper and necessary for state-jurisdictional uses despite SCE and Cal Advocates’ objections. - Cal Advocates likewise [opposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K684/588684804.PDF?ref=calregulatory.com) PRIME Plus, arguing SCE has provided no empirical evidence of customer or grid benefits, improperly equates demand charges with TOU price ratios, and ignores that dynamic pricing pilots offer more accurate and targeted signals. Cal Advocates also rejects SEIA’s MTCC proposal as inflated, unsupported, out-of-scope, and duplicative of the ongoing statewide Transmission & Distribution cost-study effort. Finally, the Vehicle-Grid Integration Council [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K345/588345896.PDF?ref=calregulatory.com) the proceeding's Vehicle-to-Grid Resource Proposal settlement, arguing that using the [Avoided Cost Calculator](https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight?ref=calregulatory.com) for export compensation is consistent with CPUC precedent, aligns with the [Net Billing Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/customer-generation/nem-revisit/net-billing-tariff?ref=calregulatory.com) framework, and is essential to scaling bidirectional EV charging as a meaningful grid resource, and that Cal Advocates’ objections should be dismissed. **Instant Analysis**: SCE’s TOU-D PRIME Plus proposal is headed into a heavily contested decision window with all non-utility parties. Opponents see the rate as having various evidentiary weaknesses: - No empirical load-shift analysis; - Unclear customer comprehension; and - Unresolved questions about fixed-charge legality under [D.24-05-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K686/531686019.PDF?ref=calregulatory.com). Consequently, PRIME Plus looks increasingly fragile unless the Commission is willing to bless a novel residential demand charge on policy grounds rather than record strength. Meanwhile, the MTCC debate shows no appetite from the Commission’s own Cal Advocates to adopt SEIA’s **$73/kW**\-year value, especially with the statewide Transmission & Distribution cost study underway. That makes MTCC adoption in this GRC Phase 2 unlikely. By contrast, the Vehicle-to-Grid Resource Proposal settlement stands on firmer footing, with its Avoided Cost Calculator-based export methodology aligning with the Net Billing Tariff precedent and offering clear policy upside for VGI development. --- ### FOOTNOTES **\***In this settlement SCE, SEIA, the Vehicle-Grid Integration Council, CALSTART, and the Small Business Utility Advocates resolve all issues surrounding SCE’s proposed Vehicle-to-Grid Resource Proposal, a new retail program that would allow electric vehicles equipped with bidirectional charging to export power back to the grid under structured, cost-based compensation rules. The agreement creates two program pathways: - One for standalone EV export systems; and - One for for systems paired with Net Energy Metering, NEM-Successor Tariff, or Net Billing Tariff solar/storage configurations (each operating as a rider layered onto existing Time-of-Use, electrification, or dynamic-pricing rates). --- \*\*D.24-05-028 implemented [Assembly Bill 205](https://legiscan.com/CA/text/AB205/id/2600089?ref=calregulatory.com) by authorizing all investor-owned utilities to overhaul residential rate design so that a portion of fixed electric-system costs is recovered through an income-graduated monthly fixed charge rather than solely through per-kWh rates. ### MONDAY AGGREGATE: Diablo Canyon; DER Flexible Connections; Edison PSPS Events URL: https://www.calregulatory.com/monday-aggregate-diablo-canyon-der-flexible-connections-edison-psps-events/ Last updated: 2025-12-02T06:07:18.000Z Updates today reflect the CPUC's continuing focus on long-term infrastructure planning and cost-recovery frameworks. - PG&E forecasts a return to normalized capital-structure oversight following its bankruptcy-era deleveraging, while simultaneously highlighting the persistent tension between wildfire-driven spending and gas-system underspend that will likely feature prominently in its[ 2027 General Rate Case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com). - Utilities' comments on DER-enabled flexible connections suggest that that any near-term flexible-interconnection policies must be calibrated to infrastructure limitations rather than conceptual frameworks. - SCE's early-November Public Safety Power Shutoff reports demonstrate how deeply embedded precautionary de-energization has become across diverse wind patterns. - The Long Beach/THUMS artificial oil islands matter continues to develop as a potential bellwether for how the Commission will handle legacy Added Facilities Agreements in California's offshore drilling phase-down. ## DIABLO CANYON PG&E filed a [response](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K334/588334680.PDF?ref=calregulatory.com) to the [Alliance for Nuclear Responsibility](https://en.wikipedia.org/wiki/Alliance%5Ffor%5FNuclear%5FResponsibility?ref=calregulatory.com) (A4NR)’s [October 2025 petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486351.PDF?ref=calregulatory.com) of the 2024 CPUC decision ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486351.PDF?ref=calregulatory.com)), which governs the costs and reasonableness review structure for Diablo Canyon’s extended-operations revenue requirement for 2025\. - In its petition, A4NR requested that the CPUC replace the forecast 2025 Resource Adequacy Market Price Benchmark (RA MPB) with the final RA MPB value when evaluating whether PG&E’s actual costs exceed the 115% threshold that triggers a reasonableness review, and also sought revisions to update the 2025 revenue requirement. - PG&E agrees that the final RA Market Price Benchmark should be used for the statutory 115% evaluation but argues this should apply not only to 2025 but to all Diablo Canyon Extended Operations Forecast proceedings through 2030, since the Market Price Benchmark is outside PG&E’s control and variances will continue in future years. - However, PG&E opposes modifying the 2025 revenue requirement or revising the findings and ordering paragraphs, noting that the [Energy Resource Recovery Account](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com)\-style forecasting and true-up framework already incorporates final Market Price Benchmark values into rates the following year, making A4NR’s proposed revisions redundant and inconsistent with established ratemaking practice. PG&E recommends partially granting the petition (limited to adopting the final RA MPB for all 115% evaluations going forward) while rejecting A4NR’s other proposed modifications. **Instant Analysis:** The main takeaway here is that a 2025 rate adjustment remains unlikely, but the Commission may refine how RA MPB values factor into future cost reviews, thereby potentially improving clarity around the multi-year Diablo Canyon cost-reasonableness structure. --- ## COST of CAPITAL PG&E submitted its [2025 Annual Capital Structure Update](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5147-G.pdf?ref=calregulatory.com) to comply with a 2020 CPUC decision ([D.20-05-053](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M338/K816/338816365.PDF?ref=calregulatory.com)), reporting that it is now fully back in compliance with its authorized ratemaking capital structure following the June 2025 expiration of the five-year temporary waiver granted at its exit from bankruptcy. PG&E says it has deleveraged over the waiver period through equity issuances and other measures, and now maintains (and forecasts through year-end 2025) a common-equity ratio at or above the authorized **52%** level. PG&E provides updated capital-structure ratios as of September 30 and projected ratios for December 31, 2025, reflecting statutory and Commission-directed adjustments for Wildfire Fund contributions, Assembly Bill 1054 wildfire-mitigation securitizations, a rate-neutral **$7.5 billion** securitization authorized in 2021, and the retroactive grantor-trust election for the Fire Victim Trust. The advice letter also lists PG&E’s current credit ratings from S&P, Moody’s, and Fitch, and notes that, because the waiver has expired and no deviation exists, PG&E no longer provides a multi-year deleveraging forecast in this update. Protests are due **December 15**. ### 📈 Credit Rating Comparison | Debt Type/Rating | Standard & Poor's | Moody's | Fitch | | ---------------- | ----------------- | ------- | ----- | | Secured Debt | BBB | Baa1 | BBB+ | | Issuer Rating | BB | Baa3 | BBB- | | Unsecured Debt | NA | NA | NA | **Instant Analysis:** PG&E’s latest capital-structure update is largely perfunctory but still noteworthy as the first post-waiver confirmation that the utility has restored its equity ratio above the authorized 52% (a key milestone after years of bankruptcy-era leverage). With the temporary waiver now expired and no deviation to report, this filing signals a return to “normal” capital-structure oversight, albeit still shaped by major statutory adjustments. Credit ratings remain mixed. In short, this is a clean compliance update, but it confirms that the Commission is unlikely to revisit capital-structure relief absent new wildfire-liability shocks or adverse credit movement. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/12/IMG_4610.JPG) ## DISTRIBUTED ENERGY RESOURCES On November 25, the three large electric investor-owned utilities (SDG&E, PG&E, and SCE) filed detailed responses to [a CPUC ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K143/586143237.PDF?ref=calregulatory.com) on DER-enabled near-term flexible connections. The IOUs emphasize that, while they see value in variable and dynamic operating envelopes, their current [Advanced Distribution Management System](https://gridmap.gridwise.org/technologies/advanced-distribution-management-system/?ref=calregulatory.com#:~:text=An%20ADMS%20can%20collect%2C%20organize%2C%20display%2C%20and,power%20flows%2C%20maintain%20reliability%2C%20and%20prevent%20overloads.) (ADMS)/[Distributed Energy Resource Management System ](https://www.nrel.gov/grid/distributed-energy-resource-management-systems?ref=calregulatory.com)(DERMS) systems are not yet capable of delivering customer-level short-term or real-time capacity forecasts at scale. ### **SDG&E** SDG&E [stresses foundational gaps](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K334/588334695.PDF?ref=calregulatory.com): - Missing programs; - Undefined incentives; - Insufficient telemetry; - Incomplete customer-level models; and - Major readiness work needed before any dynamic signaling could function reliably. SDG&E warns that the ruling's questions "place the technological cart before the financial horse” and that producing operating envelopes for all customers would require expensive new data acquisition, modeling, and system architecture. ### **PG&E** PG&E [outlines a more advanced DERMS posture](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K056/588056590.PDF?ref=calregulatory.com), one that is already producing day-ahead feeder-level forecasts at [SCADA](https://en.wikipedia.org/wiki/SCADA?ref=calregulatory.com) points and deploying variable limits through its [Flex Connect](https://www.pge.com/assets/pge/docs/clean-energy/electric-vehicles/flexible-service-connection-pilot-overview.pdf?ref=calregulatory.com) program. However, PG&E notes that full grid-wide modeling, hour-ahead forecasting, and customer-level dispatch depend on [2027 General Rate Case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com) funding and load-flow/state-estimation expansion. PG&E also highlights the need for customer-side equipment and a vendor ecosystem to make [IEEE 2030.5](https://www.ampcontrol.io/post/ieee-2030-5-the-key-to-smart-ev-charging-and-grid-integration?ref=calregulatory.com) connectivity affordable. ### **SCE** SCE [similarly reports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K933/588933106.PDF?ref=calregulatory.com) that its ADMS/DERMS capabilities will not support full short-term or dynamic forecasting until 2027–2028, and that interim approaches rely on static limits through [Rule 21 ](https://www.cpuc.ca.gov/Rule21/?ref=calregulatory.com)and its Load Control Management System pilot. SCE also emphasizes the distinction between direct 2030.5 “gateway” connections and aggregator-based cloud pathways, noting that aggregator services will often be more cost-effective for customers while direct connection may suit only larger sites. **Instant Analysis:** The apparent takeaway from these responses is that California is unprepared to operationalize dynamic or customer-level operating envelopes. All three utilities acknowledge that their ADMS/DERMS stacks lack the forecasting granularity, telemetry, modeling fidelity, and communications architecture needed to support day-ahead or hour-ahead import/export limits across the polyphase grid. The filings portend a multi-year runway: foundational data cleansing, DER modeling, AMI upgrades, telemetry expansion, load-flow/state-estimation buildout, IEEE 2030.5 integration, and customer/aggregator ecosystems must all mature before flexible connections can be scaled. For now it seems, flexible interconnection remains a niche, pilot-stage tool, and any near-term policies must reflect the large gap between conceptual enthusiasm and operational reality. --- ## RISK ASSESSMENT/SAFETY COSTS PG&E [submitted corrections](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K323/588323085.PDF?ref=calregulatory.com) to a previously filed 2024 Safety Performance Metrics Report, revising "Metric 2" (Transmission and Distribution Overhead Wires Down on Major Event Days) and "Section 4" (2024 imputed adopted values for safety-related risk-mitigation activities). The updated report confirms PG&E’s 2024 performance across 32 safety metrics adopted in a 2021 decision ([D.21-11-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M421/K107/421107805.PDF?ref=calregulatory.com)), covering wires-down events, emergency response times, gas-system integrity, fire ignitions, inspections, workforce safety indicators, and corrective-action completion rates. A key revision is the corrected count of wires-down events during major weather-driven outages (**4,676** in 2024) an inherently volatile metric driven by the number of severe storm days, which PG&E says is not used for executive compensation or internal performance goals. The updated Section 4 tables also restate imputed adopted versus actual spending on safety-related mitigation, showing areas of both underspend (e.g., gas distribution and transmission) and significant overspend (notably in electric distribution capital tied to wildfire and asset-failure mitigations). PG&E explains that data-flow issues, system-integration challenges, and evolving IEEE reliability-calculation standards necessitated these corrections, and affirms that it is working toward improved alignment with industry best practices. Key spending takeaways: - Electric Distribution capital spending exceeded adopted levels by roughly **$1.35 billion**, driven by wildfire-hardening and overhead-asset programs; - Electric Distribution O&M spending was also high, coming in more than **$300 million** above adopted levels; - Gas Distribution and Gas Transmission both fell well below adopted O&M spending, with combined underspend exceeding **$210 million**; - Gas Transmission capital spending came in about **$81 million** under plan, reinforcing the pattern of lower-than-adopted gas-side execution; - Shared Services /IT nearly doubled its adopted O&M spending, adding over **$170 million** above plan; and - Systemwide, PG&E spent about **$1.66 billion** more than adopted across safety-related O&M and capital, concentrated overwhelmingly in electric wildfire and asset-reliability categories. **Instant Analysis**: This filing provides two practical takeaways. - First, the corrected count of 4,676 Major Event Days wires-down events reinforces that this metric is almost entirely driven by storm frequency and offers little insight into day-to-day system performance, something PG&E openly acknowledges by excluding it from internal reporting, performance goals, and incentive structures. - Second, the revised Section 4 spending tables highlight PG&E’s ongoing pattern: heavy electric-distribution spending tied to wildfire and overhead-asset programs, paired with consistent shortfalls in gas-system spending. For rate observers, it's worth watching how these spending patterns will be examined in PG&E's [2027 General Rate Case](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com), where parties may question whether PG&E’s mitigation portfolio is drifting out of balance between electric wildfire risk and long-term gas-system reliability. --- ## PUBLIC SAFETY POWER SHUTOFFS SCE issued two [Public Safety Power Shutoff](https://www.sce.com/outages-safety/outage-preparedness/outage-types/public-safety-power-shutoff-psps?ref=calregulatory.com) post-event reports covering early November 2025, each driven by fast-changing fire-weather conditions and elevated wind forecasts. - A [November 2–6 event](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K323/588323055.PDF?ref=calregulatory.com) in Inyo and Mono Counties involved strong onshore winds that produced High Wind Warnings, extremely low humidity, and gusts reaching 66 mph, leading SCE to de-energize 1,145 customers on the Birchim and McGee circuits. - Days later, a weaker but still consequential Santa Ana pattern prompted [a second event from November 7–10](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K647/588647658.PDF?ref=calregulatory.com) affecting Los Angeles, Ventura, Riverside, and especially San Bernardino County, where 909 customers on the Firebird and Northpark circuits were de-energized after forecast and real-time winds neared PSPS thresholds. Across both events, SCE activated its PSPS Incident Management Team, issued thousands of notifications, set up [Community Resource Centers](https://www.sce.com/outages-safety/safety-resources-support/community-resource-centers?ref=calregulatory.com), and relied on its machine-learning-enhanced Fire Potential Index modeling, localized weather-station data, and [Technosylva](https://technosylva.com/?ref=calregulatory.com) wildfire-risk simulations to confirm that avoiding potential wildfire consequences outweighed the temporary impacts of shutoffs. In both cases, no damage or hazards were found during patrols, and power was restored once wind speeds and Fire Potential Index values fell below de-energization triggers. **Instant Analysis:** Both reports reinforce how deeply embedded PSPS has become in SCE’s wildfire-season operations, even in shoulder-season months like early November. What stands out is not the scale of the shutoffs (which is modest by historical standards) but the sensitivity of SCE’s trigger framework: - Localized, high-resolution Fire Potential Index modeling; - Aggressive wind-trigger thresholds; and - Rapid expansions of scope based on evolving forecasts. The Eastern Sierra event demonstrates how non–Santa Ana wind regimes can now generate PSPS conditions, while the subsequent Santa Ana event shows that even weaker wind patterns can still push circuits over modeled thresholds. The absence of any damage findings highlights the precautionary nature of the activations. --- ## ARTIFICIAL OIL ISLANDS Last year, SCE filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M548/K361/548361608.PDF?ref=calregulatory.com) to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the [THUMS artificial oil islands](https://en.wikipedia.org/wiki/THUMS%5FIslands?ref=calregulatory.com) must be replaced under a new, customer-financed Added Facilities Agreement, with THUMS or any successor customer providing all upfront capital and covering all removal-cost risk. SCE argues that [Rule 2](https://studylib.net/doc/18609773/tariff-rule-2.h---southern-california-edison?ref=calregulatory.com) and the 1965 AFA require the customer (not general ratepayers) to fund these special, oil-field-specific facilities. With replacement estimated at **$190 million** \+ and likely to take a decade amid declining oil production, [Senate Bill 1137](https://www.conservation.ca.gov/calgem/Pages/SB1137.aspx?ref=calregulatory.com) buffer-zone restrictions, and State/City plans to retire offshore drilling, SCE warns that utility financing could strand nine-figure assets and violate longstanding policy that added-facility costs cannot shift to the broader rate base. On November 25 – in response to an ALJ request – the City of Long Beach and THUMS [submitted a joint filing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K647/588647705.PDF?ref=calregulatory.com) clarifying that the Long Beach Unit (the eastern [Wilmington Oil Field](https://en.wikipedia.org/wiki/Wilmington%5FOil%5FField?ref=calregulatory.com), including the four THUMS islands), is owned by the State, held in trust by the City, and operated with THUMS as the field-contractor’s agent. They report that the State Lands Commission provides oversight but has declined to participate directly in this proceeding, instead deferring to the City in its trustee role. **Instant Analysis:** This proceeding may create precedent for how the CPUC handles aging, oil-specific infrastructure in a phase-down environment, with potential ripple effects for other legacy Added Facilities Agreement. ### WEEKEND NEWS CODEX: Solar Interconnection Delays; BTM Thermal Energy Storage; Rising Electricity Prices URL: https://www.calregulatory.com/weekend-news-codex-5/ Last updated: 2025-12-01T17:27:33.000Z - **CPUC Urged to Hold PG&E and SCE "to Account" for Solar Interconnection Delays:** "A group of California legislators has called on the state Public Utilities Commission to hold two utilities accountable for delays in connecting solar PV and energy storage capacity to the grid. 18 legislators penned an open letter to the California Public Utilities Commission this week, urging the regulator to hold Pacific Gas & Electric and Southern California Edison to account for 'repeatedly missing state-mandated timelines to interconnect solar and storage.' Californians installing solar or energy storage capacity need approval from their utility before they can interconnect with the grid. The CPUC has introduced mandatory timeframes for those approvals and a rule that utilities meet those timeframes 95% of the time, but the open letter claims that PG&E and SCE miss some of their deadlines 'as much as 73% of the time.'" [**PV TECH**](https://www.pv-tech.org/cpuc-urged-to-hold-pge-and-sce-to-account-for-solar-interconnection-delays/?ref=calregulatory.com)(*additional coverage at* [**SOLAR POWER WORLD**](https://www.solarpowerworldonline.com/2025/11/18-california-legislators-ask-cpuc-to-address-solar-interconnection-delays/?ref=calregulatory.com)) - **Electric Big Rigs Get a New Fast-Charge Pit Stop in California:** "[Terawatt Infrastructure](https://www.terawattinfrastructure.com/?ref=calregulatory.com) has switched on its newest commercial EV charging hub in Rialto, California, giving electric truck fleets a new high-speed charging stop along one of the US’s busiest freight routes. The hub is situated on the eastbound side of I-10 and is designed for heavy-duty fleet use, particularly for trucks traveling from the Ports of Los Angeles and Long Beach through Southern California’s industrial centers." [**ELECTREK**](https://electrek.co/2025/11/17/electric-big-rigs-get-a-new-fast-charge-pit-stop-in-california/?ref=calregulatory.com) - **Gasoline Prices Are Generally Lower in Red States:** "California leads the pack of high-cost gasoline states. Its average gasoline price is $4.64 per gallon, 50% higher than the national average at $3.09 per gallon. It also has the highest state gasoline tax of [$0.709 per gallon](https://taxfoundation.org/data/all/state/gas-taxes-state/?ref=calregulatory.com). Besides the gasoline tax, [California has additional hidden fees](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/newsoms-california-gasoline-price-gouging-assertion-is-a-myth/?ref=calregulatory.com), including a cap-and-trade program to lower greenhouse gas emissions, a low-carbon fuel program, underground gas storage fees, and a state and local sales tax — all adding to the price of gasoline. While it has oil resources and is the eighth largest producer of oil among the states, its [oil production has gone down due to state policies](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/californias-refinery-situation-looks-like-it-will-get-worse/?ref=calregulatory.com). It has also closed refineries, with two more in the works, which means it will have to import more oil and refined products to meet demand." [**INSTITUTE FOR ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/fossil-fuels/gas-and-oil/gasoline-prices-are-generally-lower-in-red-states/?ref=calregulatory.com) - **How Batteries, Not Natural Gas, Can Power the Data Center Boom:** "By putting in batteries \[at data centers\], you’re actually lowering everyone else’s electricity bill, because you’re adding capacity." [**YALE ENVIRONMENT 360**](https://e360.yale.edu/features/jigar-shah-interview?ref=calregulatory.com) - **Macro Problems for Microgrids in California**: "One of the central barriers is the role of the investor-owned utilities, particularly PG&E, Southern California Edison, and San Diego Gas & Electric. Utilities control the wires and interconnection points, which means that every community microgrid must navigate a utility approval process. These processes are lengthy, costly, and often designed to preserve utility control rather than empower local resilience. As a result, even communities eager to build clean, independent microgrids frequently face years of delay. Moreover, in many cases, implementing a microgrid project is nearly impossible due to regulatory obstacles designed to prevent utilities from losing customers, with the “over-the-fence” rule being the most significant barrier." [**PV MAGAZINE**](https://pv-magazine-usa.com/2025/10/20/macro-problems-for-microgrids-in-california/?ref=calregulatory.com) - **Nostromo's Thermal ESS Participates in CAISO Energy Market**: "The IceBrick is installed at the Beverly Hilton Hotel and also serves the adjacent Waldorf Astoria. Israel-headquartered technology company Nostromo claims it is the first behind-the-meter thermal energy storage system to participate in the CAISO wholesale energy market as a standalone demand response resource, through a partnership with distributed energy resource integration provider Olivine." [**ENERGY STORAGE NEWS**](https://www.energy-storage.news/nostromos-thermal-ess-participates-in-caiso-energy-market/?ref=calregulatory.com) - **PG&E Poll – Majority of Californians Support Powerline Undergrounding for Wildfire Mitigation:** "PG&E said Nov. 19 that after energizing 1,000 miles of underground powerlines in October, the poll found that nearly 90 percent of Californians surveyed supported the energy company burying power lines to eliminate nearly all wildfire risk posed by that equipment. The poll also showed that more than 70 percent of respondents think that their energy company should be investing more in undergrounding power lines, when compared to less costly mitigation tactics, such as installing covered conductors or implementing proactive outages to prevent ignitions." [**DAILY ENERGY INSIDER**](https://dailyenergyinsider.com/news/50393-pge-poll-majority-of-californians-support-powerline-undergrounding-for-wildfire-mitigation/?ref=calregulatory.com) - **The Rhyme and Reason Behind Rising Electricity Prices:** "According to S&P Global, the largest rate increase requests filed in 2025 belong to the following: - Florida Power & Light Company \[FPL\] ($2,472,100,000) - Consolidated Edison Company in New York \[Con Ed\] ($1,608,400,000) - Pacific Gas & Electric Company in California ($1,842,000,000 combined) - Virginia Electric & Power Company \[Dominion\] ($1,169,000,000) - Arizona Public Service Company \[APS\] ($662,400,000) - DTE Electric Company in Michigan ($574,100,000)." [**ENERGY BAD BOYS**](https://energybadboys.substack.com/p/the-rhyme-and-reason-behind-rising) ### MID-WEEK NEWS CODEX: Microgrids in Napa; the CAISO's Genie; Speed to Power URL: https://www.calregulatory.com/mid-week-news-codex-microgrids-in-napa-the-caisos-genie-speed-to-power/ Last updated: 2025-12-01T17:28:02.000Z - **An Aviation Fuel Crisis May be Coming to California:** "California’s declining oil production and refinery closures, caused by the state’s energy policies, could create an '[aviation fuel crisis](https://avweb.com/aviation-news/california-faces-aviation-fuel-strain/?ref=calregulatory.com).' An increasing dependence on imported aviation fuel could threaten national security. Several U.S. military installations, including Travis Air Force Base and Naval Air Weapons Station China Lake, rely almost entirely on California refineries for their jet fuel. [According to the Energy Information Administration](https://www.eia.gov/state/seds/sep%5Ffuel/html/pdf/fuel%5Fjf.pdf?ref=calregulatory.com), California ranks first in jet fuel demand among the states." [**INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/big-green/an-aviation-fuel-crisis-may-be-coming-to-california/?ref=calregulatory.com) - **A Tale of Four Microgrids – On-Site Energy Decisions Making Sense Across Sectors:** "Napa Valley champagne and wine producer Domaine Carneros...installed solar panels some years ago but wanted to unite all its distributed energy resources into a [controlled solar-storage and backup microgrid](https://www.microgridknowledge.com/commercial-microgrids/article/55271720/domaine-carneros-microgrid?ref=calregulatory.com) which can deliver energy resiliency in a region known for weather events and utility-enforced public safety power shutoffs. 'We’re close to the end of the grid,” \[CEO **Remi**\] **Cohen** pointed out. 'Energy resiliency means allowing continuous operations even during extended outages on the grid. We knew (installing the microgrid) would get us closer to energy independence.'" [**MICROGRID KNOWLEDGE**](https://www.microgridknowledge.com/commercial-microgrids/article/55332795/the-future-of-energy-resilience-microgrids-transforming-industries-across-america?ref=calregulatory.com) - **California Sees Sustained Decline in Natural Gas Use as Solar Output Rises**: "Natural gas generation consistently decreases during the midday hours between noon and 5:00 p.m. when solar generation peaks. In May and June, solar generation within those hours increased from 10.2 GW in 2020 to 18.8 GW in 2025." [**CANARY MEDIA**](https://www.pv-magazine.com/2025/11/26/california-sees-sustained-decline-in-natural-gas-use-as-solar-output-rises/?ref=calregulatory.com)(*additional coverage in*[***PV MAGAZINE***](https://pv-magazine-usa.com/2025/11/25/california-natural-gas-use-declines-as-solar-generation-rises/?ref=calregulatory.com)***,*** [***UTILITY DIVE***](https://www.utilitydive.com/news/natural-gas-generation-falling-california-solar-rising/806404/?ref=calregulatory.com)) - **Data Centers are Breaking the Old Grid – Let AI Build the New One:** "In California, Pacific Gas & Electric has turned to AI to blunt one of the state’s greatest threats: fire. The utility now uses AI to monitor fire conditions and provide automated notifications, improving response times, it says. The utility’s combined efforts have brought [reportable ignitions down 65%](http://www.renewableenergyworld.com/news/california-utility-preparing-for-peak-wildfire-season-with-ai-automation-and-drones/??ref=calregulatory.com) compared to the 2018-2020 average.For towns that have lived through evacuations and blackened skies, that drop means fewer late-night sirens and fewer lives uprooted. The state’s grid operator, the California Independent System Operator, is also experimenting with a generative AI system known as [Genie](https://www.govtech.com/artificial-intelligence/california-turning-to-ai-to-manage-power-outages??ref=calregulatory.com)." [**UTILITY DIVE**](https://www.utilitydive.com/news/ai-utilities-reliability-cost/805224/?ref=calregulatory.com) - **Federal Mandates Are Quietly Driving Prices Up:** "...demand isn’t the problem. Policy friction is." [**GRID BRIEF**](https://www.gridbrief.com/p/fed-mandates-vanishing-data-centers-pjm-gridlock?ref=calregulatory.com) - **How Green is Gavin?** "The chart below shows how electricity prices in California compare to the national average since Newsome became governor. Today, California residential electricity rates are 86% above the national average." [**ENVIRONMENTAL** ](https://envmental.substack.com/p/how-green-is-gavin-pt-2) [![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/gavin-1.png)](http://envmental.substack.com/p/how-green-is-gavin-pt-2) - **Interior Offshore Oil Drilling Plan Includes Six Potential California Lease Areas**: "Of the six California areas, three are off the coast of southern California starting in 2027, two along the central coast starting in 2027, and one off the coast of northern California starting in 2029." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/interior-offshore-drilling-plan-includes?ref=calregulatory.com) - **Recology Drives Ahead with Fleet Transition Despite Deregulation:** "Recology is seeing increased uncertainty in the zero-emission vehicle market in the wake of regulatory rollbacks affecting heavy-duty fleets. But the hauler, among California’s largest, is still plotting a full transition. Last month, [Recology completed a fleet transition plan](https://cte.tv/post/cte-and-c-h-robinson-foundation-grant-support-recologys-zero-emission-fleet-transition-planning?ref=calregulatory.com) with the nonprofit Center for Transportation and the Environment after winning a competitive grant process backed by the C.H. Robinson Foundation, a philanthropic fund tied to the logistics and supply chain company of the same name." [**WASTE DIVE**](https://www.wastedive.com/news/recology-fleet-transition-plan-cte-regulatory-challenges/805410/?ref=calregulatory.com) - **Speed to Power and the Department of Energy's Grid Proposal to FERC**: "Key to \[Consumer Regulated Electricity, "CRE"\] is that it is off-grid, meaning it is not physically connected to the electricity grid that we all use daily. By being off-grid, there’s no need for state utility regulation. What does this then have to do with the DOE and FERC? By being off-grid, CRE is not part of the bulk power system. Common sense tells us this is true, but common sense doesn’t always shine through in the heavily regulated electricity sector. Therefore, our responses in the two dockets ask DOE and FERC to formally acknowledge that CRE operates outside of FERC jurisdiction, including the mandatory reliability standards created by the North American Electric Reliability Corporation and enforced by FERC." [**THE FISHTANK**](https://travisfisher.substack.com/p/speed-to-power-and-the-department) - **What's in FERC's Large Load Interconnection Docket:** "Filings from OpenAI, Microsoft, Google, the Data Center Coalition, and the Clean Energy Buyers Association all agree that the current interconnection process is hampering AI growth, and poses an existential threat to U.S. leadership in the sector. But they’re divided on the key question of whether FERC should preempt state-regulated interconnection processes." [**LATITUDE MEDIA**](https://www.latitudemedia.com/news/whats-in-fercs-large-load-interconnection-docket/?ref=calregulatory.com) - **What's the Deal with Balcony Solar?** " If you have a net metering agreement, then you can attach one of these and have it fall under that same net metering agreement, whether it’s NEM1, NEM2, NEM3, under a certain threshold. In California that’s 1 kilowatt. You can buy right now...a system that’s up to 1 kilowatt and plug it in, and it will be considered part of your net metering expansion...You do not need a new interconnection agreement." [**VOLTS**](https://www.volts.wtf/p/whats-the-deal-with-balcony-solar?ref=calregulatory.com) ### WEDNESDAY AGGREGATE: Dynamic Pricing Ascends; Grid-Wide CAISO Dynamics; Interconnection Reforms URL: https://www.calregulatory.com/wednesday-aggregate-dynamic-pricing-ascends-grid-wide-caiso-dynamics-interconnection-reforms/ Last updated: 2025-12-01T17:28:24.000Z Today's briefing examines how: - Dynamic pricing is shifting from pilot programs to consolidated policy frameworks; - Gas infrastructure upgrades face new climate-adjusted scrutiny that treats long-term demand decline as the baseline assumption rather than a sensitivity case; - Transmission balancing accounts reveal increasing volatility driven by grid-wide CAISO dynamics rather than utility-specific costs, making year-ahead forecasting less stable; - The CAISO's interconnection reforms, while administratively sophisticated, hit their limits in Cluster 15, where deliverability scarcity becomes the binding constraint; and - PG&E makes a low-key (but significant) move to socialize microgrid project-failure risk, which shifts exposure from utility shareholders to ratepayers. To some degree, all of these developments are symptoms of a regulatory apparatus adapting to the gap between policy ambition and infrastructure reality. --- ### DYNAMIC PRICING The CPUC issued an [amended scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K345/588345862.PDF?ref=calregulatory.com) that consolidates two SCE dynamic pricing applications: for large-power customers ([A.24-06-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M534/K357/534357113.PDF?ref=calregulatory.com)) and one for general residential and non-residential customers ([A.24-12-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M549/K805/549805930.PDF?ref=calregulatory.com)). The proposed **Large Power Customer Dynamic Rate** has three parts: - A subscription component, based on the tariff that would otherwise apply to the customer ("Otherwise Applicable Tariff"); - A dynamic component, based on day-ahead hourly market prices and load forecasts, governed by contracts between Edison and individual customers; and - A non-bypassable charge. Similarly, Edison's proposed **General Dynamic Rate** schedule also has three parts: - A subscription component, based on customers' Otherwise Applicable Tariff; - A dynamic component, based on day-ahead hourly market prices and load forecasts (applicable only to the portion of the customer's consumption "that is deemed flexible"); and - An "other" component, including non-bypassable charges and Facilities Related to Demand Charges. Intervenor testimony is due **January 16, 2026**, with rebuttal testimony due **February 17, 2026**. **Instant Analysis:** By consolidating SCE’s two applications and anchoring them to the Commission's demand-flexibility framework (established in a decision last August, [D.25-08-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M578/K182/578182496.PDF?ref=calregulatory.com)), we have another indicator that dynamic rates are moving from pilot-stage experimentation to core rate-design policy. --- ### PG&E GAS COMPRESSOR STATION The CPUC issued a [scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K309/588309795.PDF?ref=calregulatory.com) in the proceeding where [PG&E seeks](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M562/K082/562082344.PDF?ref=calregulatory.com) a Certificate of Public Convenience and Necessity to replace aging electrical systems at the [S-238 Hinkley gas compressor station](https://ia.cpuc.ca.gov/environment/info/panoramaenv/Hinkley/index.html?ref=calregulatory.com). The ruling notes that a draft Initial Study/Mitigated Negative Declaration was issued with a final CEQA document (expected in **January 2026**), and identifies key issues for litigation, including General Order and Public Utilities Code compliance obligations, environmental review, potential stranded-asset concerns tied to declining gas demand, project cost reasonableness, and public-interest considerations. Because intervenors questioned whether some electrical components might be linked to gas-throughput needs, PG&E is ordered to submit supplemental testimony itemizing each asset, explaining whether it is affected by compression volumes, and assessing whether any such equipment would still be needed under steep long-term gas-demand decline. **Instant Analysis**: By elevating stranded-asset risk, tying asset need to long-term declines in gas throughput, and requiring PG&E to provide granular testimony on whether any electrical components are functionally linked to compression capacity, the CPUC is laying the groundwork for a more exacting review of gas-infrastructure upgrades. The directive to assess each asset’s necessity even under steep gas-demand reductions (more than 40% by 2065) indicates that future CPCNs for gas facilities may face similar climate-adjusted scrutiny. --- ### SDG&E TRANSMISSION SDG&E filed Advice Letter 4760-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to notify the CPUC that it has submitted its annual Transmission Access Charge Balancing Account Adjustment (TACBAA) update to FERC, in which it seeks revised transmission revenue requirements and rates effective **January 1, 2026**. The TACBAA tracks the difference between CAISO-billed transmission costs and revenues SDG&E receives as a Participating Transmission Owner, and the 2026 update reflects a projected year-end undercollection of **$102.8 million**, lower forecasted Net Access Charge billings, and adjusted franchise fee/uncollectible estimates, resulting in a total TACBAA credit of **$165.8 million** (which is significantly lower than the previous year’s $338.1 million credit). SDG&E proposes a 2026 TACBAA rate of **–$0.00993/kWh** and requests authority to revise its retail transmission rates upon FERC approval, with changes expected to be consolidated into other January 2026 rate updates for all bundled, Direct Access, and Community Choice Aggregator customers. Protests are due **December 10**. **Instant Analysis:** SDG&E’s TACBAA update highlights how volatile CAISO transmission settlements can rapidly swing a major balancing account from overcollection to undercollection in a single cycle. The $165.8 million credit for 2026 is about half of last year’s, driven mainly by unexpectedly low CAISO revenue credits through October 2025 (an outcome that reverses prior forecasts and tightens the retail offset customers saw in 2025). The smaller proposed TACBAA rate means transmission-related relief on January 1 will be muted compared to last year’s large downward push. For procurement-facing entities, the filing underscores that TACBAA is increasingly sensitive to CAISO-level dynamics rather than SDG&E-specific cost movements, making year-ahead forecasting less stable and more dependent on grid-wide high-voltage transmission revenue signals. --- ### SCE TRANSMISSION Southern California Edison filed AL 5689-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters/pending?ref=calregulatory.com)) to notify the CPUC of its annual updates to the Reliability Services Balancing Account Adjustment (RSBAA) and the Transmission Revenue Balancing Account Adjustment (TRBAA), reflecting corresponding filings made at FERC for 2026\. - The filing shows that SCE’s retail Reliability Services revenue requirement will rise from $8.5 million in 2025 to **$9.5 million** in 2026, driven mostly by higher [Black Start Capability](https://www.energysage.com/electricity/black-start-why-it-matters/?ref=calregulatory.com) costs. - Revised RSBAA rates (allocated using 12-[Coincident Peak](https://www.awesense.com/ecosystem/coincident-peak-and-non-coincident-peak-analysis/?ref=calregulatory.com) demand and updated for each rate group) show modest increases across nearly all customer classes. SCE also proposes a new TRBAA credit of **–$0.00222/kWh**, a smaller credit than the current –$0.00271/kWh due to lower forecasted Transmission Revenue Credits. Beginning **January 1, 2026**, SCE will combine these updated components with its existing Transmission Access Charge Balancing Account Adjustment to produce a consolidated Transmission Owner Tariff Charge Adjustment for all retail rate schedules. Protests are due **December 10**. **Instant Analysis:** While routine, this filing is a reminder of how even small balancing-account adjustments can stack into year-ahead transmission charges. The RSBAA increase reflects a narrow driver (higher Black Start costs) while the reduced TRBAA credit continues the broader trend of shrinking transmission revenue offsets. None of the changes meaningfully move bills on their own, but together they fold into the January 2026 transmission update cycle that will shape total TAC/Transmission Owner Tariff Charge Adjustment impacts for all customers. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4608-2.jpg) ### INTERCONNECTION A [new report](https://gridstrategiesllc.com/wp-content/uploads/GS%5FInterconnection-Queue-Rationing-Reforms.pdf?ref=calregulatory.com) from [Grid Strategies](https://gridstrategiesllc.com/?ref=calregulatory.com) examines how growing transmission scarcity and mounting interconnection backlogs have pushed regional grid operators to adopt various forms of interconnection queue rationing, often through temporary fast-track programs or permanent intake controls that deviate from longstanding open-access principles. - After outlining the structural causes of congestion (including limited engineering bandwidth, unpredictable upgrade costs, and inadequate proactive transmission planning) the report surveys the rationing mechanisms now in use across PJM, MISO, SPP, and the CAISO, ranging from one-time emergency programs favoring near-term capacity additions to zonal caps and scoring systems aligned with state procurement goals. - While some of these measures may speed individual projects, the report concludes they risk undermining fairness, transparency, and technology-neutral competition, and argues that long-term solutions must pair readiness-based queue discipline with forward-looking transmission planning that creates deliverability headroom and reduces reliance on ad-hoc rationing constructs. Regarding the CAISO's [Interconnection Process Enhancements ](https://www.stoel.com/insights/publications/refining-californias-grid-access-framework-caisos-draft-final-proposal-for-interconnection-process-enhancements-5-0?ref=calregulatory.com)(IPE) specifically, the report states: > On balance, CAISO’s IPE represents one of the most comprehensive queue reforms among system operators to date. By combining zonal deliverability caps, scoring-based prioritization, and transparent governance of deliverability allocations, CAISO has replaced an overloaded, speculative queue with a structured pipeline designed to integrate the resources most likely to be financed, built, and aligned with California’s needs. > Yet Cluster 15 \[**the CAISO’s current interconnection cycle, which experienced severe oversubscription and minimal advancement due to transmission constraints**\] demonstrates that administrative reforms alone cannot overcome physical infrastructure limits: timelines remain long, the share of projects advancing remains low, and significant low-cost energy potential remains stranded behind constrained transmission corridors. The upcoming refinements under IPE 5.0, particularly around energy-only conversion, long lead-time upgrades, and equitable scoring oversight, will determine whether CAISO can transform this framework into a sustainable, scalable model for integrating the volumes of clean energy required to meet California’s 2030 and 2045 goals. **Instant Analysis:** The report frames queue rationing as a symptom of a deeper constraint: the West’s inability to build transmission fast enough to keep pace with project development. The CAISO’s Interconnection Process Enhancements reforms have imposed order on a previously speculative queue, but Cluster 15 shows that process fixes cannot solve physical bottlenecks (deliverability scarcity is now the binding constraint). --- ### MICROGRIDS PG&E filed an [advice letter](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7764-E.pdf?ref=calregulatory.com) to revise its Microgrids Balancing Account so that the utility can record and recover expense costs associated with terminated or cancelled [Microgrid Incentive Program](https://www.pge.com/assets/pge/docs/save-energy-and-money/rebate-and-incentives/PGE-MIP-Handbook.pdf?ref=calregulatory.com) projects (i.e., costs that would otherwise be written off below the line). As the Microgrid Incentive Program advances, PG&E argues that two categories of expenses must be captured in a Microgrid Utility Infrastructure Upgrades sub-account: - Ongoing maintenance for Microgrid Special Facilities; and - Stranded capital costs from Microgrid Incentive Program projects abandoned due to factors outside PG&E’s control (e.g., construction issues, cost overruns, loss of financing, shifting tax incentives). Protests are due **December 8**. **Instant Analysis:** This filing is a low-key albeit meaningful move: PG&E is seeking to pre-authorize recovery of stranded microgrid development costs, which shifts the financial risk of failed Microgrid Incentive Program projects from the utility to ratepayers. In other words, the CPUC’s microgrid framework is evolving toward full socialization of project-failure risk, treating cancellations and early terminations as recoverable program expenses rather than utility write-offs. For entities following the Community Microgrid Enablement Program and Microgrid Incentive Program implementation, this is an early indicator of how cost exposure will be allocated as more microgrid pilots encounter practical or financing hurdles. ### December 4, 2025 CPUC Voting Meeting Preview URL: https://www.calregulatory.com/december-4-2025-cpuc-voting-meeting-preview/ Last updated: 2025-12-01T17:28:48.000Z [Agenda topics](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K332/588332492.pdf?ref=calregulatory.com) for the CPUC's **December 4** meeting span reliability preservation, program closeouts, cost-recovery frameworks, and infrastructure disputes. The Commission will consider whether to: - Preserve Ivanpah's solar-thermal contracts; - Approve Diablo Canyon's 2026 cost recovery; - Authorize SDG&E's ERRA forecast; - Tighten wildfire undergrounding requirements (this item is on the regular agenda – not the consent agenda – and will likely feature a discussion between the commissioners); - Wind down the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program/participating-in-self-generation-incentive-program-sgip?ref=calregulatory.com); - Consolidate [Transportation Electrification](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/transportation-electrification?ref=calregulatory.com) reporting; - Set the 2026 Wildfire Fund non-bypassable charge; - Approve Edison's tariffed on-bill financing pilot; - Terminate the [BioMAT program](https://pioneercommunityenergy.org/biomat/?ref=calregulatory.com); and - Deny CRPC’s request to classify the Union Island Pipeline as a public-utility asset. ### IVANPAH LIVES (FOR NOW) [Draft Resolution E-5429](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K132/586132670.PDF?ref=calregulatory.com) rejects (without prejudice) PG&E’s proposal to buy out and terminate its Power Purchase Agreements with Solar Partners II and VIII (the owners of the [Ivanpah solar-thermal facility](https://en.wikipedia.org/wiki/Ivanpah%5FSolar%5FPower%5FFacility?ref=calregulatory.com)). This rejection comes even as PG&E and the U.S. Department of Energy argue that ending the contracts would save ratepayers money, accelerate repayment of a remaining **$1.6 billion** federally backed loan, and potentially allow redevelopment of the site with newer technology. - Draft Resolution E-5429 finds that the contracts were procured fairly, remain aligned with PG&E’s renewable needs, and – given recent federal policy shifts, permitting uncertainty, and rising statewide load growth — cannot be terminated without risking reliability or stranding more than **$333 million** in ratepayer-funded transmission upgrades. - The rejection leaves the door open for PG&E to return with a future termination plan tied to a concrete replacement resource; meanwhile, if Ivanpah defaults, PG&E may still terminate without paying compensation. **INSTANT ANALYSIS:** This draft resolution effectively concedes that Ivanpah isn’t being preserved because it performs well, but because regulators don't think the state can afford to lose politically permissible megawatts (or risk stranding federally guaranteed debt). --- ### DIABLO CANYON COST RECOVERY A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820128.PDF?ref=calregulatory.com) approves PG&E’s request to recover **$382.233 million** in 2026 Diablo Canyon costs, continuing the cost-recovery framework established under [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com#:~:text=As%20directed%20by%20SB%20846,%2C%202030%20%28Unit%202%29.&text=PG%26E%20has%20operated%20Diablo%20Canyon,Luis%20Obispo%20County%2C%20since%201985.) and prior CPUC decisions. The PD deems PG&E’s **$563.9 million** O&M forecast reasonable, while requiring more detailed justification for future projects over $1 million, and distinguishes between state-funded transition costs and ratepayer-funded extended-operation costs. The PD authorizes statutory SB 846 payments (including **$113.97 million** in Fixed Management Fees, **$266.566 million** in Volumetric Performance Fees, and **$75 million** for the outage-related liquidated damages fund) and adopts PG&E’s proposal to escalate the Fixed Management Fee using the CPI-U inflation index. Costs are allocated across PG&E, SCE, and SDG&E, recovered through a non-bypassable charge applied to all customers, with PG&E forecasting a slight 2026 rate reduction assuming strong market revenues and full plant availability. **INSTANT ANALYSIS**: The CPUC is formalizing Diablo Canyon’s extended life as a managed, statewide reliability asset, with costs spread across all customers through a non-bypassable charge. Rate impacts remain modest under PG&E’s assumptions of strong market revenues and full plant availability, but Diablo Canyon’s ongoing costs (O&M, statutory SB 846 fees, and outage-related safeguards) are now a built-in feature of the rate environment for Community Choice Aggregators, Direct Access providers, and large customers. --- ### SDG&E 2026 ERRA FORECAST A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K455/586455828.PDF?ref=calregulatory.com) approves SDG&E’s Forecast 2026 ERRA request, authorizing **$824.1 million** (up from $122.3 million in 2025) primarily due to higher Portfolio Allocation Balancing Account (PABA) costs and lower market benchmarks. The PD finds SDG&E’s procurement, local generation, competition transition, and greenhouse gas allowance return forecasts reasonable, with rate impacts of roughly **10%** for bundled customers and **30%** to **40%** for unbundled customers. The PD adopts SDG&E’s **17,432 GWh** 2026 sales forecast, authorizes 2026 [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates, limits use of pre-2019 Renewable Energy Credits, and directs implementation of new rates via advice letter, effective **January 1, 2026**. **INSTANT ANALYSIS**: The PD reflects the Commission’s continued willingness to approve major procurement cost increases when they stem from market benchmarks and balancing-account corrections rather than utility error. The 10% to 14% bundled increase is tied to PABA dynamics and changing Resource Adequacy/Renewable Energy Credit valuations, showing how benchmark volatility can quickly translate into higher customer rates. The limitation on pre-2019 Renewable Energy Credits is the main constraint applied, emphasizing transparency in cost recovery even as the PD accepts most of SDG&E’s forecasting. --- ### UNDERGROUNDING of ELECTRICAL EQUIPMENT [Draft Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) updates the CPUC’s [Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) by expanding and tightening the review, cost-justification, and audit requirements established under [Resolution SPD-15 ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com)and aligned with [Energy Safety](https://energysafety.ca.gov/?ref=calregulatory.com)’s 2025 guidelines for [10-year Electric Undergrounding Plans](https://energysafety.ca.gov/news/2025/02/20/energy-safety-adopts-10-year-electrical-undergrounding-plan-guidelines/?ref=calregulatory.com). The draft resolution standardizes: - Project data submissions; - Revenue-requirement models; and - Decision-making metrics. The draft resolution also requires utilities to justify work outside high-fire-threat areas and limits eligibility to projects with benefit-cost ratios of at least 1 that meet defined risk thresholds. Additionally, Draft Resolution SPD-37 conditions cost recovery on: - Outperforming alternative mitigations; - Adhering to approved cost and benefit limits; and - Meeting Energy Safety performance standards... ...while introducing annual Electric Undergrounding Plan audits and a cumulative memorandum-account cap to guard against uncontrolled cost transfers. **INSTANT ANALYSIS**: Draft Resolution SPD-37 slows execution in exchange for audit-ready certainty, reframing undergrounding as defensible risk mitigation rather than symbolic wildfire policy. [Critics argue](https://capitolweekly.net/california-cant-afford-to-go-backward-on-wildfire-prevention/?ref=calregulatory.com) that the added bureaucracy risks delaying shovel-ready work and reducing near-term fire protection. --- ### ENDING the SELF-GENERATION INCENTIVE PROGRAM This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M588/K200/588200333.PDF?ref=calregulatory.com) sets the closeout process for the ratepayer-funded [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) (SGIP) while launching and defining administration of the new Greenhouse Gas Reduction Fund (GGRF) SGIP for low-income residential solar-plus-storage customers. The PD establishes deadlines for new SGIP applications (**December 30, 2025**), locks-in when funds are allocated, requires the annual return of unallocated and canceled-project funds to ratepayers, and shortens future performance-based incentive periods from five years to two for projects entering PBI after **December 30, 2025**. The PD grants struggling non-residential equity projects up to four additional six-month extensions under strict conditions and removes the Demand-Response requirement for low-income [Residential Solar and Storage Equity](https://ca.storeenergy.com/residential-equity-program/?ref=calregulatory.com) participants due to uneven statewide access to qualifying Demand-Response programs. The PD also: - Expands the ability of Program Administrators to modify the SGIP Handbook through advice letters; - Adopts a final streamlined measurement-and-evaluation plan; and - Establishes a **June 30, 2028** closure date for the Greenhouse Gas Reduction Fund SGIP, with remaining GGRF incentive and administrative funds to be returned to the state by early 2033. **INSTANT ANALYSIS:** The PD sets a disciplined wind-down for SGIP: - A hard stop on new ratepayer-funded applications in December 2025; - An accelerated performance-based incentive schedule; and - Annual returns of unused funds. The biggest move is relief for non-residential equity projects, granting four extra extensions to prevent large-scale cancellations in disadvantaged and tribal communities. Low-income residential applicants receive a Demand-Response exemption due to uneven statewide program access. The Greenhouse Gas Reduction Fund-funded SGIP is placed on a compressed timeline, closing to new applications in June 2028 with unused funds redeployed across Program Administrator territories before being returned by 2033. --- ### TRANSPORTATION ELECTRIFICATION This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K972/584972262.PDF?ref=calregulatory.com) tighten and simplifies the state's Transportation Electrification framework. The PD consolidates multiple reporting requirements into one annual TE compliance report that is due annually on **June 30**. The PD eliminates the annual Vehicle Grid Integration stocktake adopted in a 2020 decision, [D.20-12-029](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M355/K794/355794454.PDF?ref=calregulatory.com)) and shifts any future VGI reporting refinements to a Q1 2026 forum. Recall that the stocktake was intended to give the CPUC and stakeholders a clear picture of the current breadth of TE and VGI efforts. (A "repository of information" as the [Vehicle-Grid Integration Council](https://www.vgicouncil.org/?ref=calregulatory.com) has said.) The PD continues the "Technical Assistance Program" (which was established[ in 2022](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K005/499005805.PDF?ref=calregulatory.com)) with a **$36 million**, three-year budget, which is now fully decoupled from the paused "Funding Cycle One Behind-the-Meter Rebate Program." The PD stipulates that investor-owned utilities can recover pre-pause implementation costs from the latter program. Last, the PD removes the vehicle purchase requirement from Funding Cycle Zero medium- and heavy-duty programs to lower participation barriers but keeps the **December 31, 2026** sunset date. These programs include PG&E's [EV Fleet](https://www.pge.com/en/clean-energy/electric-vehicles/ev-fleet-program.html?ref=calregulatory.com) program, SCE's [Charge Ready Transport](https://crt.sce.com/overview?ref=calregulatory.com) program, and SDG&E's [Power Your Drive for Fleets Program](https://www.sdge.com/business/electric-vehicles/power-your-drive-for-fleets?ref=calregulatory.com). **INSTANT ANALYSIS:** The PD doubles down on the CPUC’s post-[D.22-11-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K005/499005805.PDF?ref=calregulatory.com) retrenchment strategy. It consolidates reporting, simplifies oversight, and keeps only the most defensible Transportation Electrification elements alive while the major rebate programs remain paused. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4705.JPG) ### WILDFIRE NON-BYPASSABLE CHARGE This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K972/584972246.PDF?ref=calregulatory.com) establishes the 2026 Wildfire Fund Non-Bypassable Charge (Wildfire Fund NBC) at **$0.00591/kWh**, effective from **January 1** through **December 31, 2026**, to collect **$908.9 million**. This amount reflects the statutory annual revenue requirement of $902.4 million under [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com) plus $6.5 million in a projected undercollection from previous years. AB 1054 established the NBC to provide a stable mechanism for California's Wildfire Fund, with PG&E, SCE, and SDG&E collecting and remitting funds to the Department of Water Resources (DWR). Since 2020, the CPUC has set the charge annually based on DWR's notices and revenue forecasts, via a collection-curve methodology to ensure revenue sufficiency. The rate has fluctuated slightly over time due to load forecasts and prior-year vacancies. The table below lists the NBC rates dating back to 2020. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/10/nbc.png) The PD orders each IOU to file a Tier 1 advice letter by **December 31, 2025** to implement the new charge. **INSTANT ANALYSIS**: The Wildfire Fund NBC remains a stable, guaranteed revenue mechanism driven by DWR accounting, utility load forecasts, and annual true-ups, not by wildfire-mitigation performance or utility behavior. For bundled, Direct Access, and Community Choice Aggregator customers, the charge continues to operate as a predictable, broadly similar cost layer, with only minor year-to-year variance dictated by sales projections and prior-period balances. --- ### CLEAN-ENERGY FINANCING **Administrative Law Judge Toy** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K815/585815581.PDF?ref=calregulatory.com) that approves with modifications a Tariff On-Bill financing pilot advanced by SCE. The PD rejects similar proposals from SDG&E, SoCalGas, and Silicon Valley Clean Energy. The [Tariff On-Bill concept](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-expands-on-bill-financing-options-for-non-residential-energy-utility-customers-2023?ref=calregulatory.com) allows customers to install clean-energy upgrades (e.g., heat pumps and efficiency measures) with no upfront cost, paying instead through a fixed charge on their utility bill tied to the property, not the individual. The PD finds Edison's proposal to be the only one sufficiently developed to test this model. The PD limits participation to approximately 200 residential sites and requires bill neutrality (meaning customers' total bills must not increase as a result of participating). The PD adds further customer protections, savings verification requirements, and reporting rules. PG&E did not propose a pilot. The rejected proposals had design flaws or did not align with CPUD directives. **INSTANT ANALYSIS**: This PD is a cautious green light, not a broad endorsement. If SCE's pilot demonstrates real savings, low defaults, and manageable administrative costs, tariffed on-bill financing could become a new cost-recovery tool for electrification, especially for households that can't access credit or capital. --- ### BIOENERGY MARKET ADJUSTING TARIFF This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) (BioMAT) program through December 31, 2025. The PD concludes that despite numerous reforms over the past decade, the BioMAT remains underutilized, high-cost, and administratively burdensome, with only about 21% of its 250 MW statutory target subscribed and 16 projects terminated before delivery. The PD finds the program’s poor performance, high per-MWh costs relative to other RPS resources, and the availability of alternative procurement mechanisms (including Renewables Portfolio Standard solicitations, [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), Qualifying Facility standard offers, Integrated Resource Planning procurement, and [Bioenergy Renewable Auction Mechanism](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-bioram?ref=calregulatory.com)) justify allowing the program to sunset. While acknowledging that statute sets no explicit end date, the PD emphasizes its authority to close underperforming programs and aligns its reasoning with the [Governor’s 2024 Affordability Executive Order](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com), which directs the Commission to modify or retire high-cost, low-value programs. Since the PD is allowing BioMAT to end, all requested programmatic changes (such as price adjustments, feedstock reallocations, or expanded uses for microgrids and LCFS-eligible charging) are summarily denied. **INSTANT ANALYSIS:** The PD effectively declares the BioMAT a high-cost, low-uptake legacy program that no longer justifies ratepayer funding in an affordability-driven environment. Despite a decade of tweaks, the BioMAT never scaled – only about 21% subscribed, with many contracts terminated (and its fixed prices sit far above mainstream RPS procurement). Going forward, it seems that niche, developer-driven procurement programs with stagnant participation will not survive under the state affordability mandate, especially where alternative procurement pathways exist. --- ### UNION ISLAND PIPELINE This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD finds that CRPC does not currently qualify as a “gas corporation” or “public utility” under California law because it no longer holds valid franchise rights in Antioch and Brentwood (those expired in 2021), and it stopped transporting gas in May 2023. The PD also cites ongoing litigation in which Antioch argues CRPC abandoned its pipeline interests, concluding that CRPC does not own, control, or operate the full pipeline and therefore cannot dedicate it to public use. The PD denies CRPC’s request to substitute a subsidiary into the application and the cities’ request to pause the proceeding, but grants CRPC’s motion to keep financial documents sealed for three years. **INSTANT ANALYSIS**: One reading of this PD is that the CPUC is applying a strict, formalist view of utility status – holding that public-utility privileges cannot attach unless an applicant already possesses uncontested, active operating rights and clear control of all relevant infrastructure. An altogether different read is that the PD treats unresolved city franchise disputes as a de facto veto over statewide utility classification, which is a circular standard found nowhere in the Public Utilities Code. Under this logic, CRPC cannot become a gas corporation without municipal rights-of-way, yet cannot secure or enforce those rights-of-way (including through eminent domain) without first being a gas corporation. ### MONDAY AGGREGATE: PG&E's CARD; ERRA Proposed Decisions; Hydrogen Blending Demo Projects URL: https://www.calregulatory.com/monday-aggregate-pg-es-card-filing-erra-pds-for-pg-e-and-sce-ious-hydrogen-blending-demo-projects/ Last updated: 2025-11-30T04:48:45.000Z Today's roundup captures a broad spectrum of items: - PG&E's gas-system cost allocation is being rebuilt in anticipation of declining throughput; - Electric utility ERRA forecasts are absorbing large year-end corrections and reshaping 2026 generation and [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates; - Gas utilities' hydrogen-blending pilots are being treated as controlled, data-gathering exercises rather than commitments to a new fuel standard; and - SoCalGas’s woody-biomass proposal highlights the Commission’s continued interest in low-carbon gas pathways, tempered by procedural and cost-reasonableness scrutiny. ### PG&E "CARD" FILING Earlier today we published [a first look](https://www.calregulatory.com/pg-e-card-filing-first-time-merger-of-the-gcap-and-gt-s-applications/) at PG&E's 2027 Gas Cost Allocation and Rate Design (CARD) [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050501.PDF?ref=calregulatory.com), which for the first time combines PG&E's historically separate Gas Cost Allocation Proceeding (GCAP) and Gas Transmission & Storage (GT&S) CARD into a single, unified framework. - The proposal recalibrates distribution, transmission, storage, and inventory-management costs using updated 2027–2030 forecasts, a shift to embedded-cost distribution methods, revised backbone path differentials, a new empirical imbalance-cost model, and an increase to the residential minimum monthly charge from $4 to **$15**. - While falling backbone and inventory-management costs look to provide short-term relief (especially for residential customers in 2027) projected increases in storage revenue requirements and class rebalancing drive future upward pressure, with small commercial, industrial, and certain wholesale/noncore groups seeing the largest impacts. **INSTANT ANALYSIS:** Residential customers get a temporary dip in 2027 due to lower backbone and inventory-management costs, but storage obligations dominate the out-years and will pull rates back upward. Small commercial, industrial, and certain wholesale/noncore groups absorb the brunt of these increases because the new cost-allocation mechanics redistribute a larger share of storage and distribution-related responsibility toward higher load-factor and distribution-tier customers. The revised imbalance methodology, higher minimum monthly charge, and annualized forecasts all point to PG&E preparing for a gas network that is contracting faster and becoming more cost-intensive to maintain. --- ### ERRA PROPOSED DECISIONS for PG&E and SCE The CPUC issued respective proposed decisions for the 2026 Energy Resource Recovery Account Forecast filings of [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781381.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K647/588647619.PDF?ref=calregulatory.com). Both PDs approve the utilities' 2026 ERRA-related forecasts: SCE’s **$4.689 billion** revenue requirement and PG&E’s $**4.511 billion** gross requirement. The PDs also implement updated fuel, purchased-power, Resource Adequacy, greenhouse-gas, and balancing-account true-ups for the **January 1, 2026** ratesetting cycle. This includes large year-end overcollections: **$700 million** for PG&E, and significant ERRA/Portfolio Allocation Balancing Account swings for SCE. Each PD: - Affirms the utilities’ updated electric-sales forecasts (SCE at approximately **80,447 GWh**; PG&E at approximately **27,101 GWh**); - Incorporates new Resource Adequacy, storage, and reliability-procurement costs; and - Adopts 2026 [California Climate Credit](https://www.cpuc.ca.gov/climatecredit/?ref=calregulatory.com) distributions (**$36.18** per customer for PG&E; $**384 million** in returns for SCE). Both PDs note declining bundled generation rates despite rising procurement-cost revenue requirements: SCE’s system-average ERRA generation rate falls about **11.9%**, and PG&E’s bundled residential rate drops by about **11%**. Each PD also updates [Power Charge Indifference Adjustment ](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com)vintages for 2026, resulting in increases for all unbundled customers, and resolves outstanding issues related to Resource Adequacy valuation, Renewable Energy Credit treatment, and [Voluntary Allocation Market Offer](https://avaenergy.org/wp-content/uploads/2022/05/4%5FVoluntary%5FAllocation%5Fand%5FMarket%5FOffer%5FVAMO%5FPresentation%5FDraft%5Fq7p7o3.pdf?ref=calregulatory.com)\-related tracking. **INSTANT ANALYSIS:** Both ERRA PDs show the same dynamic: higher overall procurement revenue requirements paired with lower bundled-generation rates in 2026, driven mostly by very large year-end balancing-account corrections and significant GHG-credit returns. For both PG&E and SCE, bundled customers benefit from accounting-driven decreases while Direct Access/Community Choice Aggregator customers face higher PCIA charges across all vintages. In effect, 2026 becomes a cleanup year, absorbing Market Price Benchmark volatility, loading in new Resource Adequacy and and energy storage costs, reconciling GHG proceeds, and unwinding substantial ERRA/PABA imbalances. Bundled rates fall for reasons tied to timing and corrections, not cheaper procurement, and unbundled customers will see noticeable PCIA pressure as a result. The Commission is scheduled to consider both PDs at its **December 18** meeting.(*We summarized the pending PD in SDG&E's 2026 ERRA forecast* [*here*](https://www.calregulatory.com/wednesday-aggregate/)*.*) --- ### IOU HYDROGEN BLENDING DEMO PROJECTS On September 26, 2025 the CPUC [convened a Public Participation Hearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K345/588345833.PDF?ref=calregulatory.com) in the proceeding where the major gas utilities propose to conduct hydrogen-blending demonstration projects. CPUC staff opened by summarizing the procedural history: the Commission had previously dismissed a 2020 blending application, then ordered new pilots through a 2022 decision ([D.22-12-057](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M500/K055/500055657.PDF?ref=calregulatory.com)) after UC Riverside conducted two major studies: - [Hydrogen Blending Impact Study](https://www.cert.ucr.edu/hydrogen-impacts-study?ref=calregulatory.com)*;* and - [Hydrogen Blending Compendium Report](https://docs.cpuc.ca.gov/PublishedDocs/SupDoc/A2209006/8727/586455848.pdf?ref=calregulatory.com) Those studies concluded that real-world demonstrations were necessary to understand materials compatibility, leakage behavior, and operational impacts before any statewide hydrogen-injection standard could be set. At the public hearing, utilities (especially SDG&E) highlighted research indicating that blends of up to **20%** hydrogen by volume behave similarly to natural gas with respect to flow regime, leakage, and appliance safety. SDG&E also emphasized that it only seeks O&M funding, has reduced its project costs by using renewable hydrogen produced at its Escondido site, and views blending as a cost-effective decarbonization approach consistent with modeling from the [California Air Resources Board](https://ww2.arb.ca.gov/?ref=calregulatory.com). The remainder of the hearing consisted of extensive public comment, with speakers representing community groups, technical experts, and local residents. Their testimony reflected a wide range of views, with some expressing support for controlled demonstrations, others raising concerns about safety, costs, pipeline integrity, environmental impacts, and whether hydrogen blending is an appropriate decarbonization pathway for California’s gas system. **INSTANT ANALYSIS**: The CPUC is treating hydrogen blending as a controlled experiment, not a step toward broad deployment. Utilities attempted to position 20% blends as technically safe and operationally manageable, but the Commission’s posture remains careful: it wants real-world data before entertaining anything beyond pilot work. SDG&E’s cost-reduction claims improve the optics, yet public testimony showed unresolved concerns around safety, materials impacts, community risk, and whether hydrogen blending fits California’s long-term gas transition. --- ### SOCALGAS WOODY BIOMASS PROPOSAL On November 21, 2025 parties responded to SoCalGas's [proposed woody-biomass pilot project](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K959/583959234.PDF?ref=calregulatory.com) that would convert almond-orchard residues (such as removed trees, shells, and sticks) into pipeline-quality bio-synthetic natural gas ([Bio-SNG](https://www.sciencedirect.com/topics/engineering/bio-synthetic-natural-gas?ref=calregulatory.com)). The project, developed by [West Biofuels](https://www.westbiofuels.com/?ref=calregulatory.com), would gasify agricultural woody waste to produce biomethane for injection into SoCalGas’s system, funded with up to **$19.7 million** in previously allocated Cap-and-Trade allowance proceeds under [Senate Bill 1440](https://calmatters.digitaldemocracy.org/bills/ca%5F201720180sb1440?ref=calregulatory.com). - The [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) (BAC) [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K309/588309782.PDF?ref=calregulatory.com) SoCalGas’s proposed pilot, arguing that the project directly advances a long list of state climate, air-quality, wildfire-mitigation, agricultural-waste, and job-creation mandates. BAC emphasizes that converting almond-orchard waste and forest residues into pipeline-grade biomethane will cut [short-lived climate pollutants](https://www.ccacoalition.org/content/short-lived-climate-pollutants?ref=calregulatory.com), generate carbon-negative emissions aligned with [CARB’s Scoping Plan ](https://ww2.arb.ca.gov/our-work/programs/ab-32-climate-change-scoping-plan?ref=calregulatory.com)and [Senate Bill 1279](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202120220AB1279&ref=calregulatory.com), reduce agricultural open-burning and pile-decay emissions, support wildfire-mitigation efforts, and provide durable economic benefits in rural regions. BAC positions the pilot as a crucial test case for future woody-biomass-to-pipeline projects. - [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) does not address the merits of the technology but instead [protests](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K334/588334619.PDF?ref=calregulatory.com) the application on procedural and substantive sufficiency grounds. Cal Advocates notes that SoCalGas did not provide a detailed cost breakdown, which raises questions about the reasonableness of using Cap-and-Trade funds and whether any remaining funds should be used for applicant-owned infrastructure. - The [Small Business Utility Advocates](https://www.utilityadvocates.org/?ref=calregulatory.com) do not oppose the application but air ratepayer-affordability concerns and emphasize the importance of meaningful participation and job opportunities for small businesses. **INSTANT ANALYSIS**: The proposed pilot fits cleanly within California’s climate and waste-reduction goals, but if the CPUC views the application as weak on cost details and CARB-compliance, it will give Cal Advocates some procedural footing to push for a tighter scope and deeper project scrutiny. ### PG&E "CARD" Filing: First-Time Merger of the GCAP and GT&S Applications URL: https://www.calregulatory.com/pg-e-card-filing-first-time-merger-of-the-gcap-and-gt-s-applications/ Last updated: 2025-11-30T04:48:52.000Z On November 21, PG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050501.PDF?ref=calregulatory.com) seeking CPUC approval of its comprehensive 2027 Gas Cost Allocation and Rate Design (CARD) proposals, which for the first time combine its historically separate Gas Cost Allocation Proceeding (GCAP) and Gas Transmission & Storage (GT&S) CARD into a single, unified framework. - The filing aligns cost allocation, throughput forecasting, and rate design across gas distribution, transmission, and storage functions for the 2027–2030 period, using revenue requirements and capacity forecasts from PG&E’s pending 2027 [General Rate Case Phase I](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com). - PG&E emphasizes that falling gas throughput (driven by electrification and state climate policy) requires updated methodologies to maintain system safety and reliability while supporting decarbonization. - PG&E proposes shifting to embedded-cost allocation for distribution, updating backbone and local transmission methodologies, modifying energy-efficiency and brokerage-fee allocations, adjusting storage service design, updating master-meter discounts and Natural Gas Vehicle compression charges, and increasing the residential minimum monthly transportation charge from $4 to **$15**. **INSTANT ANALYSIS:** PG&E’s 2027 Gas CARD consolidates GCAP and GT&S into one framework and resets how gas costs are assigned as statewide gas use declines. Backbone and inventory costs fall, but rising storage obligations and the shift to embedded-cost distribution methods push costs upward for small commercial, certain noncore groups, and wholesale customers. Residential customers will see a brief dip in 2027 before pressures return in later years. The filing introduces new forecasting and imbalance tools that reshape how expenses are spread across customer classes as the gas system contracts. Below is an analysis of PG&E's accompanying testimony, which is available [here](https://pgera.azurewebsites.net/Regulation/search?ref=calregulatory.com). ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/iterograph_Fri-Nov-21-2025--39--1.png) ## ACCOMPANYING TESTIMONY ### **Policy Introduction** The policy portion of PG&E's testimony explains how the CARD fits into the overall ratemaking structure (following General Rate Case Phase I revenue authorization) and updates the underlying cost-of-service studies, including: - Embedded cost methodology; - Local-transmission allocation; - Energy-efficiency cost allocation; - NGV compression cost methodology; - Master-meter discounts; and - Inventory-management practices. PG&E argues that shifting fully to embedded costs better reflects today’s safety-driven investments and that rate design should be recalibrated annually rather than based on multi-year averaged forecasts. The company situates these proposals within California’s broader gas-transition policies, anticipating a nearly 10% decline in throughput by 2027 due to electrification and renewable expansion. PG&E proposes increasing the minimum monthly transportation charge, preparing for a future fixed residential charge, and aligning rate calculations with year-specific sales forecasts to maintain system stability as throughput erodes. ### **Forecast & Cost-of-Service Studies** PG&E projects a steady decline in natural-gas usage through 2030, driven mostly by reduced reliance on gas-fired electric generation as renewable and storage capacity grows on the CAISO system. - Market-responsive electric-generation demand falls sharply from 684 MDth/d in 2024 to the mid-500s by 2027–2030, with a small uptick in 2030 tied to the staged retirement of Diablo Canyon. Non-market-responsive cogeneration stays flat at approximately 148 MDth/d. - Core residential and commercial loads gradually decline due to energy-efficiency and electrification, while industrial throughput shows mixed trends (distribution-level volumes continue a long decline, but transmission-level throughput recovers slightly from post-COVID lows). Total on-system throughput falls from 2,008 MDth/d (2024) to roughly 1,820 MDth/d by 2030. - In designing backbone transmission rates, PG&E maintains the long-standing system-average backbone load-factor methodology adopted in prior GT&S and CARD cases, producing load factors of about 80% in 2027, declining to 74% by 2030\. This approach stabilizes Redwood/Baja path\* rates, avoids large swings tied to changing gas-supply patterns, and evenly allocates reserve capacity. - PG&E proposes a Baja-Redwood differential set at 50% of the natural differential, slightly lower than the 54% settlement value used for 2023–2026\. Adjustments for off-system flows, firm reservations, Silverado flows, and path-specific distortions round out the backbone inputs used to set 2027 rates. ### **Core Gas Supply** PG&E’s prepared testimony outlines Core Gas Supply’s methodology for determining storage inventory and withdrawal capacity necessary to meet the state’s 1-in-10 cold-day reliability standard. The testimony includes confidential storage tables showing current and proposed 2027 withdrawal levels, inventory trajectories, and allocations between PG&E-owned and independent storage providers. Core Gas Supply explains that, in the 2027 GRC, PG&E proposed making allocated-storage withdrawal capability dependent on inventory levels, prompting CGS to develop its own empirically based withdrawal-to-inventory curve using winter load data from 2015–2025\. By analyzing peak-demand days (defined as exceeding the 90th percentile) CGS derives a January baseline withdrawal capacity that should count toward meeting the reliability requirement. The testimony ultimately recommends specific-albeit-redacted thousand-Dth/day withdrawal levels to ensure PG&E can serve core customers during extreme conditions while aligning storage operations with updated standards and the 2024 [California Gas Report](https://www.pge.com/pipeline/en/reference-library/regulatory/cgr.html?ref=calregulatory.com). ### **Cost Allocation and Rate Design for GT&S** PG&E lays out how the utility will translate General Rate Case–adopted revenue requirements and capacity forecasts into actual gas transmission, storage, and customer-access rates for 2027–2030\. Most existing CARD structures remain intact (including Gas Accord backbone rate segmentation and unified volumetric Local Transmission rates) but PG&E proposes two notable changes: - A revised Baja–Redwood path differential set at 50% of the “natural” cost spread; and - A return to the pre-2023 method of allocating storage costs to injection, inventory, and withdrawal functions based on forecasted capacities rather than equal splits. The biggest update is PG&E’s new empirical method for allocating Inventory Management costs. Using five years of [SCADA](https://en.wikipedia.org/wiki/SCADA?ref=calregulatory.com)\-based imbalance data, PG&E shows that intra-day pressure-balancing needs dominate system operations and that the core, industrial, and electric-generation segments contribute to imbalances differently as throughput changes. PG&E therefore replaces the 2023 GT&S CARD all-party settlement’s old 50/50 weighting of inter- vs. intra-day imbalances with a forecast-adjusted, data-driven approach (roughly 36/64) and applies these refined class-level imbalance patterns to produce new Inventory Management rates. The filing also updates noncore Customer Access Charges to match GRC-adopted revenue requirements and blends seasonal storage changes into annual rates to avoid mid-year adjustments. ### **Distribution Cost Allocation and Rate Design** PG&E proposes a major shift in how gas distribution costs are allocated, replacing the longstanding marginal-cost methodology with an embedded-cost approach that PG&E argues more accurately reflects actual infrastructure and customer-service obligations. Because this transition significantly lowers the residential share of costs while increasing allocations for commercial and industrial classes, PG&E proposes a four-year glide path to avoid rate shock. PG&E also updates energy-efficiency allocations, the core brokerage fee, NGV compression costs, and gas baseline quantities, and introduces a new annual (rather than 4-year average) sales-forecast methodology to reduce balancing-account volatility as throughput declines. A central feature of the proposal is raising the residential Minimum Monthly Transportation Charge from $4 to $15, which PG&E argues is necessary to recover a meaningful portion of customer-related fixed costs, given that the true monthly cost to serve a residential gas customer approaches $28–$30\. PG&E presents the $15 charge as a partial, transitional step that improves cost causation, reduces volumetric rates, and modestly impacts about one-quarter of non-CARE customers. Looking ahead, PG&E indicates that a full fixed monthly customer charge will be proposed in a later CARD after the Commission’s Gas Transition Planning docket provides policy guidance. ### **Rate Table Appendices** Below are some observations from the rate-table testimony. - Backbone transmission revenue responsibility shifts downward for core customers. The Redwood Path (core) reservation charge falls from **$19.55** to **$11.09** (2026) and trends modestly afterwards. - Natural gas storage costs increase dramatically (especially in the core allocation). The core storage revenue requirement jumps **39 to 46%** across 2027-2030. - Inventory management costs fall sharply for both core and noncore (**\-22%** to -**26%** reductions for core and -**10%** to **\-12%** reductions for noncore). This is the clearest downward pressure item. - Local transmission remains nearly flat (inflation-only growth). Local Transmission Base increases **1%** per year for core and decreases -**3%** per year for noncore. - There is significant compression of the Customer Access Charge (CAC). Large Commercial/Core NGV/Industrial drops from **$0.1060** to **$0.0511** in 2027 and Residential/Small Commercial drops from **$0.3096** to **$0.2323**. - Bill impacts demonstrate a cross-current: core residential customers see decreases and small commercial and noncore customers face increases. - For bundled residential customers, after a General Rate Case-driven uptick, January 2027 rates drop about 5% under the CARD proposal. - Bundled small commercial customers see a 5.4% GRC-driven increase plus a 2.8% CARD-driven increase in 2027, followed by a 6.6% increase in 2028. - Many backbone and transmission-only rates see modest decreases, but distribution-tiered classes (e.g., SC noncore NGV, West Coast Gas Castle/Mather) see large increases (double-digit). - G-XF Expansion shipper rates remain stable and low-impact. - Seasonal Straight Fixed Variable/Modified Fixed Variable\*\* spreads remain intact. These rate tables suggest a reshuffling of PG&E’s gas cost allocation that ultimately moderates residential impacts while increasing pressure on small commercial, storage-dependent classes, and certain wholesale/noncore segments. The most consequential movement is the rise in storage-related revenue responsibility, which offsets major decreases in backbone and inventory management costs. Core customers benefit from double-digit reductions in backbone transmission charges, producing modest rate relief in 2027, but the relief is temporary as storage costs and class rebalancing tighten again by 2028–2030\. Small commercial customers, by contrast, face meaningful increases across both bundled and transport rates, with year-two (2028) impacts in the 6 to **15%** range, and wholesale classes tied to distribution see some of the largest increases in the entire portfolio. PG&E’s reductions to the Customer Access Charge shift more cost recovery back into volumetric components, subtly re-weighting cost responsibility onto higher load-factor users without explicitly changing rate-design formulas. ### FOOTNOTES \*PG&E’s Redwood and Baja Paths are the utility’s two major backbone gas-transmission corridors. Redwood moves gas from northern receipt points (Malin, Canadian and Northwest supplies) into PG&E’s system, while Baja moves gas from Southern California and Southwest interconnects northward. \*\*SFV recovers most fixed costs through the firm reservation charge and little through usage, while MFV shifts more of those fixed costs into volumetric charges, blending reservation and usage recovery. ### WEEKEND NEWS CODEX: Winter Reliability; P66 and Sustainable Aviation Fuel; Oil Drilling URL: https://www.calregulatory.com/weekend-news-codex-4/ Last updated: 2025-12-01T17:29:36.000Z - **2025-2026 Winter Reliability Assessment** – [**NERC**](https://www.nerc.com/globalassets/our-work/assessments/nerc%5Fwra%5F2025.pdf?ref=calregulatory.com) - **Appeals Court Grants Injunction against California Climate Risk Law:** "A federal appeals court granted an injunction against one of California’s climate reporting laws. The Chamber of Commerce and other business groups have challenged the laws on First Amendment grounds and have sought to block implementation of the laws while their lawsuit proceeds." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/appeals-court-grants-injunction-against?ref=calregulatory.com) - **Beyond the Day-Ahead: Bridging East and West, Redefining Hubs, and International Coordination in the West:** "...the [Legislative Analyst’s Office](https://lao.ca.gov/Publications/Report/4952?ref=blog.gridstatus.io#:~:text=Only%20about%2010%20percent%20of,has%20occurred%20in%20recent%20years.) reported that while only 10% of wildfires were started by utility equipment, 8 of the 20 most destructive fires in California’s history were started by powerlines. For example, the most destructive fire in state history was the Thomas fire, caused by strong winds, leading a SoCal Edison power line to arc. The grass below caught fire, and the strong Santa Ana winds carried the fire, ultimately burning 281,000 acres in less than two months." [**EXPORTS**](https://blog.gridstatus.io/western-markets-evolution-2025-part-2/?ref=calregulatory.com) - **Bid Optimization – ERCOT & CAISO Market Outlook:** "Adding to an already volatility-starved year, California has now been hit with a streak of cloud cover, and with it the disappearance of charging prices low enough to justify day-ahead arbitrage. Cloudy conditions will dominate over the next several days, with the 21st expected to deliver less than 10 GW of peak solar production. Stronger output should return by the 23rd, at which point TB4 is likely to become a solid strategy once again. In the meantime, operators stepping back from TB4 due to weak spreads should shift their focus toward real-time energy opportunities and regulation." [**ASCEND ANALYTICS**](https://www.ascendanalytics.com/blog/bid-optimization-ercot-caiso-market-outlook---week-of-november-19th-2025?ref=calregulatory.com) - **California's Green Gambit – A Timeline:** "Assembly Bill 118 artificially created more support for renewable energy by promoting the electrification of transportation and by directly funding projects such as the [California Electric Vehicle Infrastructure Project](https://calevip.org/?ref=calregulatory.com), which sought to, but has ultimately failed, to create an interconnected network of EV charging stations to compete directly with the scale of gas stations." [ **INSTITUTE for ENERGY RESEARCH**](https://www.instituteforenergyresearch.org/big-green/californias-green-gambit-a-timeline/?ref=calregulatory.com) - **California Climate Data Disclosure Hit by Court Order, Emissions Rule Still Intact:** "For the roughly 4,100 companies that had expected to prepare risk-reports under SB 261, the injunction creates ambiguity: whether a delayed deadline will follow, or whether state regulators may adjust their timeline, remains unclear. The outcome is being closely watched as a barometer of how far states may go in mandating climate-related disclosures, and whether such mandates survive constitutional challenge." [**CARBON HERALD**](https://carbonherald.com/california-climate-data-disclosure-hit-by-court-order-emissions-rule-still-intact/?ref=calregulatory.com) - **Choosing Between Increasing Subsidies or Lowering Rates for Electrification:** "States that remain committed to addressing climate change are deciding how to respond. Choices include backfilling federal spending or backing off of their climate ambitions. In late 2024, California’s Governor **Gavin Newsom i**nitially said the state would replace lost federal funding for electric vehicles, but then he [reversed](https://www.sfgate.com/tech/article/newsom-reverses-ev-credit-california-21057761.php?ref=calregulatory.com) course. Many states are facing fiscal challenges and have balanced budget obligations that make backfilling federal funding unrealistic. Summing up the challenge, during a recent [Politico interview](https://www.politico.com/newsletters/california-climate/2025/11/07/californias-next-senate-leader-talks-budget-oil-00643464?nname=california-climate&nid=00000189-315c-d8dd-a1ed-797dc9f10000&nrid=00000171-9576-d991-af75-b5f680310000%3Fexperience%5Fid%3DEXYF89KVT5UQ&template%5Fid=OT5J0E7B7DD7&is%5Flogin%5Flink=true&ref=calregulatory.com) about the loss of federal electric vehicle tax credits, incoming California Senate leader **Monique Limón** said the state needs to 'find the middle ground between desire and capacity.'" [**ENERGY at HAAS**](https://energyathaas.wordpress.com/2025/11/17/choosing-between-increasing-subsidies-or-lowering-rates-for-electrification/?ref=calregulatory.com) - **Clean Electrification is Inevitable:** "Copy California is always my mantra." [**VOLTS**](https://www.volts.wtf/p/clean-electrification-is-inevitable?ref=calregulatory.com) - **Energy M&A and PPAs – Risks, Costs, and Market Shifts:** "CAISO remains one of the most dynamic and cost-sensitive markets for energy procurement. Over the past year, inflation, supply chain constraints, and procurement mandates – combined with uncertainty surrounding tariffs and tax credits – have driven a sharp escalation in PPA pricing. Prior to the passage of the [One Big Beautiful Bill Act](https://www.ascendanalytics.com/blog/ascend-analytics-view-on-the-one-big-beautiful-bill?ref=calregulatory.com), solar PPA prices had already risen roughly 13% year-over-year. Following OBBBA’s accelerated tax credit phaseout timeline and continued tariff uncertainty, prices increased an additional 24%, marking one of the steepest short-term jumps in recent years." [**ASCEND ANALYTICS**](https://www.ascendanalytics.com/blog/us-energy-market-ppa-merger-acquisition-strategies-shifts?ref=calregulatory.com) - **Kinder Morgan and Phillips 66 Launch Western Gateway Pipeline Connecting Midwest Supply to the Southwest and California:** "Kinder Morgan, Inc. and Phillips 66 have announced the binding open season for an ambitious new refined products corridor: the [Western Gateway Pipeline](http://www.westerngatewaypipeline.com/?ref=calregulatory.com). Announced on October 20, the project pairs major midstream operators, leveraging both new build and significant reversals of existing assets. If built, the Western Gateway would, for the first time, supply California with refined fuels via pipeline directly from outside the state. This marks a pivotal shift for a region historically dependent on isolated in-state refineries and waterborne imports – offering new supply resilience for California, Arizona, and Nevada." [**STILLWATER ASSOCIATES**](https://stillwaterassociates.com/open-season-for-western-expansion-kinder-morgan-and-phillips-66-launch-western-gateway-pipeline-connecting-midwest-supply-to-the-southwest-and-california/?ref=calregulatory.com) ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/iterograph_Thu-Nov-20-2025--4--1.png) - **Phillips 66 to Supply SAF to DHL for Three Years:** "Phillips 66 has won a three-year contract to deliver over 240,000 metric tons of sustainable aviation fuel to DHL Group. 'The SAF will be produced at Phillips 66's Rodeo Renewable Energy Complex in California, one of the world's largest renewable fuels facilities with a production capacity of 150 million gallons per year of neat SAF (i.e. SAF that is not blended with conventional jet fuel),' DHL said..." [**RIGZONE**](https://www.rigzone.com/news/phillips%5F66%5Fto%5Fsupply%5Fsaf%5Fto%5Fdhl%5Ffor%5Fthree%5Fyears-20-nov-2025-182357-article/?ref=calregulatory.com) - **Rising Electricity Prices – the Missing Link:** "The reality is that many factors are contributing to rising electricity rates, especially the rapid increases that households and businesses have experienced over the last five years. But the various studies have overlooked a key factor: the changing *mix* of generating resources, as traditional fossil-fuel and nuclear plants have been replaced by wind and solar ones." [**REAL CLEAR ENERGY**](https://www.realclearenergy.org/articles/2025/11/20/rising%5Felectricity%5Fprices%5Fthe%5Fmissing%5Flink%5F1148513.html?ref=calregulatory.com) - **Q3 2025 Electric Rates Report –** [**CAL ADVOCATES**](https://www.publicadvocates.cpuc.ca.gov/-/media/cal-advocates-website/files/press-room/reports-and-analyses/251106-public-advocates-office-q3-2025-rates-report.pdf?ref=calregulatory.com) - **Trump Outrages California Authorities with Oil Drilling Plan:** "The U.S. federal government on Thursday announced plans to allow oil and gas drilling off the coast of California and Florida for the first time in decades, prompting a strong reaction from California’s governor, who called the plan 'idiotic.' The Department of the Interior yesterday [announced](https://www.doi.gov/pressreleases/interior-launches-expansive-11th-national-offshore-leasing-program-advance-us-energy?ref=calregulatory.com) an order signed by **Secretary Doug Burgum** titled Unleashing American Offshore Energy, which would roll back limits introduced during the previous administration and open up more offshore areas for oil and gas exploration." [**OIL PRICE**](https://oilprice.com/Latest-Energy-News/World-News/Trump-Outrages-California-Authorities-With-Oil-Drilling-Plan.html?ref=calregulatory.com) - **What's Happening in Energy?** "In California, Longroad Development Company, LLC is proposing to build and operate the Rosa Storage Project, a 1000 MW Battery Energy Storage System Generating Facility located in Moorpark. Queue Cluster 14 Interconnection Studies have been completed...and as a result of those studies, the project has been assigned a share of Reliability Network Upgrades (RNU, where IRNU is interconnection and GRNU is general) of $18.8 million due this month. Per the transmittal letter, 'It is SCE’s understanding that Interconnection Customer \[Longroad\] disputes the project payment schedule and requirement to post collateral to secure funding for its portion of the shared RNUs.'" [**HALCYON**](https://halcyon.io/blog/whatshappeninginenergy/nov21?ref=calregulatory.com) ### FRIDAY AGGREGATE: SCE Rates; Demand Response; Self-Generation Incentive Program URL: https://www.calregulatory.com/friday-aggregate-sce-rates-demand-response-self-generation-incentive-program/ Last updated: 2025-11-30T04:49:16.000Z Items on today's radar map out the early contours of SCE’s 2026 rate landscape: - A **$10.19** billion Post-Test Year update with low-single-digit bill impacts; - A full Transportation Electrification revenue refresh for Charge Ready and the Medium/Heavy-Duty portfolio; and - A meaningful expansion of the Capacity Bidding Program through a new direct-participation pathway aimed at SGIP customers. Additionally, SoCalGas adds new SGIP-eligible Time-of-Use rates for the Imperial Irrigation District and Anaheim. In sum, the filings add more clarity to **January 1, 2026** rates while quietly reshaping customer access to Demand Response. For more on January 1 rates, see the following CRI posts: - [January 1, 2026 Electric Rate Updates: PG&E, SCE, and SDG&E](https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/); - [PG&E Files Natural Gas Rate and PPP Surcharge Updates](https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/); - [SoCalGas Annual Consolidated Rate Update Filing](https://www.calregulatory.com/socalgas-annual-consolidated-rate-update-filing/); and - [SDG&E's 2026 Natural Gas Rates (in the November 3 Monday Aggregate)](https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/) (*For the results of yesterday's CPUC voting meeting, go* [*here*](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/)*.*) --- ### SOUTHERN CALIFORNIA EDISON RATES SCE filed Advice Letter 5677-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to implement its 2026 Post-Test Year ratemaking updates authorized in the CPUC's September decision ([D.25-09-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M580/K788/580788967.PDF?ref=calregulatory.com)) addressing Edison's 2025 General Rate Case. The filing updates SCE’s 2026 Authorized Base Revenue Requirement using the CPUC-approved attrition mechanism, which applies Consumer Price Index-based O&M escalation (capped at **5%**), wildfire-mitigation capital additions, and other adjustments. SCE incorporates several specific updates into its 2026 revenue requirement: - A revised uncollectibles factor (0.297%) that raises the Authorized Base Revenue Requirement by **$9.3 million**; - A correction to the gain on the sale of SCE's Long Beach Regional Office, reducing 2026 revenue requirement by **$1.382 million**; - A **$0.389 million** revenue-requirement reduction linked to insurance reimbursements for the 2020 Creek Fire; and - A **$26.3 million** reduction reflecting the continuation of customer-funded wildfire liability self-insurance through 2028\. After applying these adjustments, SCE’s 2026 GRC revenue requirement totals approximately **$10.19 billion**, allocated across distribution, generation, and new system generation functions. SCE reports that the updated Authorized Base Revenue Requirement will raise system-average bundled rates by about **2.4%** compared to current October 1, 2025 levels, with residential bills increasing roughly **2.6%** for both CARE and non-CARE customers. These impacts will ultimately be folded into the broader, year-end consolidated rate change effective **January 1, 2026**. The advice letter also revises a large suite of preliminary statements, covering accounts such as: - **Base Revenue Requirement Balancing Account** (the core true-up account for base GRC revenue); - **Portfolio Allocation Balancing Account** (the balancing account that ensures SCE properly allocates generation base costs to customers); - **Energy Resource Recovery Account** (the main fuel and purchased power true-up account); - **Vegetation Management Balancing Account** (a two-way balancing account that ensures SCE spends – and recovers – vegetation management costs appropriately); - **Risk Management Balancing Account** (the account that manages SCE’s wildfire liability self-insurance program); - **New System Generation Balancing Account** (the balancing account that recovers costs for SCE’s owned generation/storage fleet added in recent GRC cycles); and - **Pension Costs Balancing Account** (the account that ensures SCE only recovers the correct level of pension-related expenses)... ...to incorporate the new 2026 revenue requirement and updated uncollectibles factor. **INSTANT ANALYSIS**: This is a straightforward 2026 Post-Test Year update that raises bundled rates modestly based on attrition mechanics adopted in the 2025 GRC. Most of the movement comes from the Consumer Price Index-based O&M escalation and an updated uncollectibles factor, partially offset by wildfire self-insurance adjustments and smaller accounting corrections tied to the Long Beach property sale and Creek Fire reimbursements. Below are illustrative rate changes anticipated by this filing. | Bundled Average Rates (¢/kWh) | | | | | | --------------------------------- | ------------- | --------------- | -------------- | -------- | | Customer Group | Current Rates | Proposed Change | Proposed Rates | % Change | | Residential | 35.3 | 0.91 | 36.2 | 2.6% | | Lighting – Small and Medium Power | 32.2 | 0.78 | 33.0 | 2.4% | | Large Power | 21.3 | 0.44 | 21.7 | 2.1% | | Agricultural & Pumping | 25.4 | 0.57 | 26.0 | 2.3% | | Street & Area Lighting | 36.1 | 0.46 | 36.5 | 1.3% | | Standby | 18.0 | 0.29 | 18.3 | 1.6% | | **Total** | 30.2 | 0.72 | 30.9 | 2.4% | | Residential Bill Impact ($/Month) | | | | | | | | | --------------------------------- | - | ------- | - | --------------- | - | -------- | -------- | | Description | | Current | | Proposed Change | | Proposed | % Change | | Non-CARE residential bill | $ | 193.23 | $ | 4.94 | $ | 198.17 | 2.6% | | CARE residential bill | $ | 122.31 | $ | 3.12 | $ | 125.44 | 2.6% | --- ### TRANSPORTATION ELECTRIFICATION SCE filed Advice Letter 5676-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to implement the authorized 2026 revenue requirements for its full [Charge Ready](https://www.sce.com/business/smart-energy-solar/charge-ready?ref=calregulatory.com) portfolio (Phase 1, Phase 2, the Schools and Parks pilots) and for its broader Transportation Electrification programs. All amounts will be rolled into SCE’s next consolidated revenue requirement and rate change on **January 1, 2026**. The filing recaps the Commission decisions that created or expanded each program, details the associated balancing accounts, and presents SCE’s 2026 revenue requirements for each component using the currently authorized **7.66%** rate of return pending a forthcoming Cost of Capital [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) (see our summary of that item [here](https://www.calregulatory.com/monday-aggregate-cost-of-capital-affordability-senate-bill-1221/)). - Charge Ready Phase 1 continues recovery of up to **$44 million** in authorized early-stage charging infrastructure and ME&O spending. - Phase 2 carries forward the large-scale **$436 million** Charge Ready 2 deployment. - The Schools and Parks pilots reflect statutory programs under Assembly Bills 1082/1083\. The Transportation Electrification Portfolio includes both "Priority Review Projects" approved in a 2018 decision ([D.18-01-024](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M204/K670/204670548.PDF?ref=calregulatory.com)) and the Medium/Heavy-Duty infrastructure program authorized in a separate 2018 decision ([D.18-05-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M215/K783/215783846.PDF?ref=calregulatory.com)). Across all categories, SCE provides detailed 2026 revenue-requirement line items (O&M, rebates, depreciation, taxes, and return) and states that final amounts will be recalculated if the CPUC's pending 2026 Cost of Capital PD adjusts the utility’s rate of return in time for January implementation. **INSTANT ANALYSIS**: This filing's significance lies in how much Transportation Electrification and Charge Ready infrastructure is now baked into SCE’s baseline distribution revenue requirement for 2026\. With all major charging programs rolling into January rates, this advice letter reflects how transportation electrification has become an embedded, predictable component of utility revenue needs rather than a series of standalone pilots. The only real variable is the Commission's [pending 2026 Cost of Capital PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com): - If the CPUC adopts a lower Return on Equity/Rate of Return, all these transportation electrification and Charge Ready components will be recalculated downward. - If not, SCE’s current Rate of Return (7.66%) holds. --- ### DEMAND RESPONSE SCE filed Advice Letter 5675-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to modify its [Capacity Bidding Program](https://www.sce.com/factsheet/CapacityBiddingProgram?ref=calregulatory.com) – Elect (CBP-E) by adding a new Direct Participation Option (DPO). This change is designed to give residential and non-residential customers a way to enroll directly with SCE, without going through a third-party aggregator or taking on the burdens of becoming a self-aggregator, so they can participate in CBP-E and satisfy the [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) (SGIP) requirement to join a qualified Demand-Response program. At present, SGIP customers who receive service through Community Choice Aggregators, Direct Access providers, or non-SCE Electric Service Providers have extremely limited options because the Capacity Bidding Program is restricted to bundled customers (and only one CBP-E aggregator accepts certain residential classes). SCE frames the Direct Participation Option as an additional pathway that removes enrollment bottlenecks and allows more customers awaiting SGIP incentives to participate in CBP-E. - Under the proposal, DPO customers would accept CBP-E tariff terms through a dedicated enrollment website, after which SCE (or an appointed Operator) would handle all administrative tasks (including registration, nominations, performance tracking, and settlement calculations). - Customers would not need to post financial deposits, operate within [APX MarketSuite](https://apx.com/power-scheduling-energy-accounting-services/?ref=calregulatory.com), or perform monthly nomination duties. - To maintain performance accountability, DPO participants would be subject to existing incentive and penalty rules, but SCE proposes capping both capacity incentive payments and penalties at 50%, with the retained portion offsetting program administration costs. - Baselines for DPO customers would remain individual rather than aggregated, and payments (or penalties) would be settled once per season, consolidated until they reach at least $10. SCE estimates approximately **$1 million** in DPO operational costs for 2026–2027, funded entirely through already-authorized CBP-E budgets and the retained 50% of participant incentives, which SCE argues keeps the option cost-neutral. **INSTANT ANALYSIS:** SCE’s proposal is a pressure-relief valve for a bottleneck the CPUC created when it tied SGIP eligibility to participation in a qualified Demand Response program: because most residential CCA/Direct Access customers have no viable CBP-E aggregator to enroll with, their SGIP projects are stuck. By adding a Direct Participation Option, SCE is stepping in as a de facto utility-run enrollment pathway that bypasses the thin aggregator market, allowing customers to meet SGIP requirements while adding incremental Demand Response capacity. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4622.JPG) ### SELF-GENERATION INCENTIVE PROGRAM (SGIP) SoCalGas filed Advice Letter 6562-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to identify and seek approval for new residential time-varying electric rates that qualify customers for the [SGIP](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com). Pursuant to CPUC decisions, residential SGIP participants must enroll in a Time-of-Use (TOU) rate with a summer peak beginning at or after 4 p.m. and a minimum peak-to-off-peak differential of 1.69, unless they are [CARE](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com) or [Medical Baseline customers](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/medical-baseline?ref=calregulatory.com) who lack an eligible rate meeting those requirements. The decisions also require SGIP Program Administrators to notify the Commission whenever new qualifying non-utility electric rates appear in their territories. SoCalGas reports that three such rates: - One from [Imperial Irrigation District](https://www.iid.com/?ref=calregulatory.com); and - Two from [Anaheim Public Utilities](https://www.anaheim.net/6099/Public-Utilities?ref=calregulatory.com)... ...now satisfy the required price differentials and timing criteria. Each offers a peak beginning at 4 p.m. and meets or exceeds the 1.69 price-ratio threshold. SoCalGas therefore requests that the CPUC approve these rates as eligible for SGIP enrollment. **INSTANT ANALYSIS:** This housekeeping item expands the list of SGIP-qualifying TOU rates in SoCalGas territory to include the Imperial Irrigation District and Anaheim Public Utilities’ residential schedules, all of which meet the 4 p.m. peak requirement and exceed the 1.69 price-ratio threshold. The practical effect is that SGIP administrators and developers now have clearer enrollment pathways for customers served by these municipal providers. ### November 20, 2025 CPUC Voting Meeting Results URL: https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-results/ Last updated: 2025-11-25T05:25:52.000Z Below is a summary of the Commission's [Thursday, November 20 voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K499/586499801.pdf?ref=calregulatory.com) results. Today's meeting offered a cross-section of the state’s most pressing energy transitions: - The end of PG&E’s zonal electrification pilot; - The launch of a deeper mobilehome-park electrification initiative; - New energy-efficiency market-transformation directives; - A reset of the Avoided Cost Calculator cycle; and - Another round of mid-term reliability procurement. The Commission also approved a significant crude-oil pipeline rate increase and pushed several items to December. The meeting blended procedural cleanup work with long-term policy direction across gas, electric, and Distributed Energy Resource portfolios. --- ### PG&E ZONAL ELECTRIFICATION at CALIFORNIA STATE UNIVERSITY MONTEREY BAY A Commission [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K799/587799131.PDF?ref=calregulatory.com) dismisses PG&E’s [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M496/K451/496451495.PDF?ref=calregulatory.com) for [a zonal electrification pilot at CSU Monterey Bay](https://csumb.edu/news/news-listing/east-campus-may-become-californias-largest-electrification-project/?ref=calregulatory.com) after PG&E exercised its contractual option to terminate the project. In requesting termination, PG&E cited pipeline safety concerns and an incompatible regulatory timeline. Originally framed as a model for transitioning entire zones from gas to all-electric service, the project shrank over time (from 1,200 dwellings and eight miles of pipeline to roughly 400 dwellings and four to five miles) and ultimately became infeasible once PG&E concluded that remediation of the aging gas system could not wait for Commission approval. Several parties opposed the withdrawal, arguing that PG&E may be attempting to avoid an unfavorable outcome and that the case raises broader policy questions about ratepayer-funded electrification, stranded costs, and gas system transition. While granting PG&E’s request to terminate, the decision preserves the value of the two-year record by directing PG&E to prepare a lessons-learned report summarizing policy, cost, ratepayer, and operational findings. PG&E must file the report in the state’s ongoing [Building Decarbonization](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M264/K629/264629773.PDF?ref=calregulatory.com) and [Long-Term Gas Planning](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com) rulemakings, where it may inform future proposals. **INSTANT ANALYSIS:** Thursday's decision avoids resolving the core policy tension (whether gas ratepayers should finance electrification that retires gas assets) but preserves the full evidentiary record and forces PG&E to translate its experience into a formal report. Ideas explored in this case will reappear in other procedural venues, even though the pilot itself collapsed. --- ### MOBILEHOME ELECTRIFICATION PILOT The CPUC adopted a [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K925/587925783.PDF?ref=calregulatory.com) establishing a joint CPUC–California Energy Commission Mobilehome Park Electrification Initiative aimed at fully electrifying selected mobilehome parks and retiring their natural-gas infrastructure. The decision does not approve any new ratepayer funding and actually **declines** staff's proposal to use **$50 million** in Public Purpose Program funding. "This approach," the decision states, "supports the importance of finding alternatives to ratepayer funding, to avoid adding additional upward pressure on electric rates, which can discourage customers from pursuing electrification." Below are some additional details. - The initiative builds on an existing [Mobilehome Park Utility Conversion Program](https://www.cpuc.ca.gov/regulatory-services/safety/mhp/mobilehome-park-utility-upgrade-program?ref=calregulatory.com), which already converts submetered systems to direct utility service, but expands the scope to include full behind-the-meter electrification for every participating home. - Under the pilot, selected parks served by PG&E, SCE, and SDG&E will receive no-cost replacement of all major gas appliances with high-efficiency electric technologies, along with any necessary in-home remediation such as rewiring, panel upgrades, and code-compliant repairs. - The program is designed to help the CPUC better understand the technical, legal, and policy implications of large-scale electrification in manufactured-home communities, while also ensuring tenant protections, bill-impact safeguards, and coordinated termination of gas service. The decision directs electric and gas utilities to collaborate with the CEC’s [Equitable Building Decarbonization](https://www.energy.ca.gov/programs-and-topics/programs/equitable-building-decarbonization-program?ref=calregulatory.com) program on infrastructure needs, funding alignment, and sequencing of work, and requires participating park owners to record deed restrictions prohibiting new gas infrastructure for at least 20 years. **INSTANT ANALYSIS:** This decision transforms a narrow infrastructure-upgrade program into a controlled trial of full gas retirement in mobilehome parks, pairing utility-installed 200-amp electric service with CEC-funded appliance replacements and in-home remediation, at no cost to residents. By requiring deed restrictions that bar new gas lines for 20 years and refusing to authorize new ratepayer spending, the CPUC is testing whether deep electrification retrofits in low-income manufactured housing can be executed affordably and at scale. The outcome will directly inform how California approaches future gas phase-outs, cost recovery, and transition planning in communities that are typically the hardest to modernize. --- ### ENERGY EFFICIENCY A decision adopted Thursday approves the [California Market Administrator](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K575/586575760.PDF?ref=calregulatory.com) (CalMTA)'s first two statewide market-transformation initiatives: - Full approval for a [room heat-pump initiative](https://calmta.org/room-heat-pumps/?ref=calregulatory.com); and - Conditional approval for an [induction-cooking initiative](https://calmta.org/resourcereport/induction-cooking-mti-plan/?ref=calregulatory.com), which must be narrowed to 120-volt products and resubmitted via a Tier 2 advice letter by **April 3, 2026**. Together with CalMTA’s administration, operations, and evaluation activities, the decision authorizes a **$114.6 million** budget for 2026–2031, aligning the market-transformation initiative cycle with the next statewide energy-efficiency portfolio cycle. Notably, the Commission withdrew a[ competing proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K301/581301683.PDF?ref=calregulatory.com) (alternate proposed decision, or "APD") issued by **Commissioner Matt Baker**. Had it been adopted, Commissioner Baker's APD would've authorized the room heat-pump initiative while denying the induction-cooking initiative. Accordingly, the budget authorized by Baker's APD was about half the amount authorized in today's final decision. **INSTANT ANALYSIS**: This decision gives CalMTA enough runway to move from a multi-year setup into actual market deployment, but with a clear note of caution. The Commission is comfortable with room heat pumps but remains uneasy about the broader induction strategy. Thursday's decision directs CalMTA to narrow the that strategy, update related assumptions, and stay within a tighter budget. While the budget authorization shows that market transformation is still a live priority under state law (even under constant affordability pressures), the Commission is drawing firmer boundaries around risk, bill impacts, and methodological rigor. --- ### AVOIDED COST CALCULATOR The CPUC adopted a decision revising the CPUC’s biennial [Avoided Cost Calculator](https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight?ref=calregulatory.com) (ACC) update process while substantially increasing the annual consultant budget that supports ACC modeling. The decision concludes that the existing ACC schedule (characterized by lengthy evidentiary hearings, multiple testimony rounds, and a prolonged resolution sequence) has produced delays and is no longer compatible with the growing complexity of Distributed Energy Resources cost-effectiveness work. To realign timing with the [Integrated Resource Planning](https://www.cpuc.ca.gov/irp/?ref=calregulatory.com) cycle, the decision replaces reliance on the IRP Preferred System Plan with the most recently adopted IRP Transmission Planning Process base-case portfolio, which – in the CPUC's view – offers more predictable availability for the 2026 update. The decision increases the ACC update budget from $350,000 to **$1.2 million** per year, citing historically insufficient funding, inflation, the growing modeling burden (including integration of transmission and distribution avoided-cost studies), and the need for a durable funding baseline. **INSTANT ANALYSIS:** The Commission is taking steps to adapt to the rapidity of new energy paradigms e.g., restructuring the ACC update cycle around whichever Integrated Resource Planning portfolio becomes available first, even if that means relying on the Transmission Planning Process base case instead of the Preferred System Plan. - The budget jump to $1.2 million/year, recovered from ratepayers, reflects how large and complex the ACC has become (especially with transmission, distribution, and Net Billing export modeling now baked into the workload). - The decision acknowledges stakeholder worries about compressed timelines but holds firm: the ACC must be updated faster, and the resources must match the task. Going forward, ACC revisions may arrive on a more predictable cadence, with modeling updates delivered earlier in each cycle, with fewer slowdowns between portfolio adoption and ACC deployment. --- ### COST-EFFECTIVENESS TOOLS for DERs The CPUC adopted a [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M587/K924/587924964.PDF?ref=calregulatory.com) denying the [California Efficiency + Demand Management Council](https://cedmc.org/?ref=calregulatory.com)’s [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M563/K203/563203670.PDF?ref=calregulatory.com) to modify a 2019 decision ([D.19-05-019](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M293/K833/293833387.PDF?ref=calregulatory.com)), which established the Total Resource Cost ([TRC](https://eecoordinator.info/wp-content/uploads/2021/08/2019%5FSEEC%5FPresentation%5FTRC-for-the-Rest-of-Us-Breaking-Down-Cost-Effectiveness.pdf?ref=calregulatory.com)) test as the Commission’s primary cost-effectiveness tool for Distributed Energy Resources. The Council sought to replace TRC with a "Program Administrator Cost" test solely for allocating DER program budgets, arguing that recent policy developments and analytical concerns justified the shift. Thursday's decision finds the petition procedurally deficient and untimely. **INSTANT ANALYSIS**: The key takeaway here is that TRC remains the CPUC's primary DER cost-effectiveness test, and attempts to reframe DER budget allocation standards will only be entertained within live proceedings. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4606.JPG) ### MID-TERM RELIABILITY The CPUC adopted Resolution E-5428, which approves eight new mid-term reliability contracts and one amendment submitted by SCE under its 2025 procurement plan. The portfolio includes solar-plus-storage projects in Kern and Riverside Counties and a solar project in Arizona, totaling about 498 megawatts, plus a 75-MW amendment to the [Gateway battery facility in San Diego](https://www.powermag.com/worlds-largest-for-now-battery-storage-project-online-in-california/?ref=calregulatory.com) that extends its delivery date to 2027 following a 2024 thermal event investigated by the CPUC and the Environmental Protection Agency. - Collectively, these contracts supply roughly 151 MW of effective capacity toward SCE’s obligations under the CPUC's original "mid-term reliability" decision ([D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com)) and a supplemental procurement decision ([D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com)). The solar agreements also contribute to SCE’s Diablo Canyon Replacement and Renewable Portfolio Standard targets. - Resolution E-5428 finds the contracts consistent with SCE’s 2024 RPS Procurement Plan, competitively priced, and procured through a transparent, least-cost/best-fit process verified by independent evaluator Sedway Consulting. Costs will be recovered through the Portfolio Allocation Balancing Account (the 2021 sub-account for solar and 2023 for storage) with all ratepayers sharing benefits and costs. Contract prices and cost data are confidential, pursuant to the Public Utilities Code. **Instant Analysis:** By approving SCE’s solar-plus-storage portfolio and extending the [Gateway BESS](https://en.wikipedia.org/wiki/Gateway%5FEnergy%5FStorage?ref=calregulatory.com) contract after a [2024 fire](https://response.epa.gov/site/site%5Fprofile.aspx?site%5Fid=16485&ref=calregulatory.com), the Commission is demonstrating some flexibility toward operational realities. The confidential pricing underscores a cautious stance toward market sensitivity, which is par for the course on these types of agreements. --- ### **CRUDE OIL TRANSPORTATION** A [decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K610/584610997.PDF?ref=calregulatory.com) adopted Thursday authorizes Crimson California Pipeline, LP to raise crude-oil transportation rates on its Southern System by 26.35%, retroactive to August 1, 2024, with interest. The decision finds the increase just and reasonable after Crimson removed parent-company [CorEnergy](https://corenergy.reit/strategy/?ref=calregulatory.com)'s finances from its filing and adopted a 60/40 equity-to-debt ratio, 12% cost of debt, and 15% return on equity, consistent with [*Bluefield* and *Hope* standards for financial soundness](https://scholarworks.law.ubalt.edu/cgi/viewcontent.cgi?article=1274&context=lf&ref=calregulatory.com). According to the decision, a smaller 10% increase would have left Crimson operating at a loss. **Instant Analysis**: By approving a 26.35% increase (more than double the statutory 10% self-implementation cap) the Commission is telegraphing that maintaining safe, solvent operations outweighs short-term rate stability. The decision also establishes an apparent precedent: parent or affiliate financials cannot be used to inflate cost recovery. But once excluded, the CPUC will still accommodate reasonable equity returns to prevent underinvestment or safety degradation. ### DELAYED ACTION Note that the Commission delayed action on the following items until **December 4**: - **Undergrounding of Electrical Equipment**: [Draft Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) which updates the CPUC’s [Senate Bill 884 program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com) overseeing the expedited undergrounding of electric distribution lines by large utilities. - **Self-Generation Incentive Program (SGI)**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M577/K291/577291720.PDF?ref=calregulatory.com) that closes out the ratepayer-funded [SGIP](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) and establishes procedures for the return of unspent funds to customers while launching a "Greenhouse Gas Reduction Fund." - Bioenergy Market Adjusting Tariff (BioMAT): A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denying a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [BioMAT](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) program through December 31, 2025. - **Union Island Pipeline**: A [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denying a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. ### Parties React to Safety Policy Division's Evaluation in the SoCalGas/SDG&E RAMP Proceeding URL: https://www.calregulatory.com/parties-react-to-safety-policy-divisions-evaluation-in-the-socalgas-sdg-e-ramp-proceeding/ Last updated: 2025-12-01T17:30:18.000Z The following summary synthesizes all major stakeholder responses to the Sempra Utilities' (SoCalGas/SDG&E) 2025 Risk Assessment and Mitigation Phase (RAMP) filings, including the utilities’ own comments and those submitted by TURN, the [Mussey Grade Road Alliance](https://www.guidestar.org/profile/27-1277756?ref=calregulatory.com) (MGRA), [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com), the Indicated Shippers, and the [Small Business Utility Advocates](https://www.utilityadvocates.org/?ref=calregulatory.com) (SBUA). Driven by an [August 11 scoping memo](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M575/K458/575458324.PDF?ref=calregulatory.com) and Safety Policy Division (SPD) [evaluation](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K447/583447042.PDF?ref=calregulatory.com), these comments reveal how SoCalGas/SDG&E's risk models, tranching methodologies, mitigation-selection logic, and cost-benefit analyses are being scrutinized and challenged across the proceeding. (*For reference, SoCalGas's application is available* [*here*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363588.PDF?ref=calregulatory.com)*; SDG&E's application is available* [*here*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K243/566243429.PDF?ref=calregulatory.com)*.*) --- ### **SoCalGas/SDG&E** The Sempra Utilities [defend](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K371/587371284.PDF?ref=calregulatory.com) the overall structure and compliance of their 2025 RAMP filings, emphasizing that their risk models, scaling methodology, and alternative [Homogeneous Tranching Method](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/safety-policy-division/meeting-documents/tranching-whitepaper%5F11012024%5Ffinal.pdf?ref=calregulatory.com) (HTM) are aligned with the CPUC’s Risk-Based Decision-Making Framework and reflect meaningful improvements in data quality, model sophistication, and wildfire/PSPS risk evaluation. The utilities express willingness to adopt many of the CPUC [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com)’s recommended refinements, such as: - Clarifying cost-benefit ratio (CBR) calculations; - Improving documentation; - Increasing tranching transparency; - Disaggregating risk categories; and - Better aligning mitigation plans with risk outputs... ...while maintaining that their filings already meet regulatory requirements and appropriately prioritize high-consequence events. They highlight enhancements such as 24-hour unsuppressed fire modeling, improved physics-based probability-of-failure modeling, and more granular risk segmentation, and commit to integrating additional refinements into their upcoming Test-Year 2028 General Rate Case. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/iterograph_Tue-Nov-11-2025.png) Meanwhile, every intervenor argues that substantial methodological, transparency, and analytical deficiencies remain. The intervenors identify common themes: - Unexplained changes in risk scores; - Insufficient justification for the Sempra Utilities' risk-scaling choices; - Opaque mitigation-selection logic; - Over-segmentation and misalignment in SDG&E’s wildfire and Public Safety Power Shutoff tranching; and - Inconsistent or incomplete alternatives analyses. ### INDICATED SHIPPERS The Indicated Shippers [concentrate](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K054/588054074.PDF?ref=calregulatory.com) on SoCalGas’s gas-side modeling, arguing that SoCalGas provides no adequate justification for drastic increases in **LoRE** (Likelihood of Risk Event)/**CoRE** (Consequence of Risk Event) values compared to the 2021 RAMP, and that risk-averse scaling can transform weak mitigations into apparently strong ones. The Shippers strongly endorse SPD’s recommendation to require unscaled cost-benefit ratios and warn against ratepayer commitments to high-cost mitigations with unscaled cost-benefit ratios below 1.0\. For Underground Gas Storage, the Shippers press the Commission to require field-specific risk segmentation, especially for aging, higher-risk facilities, and to ensure mitigation plans reflect those differences. ### CAL ADVOCATES Cal Advocates [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K371/587371285.PDF?ref=calregulatory.com) SPD’s findings and adds concerns about the Sempra Utilities' inconsistencies in mileage, cost, and benefit assumptions in undergrounding and covered conductor comparisons. Cal Advocates calls for corrected analyses and resubmitted cost-benefit ratio calculations. Cal Advocates argues further that the utilities' modeling lacks adequate stability and documentation, and that meaningful decision-making requires more granular cost data and transparent explanations of how scaling and discount-rate assumptions influence mitigation choices. ### TURN TURN [focuses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781320.PDF?ref=calregulatory.com) on modeling weaknesses, especially in SDG&E’s wildfire and Public Safety Power Shutoff chapters. TURN argues that the utility’s revised tranching still fails to create genuinely homogeneous risk groupings, that historical risk reduction from past investments is omitted, and that SDG&E incorrectly ignores the mitigating effects of customer and facility backup power in PSPS consequences. TURN also warns that SDG&E’s fire simulations, without accounting for suppression, distort the risk landscape and potentially misguide mitigation spending. ### MUSSEY GRADE ROAD ALLIANCE MGRA [extends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K371/587371288.PDF?ref=calregulatory.com) TURN's critique by questioning the realism of SDG&E’s fire modeling, especially the 24-hour “unsuppressed burn” assumption that ignores Cal Fire’s operational success in containing the vast majority of fires. MGRA argues that this approach severely inflates the scale of potential wildfire consequences. MGRA also challenges SDG&E’s cost-benefit transparency, especially for grid-hardening programs where primary and secondary infrastructure cost and risk data are lumped together, making it impossible for stakeholders to evaluate the true trade-offs between undergrounding, covered conductor, and other mitigations. ### SMALL BUSINESS UTILITY ADVOCATES SBUA [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K371/587371279.PDF?ref=calregulatory.com) that convex scaling may inflate catastrophic risk and systematically bias the Sempra Utilities' modeling toward capital-heavy projects that impose disproportionate rate impacts on small commercial customers. SBUA highlights the lack of tranche-to-mitigation traceability, warning that SoCalGas/SDG&E do not clearly demonstrate how individual risk tranches map to spending decisions. SBUA supports further alternatives analysis (including vegetation management, non-infrastructure mitigations, and discrete Battery Electric Storage System safety risk modeling) and offer cautious support for the utilities' proposed [Homogeneous Tranching Method](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/safety-policy-division/meeting-documents/tranching-whitepaper%5F11012024%5Ffinal.pdf?ref=calregulatory.com) while acknowledging SPD’s findings that HTM still fails to produce consistently homogeneous tranches in wildfire modeling. --- **INSTANT ANALYSIS**: Collectively intervenors argue that the Sempra Utilities' risk modeling architecture remains too opaque, too volatile, and too dependent on mathematical transformations (especially convex scaling) to support confident, cost-effective mitigation planning. - While SoCalGas and SDG&E defend the integrity of their RAMP submissions and commit to iterative refinements, every intervenor identifies the same structural problems: unexplained LoRE/CoRE inflation, misaligned or over-segmented tranching, unrealistic wildfire consequence modeling, weak alternatives analysis, and mitigation portfolios that appear optimized for scaled results rather than underlying, verifiable risk reductions. - Practically speaking, the RAMP-to-General Rate Case pipeline may not yet be reliable as a foundation for billions in wildfire, PSPS, and gas-system spending. Stakeholders are effectively telling the CPUC: do not carry these models forward without correction. - The CPUC must now either require the utilities to rerun key analyses with transparent, replicable assumptions (including unscaled CBRs and field-specific risk segmentation) or risk anchoring the 2028 GRC in models that (according to intervenors) obscure tradeoffs, inflate benefits, and make independent verification nearly impossible. ### WEDNESDAY AGGREGATE: Wildfires; Cost of Capital; SoCalGas Microgrid Optional Tariff URL: https://www.calregulatory.com/wednesday-aggregate-2/ Last updated: 2025-11-30T04:49:47.000Z The CPUC's mid-November docket flow is converging around wildfire liability, risk signals, and microgrid market boundaries. - PG&E is testing the full-strength presumption of prudence under Assembly Bill 1054 with a nearly **$2 billion** recovery request. - SCE continues to refine operational practices amid tightening weather patterns for its Public Safety Power Shutoffs. - The investor-owned utilities are mounting a coordinated Cost of Capital push. - SoCalGas seeks fresh debt authority. - The battle lines over utility participation in distributed markets sharpen in SoCalGas's Microgrid Optional Tariff proceeding. Additionally, please see our [November 18 electricity rate update](https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/) for an early look at **January 1, 2026** rates. --- ### WILDFIRES PG&E filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323960.PDF?ref=calregulatory.com) seeking review and recovery of costs from the [2019 Kincade](https://en.wikipedia.org/wiki/Kincade%5FFire?ref=calregulatory.com) and [2021 Dixie Fires](https://en.wikipedia.org/wiki/Dixie%5FFire?ref=calregulatory.com). PG&E argues that: - Both ignitions qualify as “covered wildfires"; - It held valid safety certifications at the time... ...and consequently deserves [Assembly Bill 1054](https://www.singletonschreiber.com/theblog/how-does-ab-1054-work-blog?ref=calregulatory.com)’s presumption of prudence while requesting authorization to recover **$1.59 billion** in net Wildfire Event Mitigation Account (WEMA)-recorded claims, litigation, and financing costs. PG&E requests an additional **$314 million** in Catastrophic Event Memorandum Account (CEMA)-recorded restoration costs, with balances to be updated in rebuttal. PG&E asserts that it prudently designed, maintained, and operated the involved facilities, that no imprudence contributed to either ignition, and that extreme winds, drought, fuel loads, and topography exacerbated the fires’ severity. PG&E highlights substantial reimbursements already received from the Wildfire Fund and anticipates seeking securitization for approved WEMA-electric costs later. PG&E filed an [accompanying motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K231/587231676.PDF?ref=calregulatory.com) to shorten protest deadlines, requesting protests by **December 2** and replies by **December 8**. **INSTANT ANALYSIS**: This is the first catastrophic-wildfire cost-recovery case filed under AB 1054 in which PG&E enters with a full statutory presumption of prudence, making the central fight not about ignition facts but about whether any party can raise “serious doubt." PG&E’s filing is aggressive and clearly coordinated with the Wildfire Fund Administrator. The scale of requested recovery (over $1.9 billion combined across WEMA and CEMA) means this proceeding will set a precedent for how AB 1054 is applied when safety certificates are in place, with major implications for investor confidence, future wildfire-cost securitizations, and statewide affordability trajectories. --- ### PUBLIC SAFETY POWER SHUTOFFS SCE filed a [post-event report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M588/K050/588050432.PDF?ref=calregulatory.com) that describes a Public Safety Power Shutoff that occurred from October 25 through 30, 2025, when rapidly intensifying Santa Ana winds, extremely dry conditions, and elevated [Fire Potential Index](https://research.noaa.gov/an-experimental-noaa-tool-that-predicts-hourly-wildfire-hazards-across-the-u-s/?ref=calregulatory.com) values led SCE to deenergize 16 distribution circuits. These circuits spanned Los Angeles, Riverside, San Bernardino, and Ventura Counties and the PSPS affected **2,640** customers. SCE activated its [Emergency Operations Center](https://download.edison.com/405/files/202210/08%20EOC%20Tour%20Slide%20Deck.pdf?Signature=oGixOiLQkrP1dcLqiTtvcgxMsPQ%3D&Expires=1771781740&AWSAccessKeyId=AKIATACLJRQCT2IBV7MN&versionId=8bNWaHnrKnXby7wTjr3kieFmVF2AqSBF&response-content-disposition=attachment&ref=calregulatory.com), issued more than **1.8 million** multilingual notifications, and conducted pre-event patrols and real-time monitoring as wind gusts approached 50 to 60 mph in some areas. No wind-related damage was found, and all service was restored early on October 30\. Using its PSPS risk-benefit tool, which showed wildfire risk exceeding PSPS risk on every affected circuit, SCE justified the shutoffs as necessary, though it acknowledged delays and gaps in some customer notifications and outlined corrective steps **INSTANT ANALYSIS:** This PSPS was a tight, weather-driven activation triggered by high-confidence Santa Ana conditions, elevated Fire Potential Index values, and gusts approaching 60 mph. SCE's risk modeling showed wildfire consequences far outweighing PSPS harms on every affected circuit, and patrols found no wind-related damage, with full restoration achieved by October 30\. The operational execution was clean, but the familiar weak spot reappeared: notification gaps, driven by late-breaking circuit additions and internal campaign-authorization lags. --- ### COST of CAPITAL On November 13, representatives from PG&E, SCE, SDG&E, and SoCalGas [held a joint WebEx meeting](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K328/587328363.PDF?ref=calregulatory.com) with advisors to CPUC **President Alice Reynolds** and **Commissioner Darcie Houck** to discuss their 2026 Cost of Capital applications. The utilities emphasized that a timely CPUC decision is critical to ensure new rates take effect by **January 1, 2026**. They argued that a higher, just-and-reasonable cost of capital is necessary given what they described as worsening investor risk conditions in California. This included: - Wildfire-related liability and recovery uncertainty; - Elevated undercollections; - Regulatory lag; and - Increasing disallowances. The utilities noted that nationwide interest rates and average authorized ROEs have risen since the last full Cost of Capital proceeding, while California’s risk environment has intensified. They pointed to recent wildfires, ongoing uncertainty even after [Senate Bill 254](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202520260SB254&ref=calregulatory.com), and credit pressures such as [S&P’s downgrade of SCE. ](https://www.spglobal.com/ratings/en/regulatory/article/-/view/type/HTML/id/3442545?ref=calregulatory.com)SoCalGas also highlighted heightened regulatory and financial risk for gas utilities, including delayed cost recovery and higher borrowing costs. **INSTANT ANALYSIS**: This is a push by all four IOUs to demonstrate that California’s risk profile has worsened, and therefore their requested ROEs should stand. The arguments are an attempt to pre-empt the CPUC’s inclination toward continuity and to blunt intervenor criticism by packaging the risk story as statewide affordability and reliability concerns rather than shareholder protections. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/iterograph_Tue-Oct-28-2025--10-.png) ### UTILITY FINANCES **Administrative Law Judge Gerstle** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472615.PDF?ref=calregulatory.com) that, if adopted, would authorize SoCalGas to issue up to **$3.3 billion** in new long-term debt to: - Fund capital investments; - Reimburse its treasury for prior spending; and - Maintain flexibility for contingencies... ...while also permitting a broad range of financing instruments including first mortgage bonds, debentures, foreign debt, long-term loans, and accounts-receivable financing. The PD allows SoCalGas to use debt enhancements and hedging tools (e.g., call and put options, swaps, and Treasury locks) under existing CPUC rules to reduce financing costs for ratepayers. The PD stresses that approval to issue debt does not constitute approval of any project or guarantee cost recovery, which will be reviewed in future rate proceedings. Comments are due **December 2**. The CPUC is scheduled to consider this item on **December 18**. **INSTANT ANALYSIS:** This is a straightforward financing authorization with no surprises and no opposition. The $3.3 billion authority largely aligns with precedent and preserves standard utility flexibility across instruments, enhancements, and hedging tools. --- ### MICROGRIDS Cal Advocates filed [notice of a November 7 ex parte meeting](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K781/587781321.PDF?ref=calregulatory.com) in the proceeding where SoCalGas [requests a Microgrid Optional Tariff (MOT)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M564/K309/564309571.PDF?ref=calregulatory.com). Cal Advocates met with advisors from the offices of **President Reynolds** and **Commissioner Baker** to outline their opposition to SoCalGas’s proposal. - Cal Advocates argued that supplemental testimony served by SoCalGas fails to remedy deficiencies identified in the scoping memo – the supplement repeats material from the original application instead of providing required detail on legal compliance, ratepayer protections, or competition impacts. - Cal Advocates argued further that the MOT would improperly leverage ratepayer-funded utility advantages to enter unregulated commercial microgrid markets, while shifting costs and suppressing competition. Last, Cal Advocates argued that SoCalGas’s claimed precedents (its [Distributed Energy Resources Tariff](https://www.socalgas.com/business/power-generation/ders-tariff?ref=calregulatory.com) and [Hydrogen Innovation Experience](https://www.socalgas.com/sustainability/hydrogen/h2home?ref=calregulatory.com)) are inapplicable; the former had strict statutory safeguards not present in the MOT proposal, and the latter was a small, shareholder-funded demo project (unlike the large commercial projects anticipated under the MOT). **INSTANT ANALYSIS**: The tone of the notice suggests that Cal Advocates may be seeking full dismissal of SoCalGas's application, framing it as an inappropriate attempt by a monopoly gas utility to enter a competitive microgrid market using structural advantages funded by ratepayers. The rebuttal of SoCalGas’s claimed precedents (DERS Tariff, Hydrogen Innovation Experience) also presages arguments that other parties may adopt e.g., that SoCalGas is overstating historical Commission support for utility participation in distributed energy markets. ### MID-WEEK NEWS CODEX: California Climate Law; Valar Atomics; Octopus URL: https://www.calregulatory.com/weekend-news-codex-3/ Last updated: 2025-11-25T06:54:06.000Z - **Business Groups Petition U.S. Supreme Court to Pause California Climate Law:** "The U.S. Chamber of Commerce and other industry groups filed an emergency appeal on November 15, 2025, requesting the U.S. Supreme Court to put California’s climate reporting laws on hold while [legal challenges](https://www.californiaenergytransition.com/p/business-groups-challenge-california?ref=calregulatory.com) continue, the AP [reported](https://apnews.com/article/climate-change-california-newsom-supreme-court-559597f5196116d567ad234cc5397b11?ref=calregulatory.com). The laws take effect January 1, 2026\. SB 253, known as the Climate Corporate Data Accountability Act, requires companies with revenues of more than $1 billion to report their greenhouse gas emissions related to both operations and their supply chain. SB 261, known as the Climate-Related Financial Risk Act, requires companies with annual revenue of more than $500 million and that do business in California to disclose publicly the climate-related financial risks to their company and how they will address them. (see [Climate Reporting Laws: Comparison of Key Provisions](https://www.californiaenergytransition.com/p/climate-reporting-laws-comparison?ref=calregulatory.com).)" [ **CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/business-groups-petition-scotus-to?ref=calregulatory.com) - **California Energy Price Data for October 2025:** "Gasoline and diesel price levels showed minor effects in October from the October 3 El Segundo Refinery Fire, with overall average prices in California largely stable throughout the month but with some moderate increases in some regions. The primary price effect was seen in the spread between prices in the state and in the rest of the country, which grew by 11 cents on average from September as prices in the other states (with the exception of some prices in the Midwest as the result of refinery disruption) more directly reflected softening crude prices. Southern California, however, has experienced a recent rise in prices due to ongoing refinery maintenance related to the mandated changeover in fuel formulations." [**CENTER FOR JOBS & THE ECONOMY**](https://centerforjobs.org/ca/energy-reports/october-energy-price-data-for-september-2025-2?ref=calregulatory.com) - **El Segundo-Based Valar Atomics Splits the Atom** > Today, Valar Atomics became the first startup in history to split the atom. > > Announcing Project Nova, a series of zero power critical tests on Valar Atomics' Nova Core in collaboration with Los Alamos NCERC and NNSS. > > Nova went critical for the first time this morning at 11:45am. [pic.twitter.com/EanSIeaAtS](https://t.co/EanSIeaAtS?ref=calregulatory.com) > > — Isaiah Taylor - making nuclear reactors (@isaiah\_p\_taylor) [November 17, 2025](https://twitter.com/isaiah%5Fp%5Ftaylor/status/1990535382438719825?ref%5Fsrc=twsrc%5Etfw&ref=calregulatory.com) - **New PG&E Electrification Impact Study – Smart Planning Can Lower Long-Term Costs**: "The two major findings: electrification will require significant new investment, and, if managed well, it can actually make the grid more affordable to operate. PG&E modeled three scenarios to capture different futures. The Base Scenario used current planning practices and customer behaviors. The Equity Scenario expanded electrification in disadvantaged, low-income, and Tribal communities to match their share of the population, resulting in higher overall adoption of DER and electrification technologies. The Enhanced Demand Flexibility Scenario added load management that shifts or reduces peaks at times and places that matter most for the grid. Across these cases, total distribution system investment needs through 2040 ranged from $23B-$31B. Compared to the Base Scenario, the Enhanced Demand Flexibility Scenario achieved an estimated savings of about $1.8 billion, showing how well-targeted flexibility can meaningfully reduce grid costs." [**E3**](https://www.ethree.com/pge-eis/?ref=calregulatory.com) - **Octopus Extends its Tentacles into America**: "In the near future, Octopus Shift is also going to empower customers to manage their devices against a time-of-use rate they might be on. It’s not just saving money with a once-a-month payment for capacity when a demand response event gets called, but it’s also helping you save money every single day by making sure your EV is charging during the off-peak period or pre-cooling your home during the off-peak period. " [**VOLTS**](https://www.volts.wtf/p/octopus-extends-its-tentacles-into?ref=calregulatory.com) - **Power Behind the Redwood Curtain – A History of Electric Transmission and Natural Gas Infrastructure in Humboldt County:** "While some investments have been made in Humboldt County’s energy infrastructure in the six decades following the post-war buildout, they have focused primarily on maintaining the capacity and architecture of the existing system, hardening some system components, and – in the case of the nuclear unit of the Humboldt Bay power plant – decommissioning. There have been no large investments in expanding the capacity of the electric transmission and natural gas pipeline infrastructure serving the county since the mid 1960s." [**SCHATZ ENERGY RESEARCH CENTER**](https://schatzcenter.org/pubs/2025-Humboldt-Energy-Infrastructure-History.pdf?ref=calregulatory.com) - **Report – California Data Center Emissions Tripled from 2019 to 2023, Could Drive $266M in Annual Health Costs by 2028:** "In 2019, the average carbon intensity for electricity in California was just under half the national average. Yet even though California’s grid is among the cleanest in the country, the report finds that greenhouse gas emissions from data center operations are still climbing — primarily due to the grid’s continued reliance on natural gas plants as generating electricity from fossil fuels brings significant health impacts. Both the off-site natural gas plants and the onsite diesel generators — still the primary backup system for most data centers — emit nitrogen oxides and fine particulate matter that worsen respiratory and cardiovascular disease." [**NEXT10**](https://www.next10.org/press-releases/report-california-data-center-emissions-tripled-2019-2023-could-drive-266m-annual?ref=calregulatory.com) ([Full Report](https://www.next10.org/sites/default/files/2025-11/ai-environmental-public-health-costs.pdf?ref=calregulatory.com)) - **The Case for Virtual Power Plants:** "A July 29 California ISO demonstration showed the capability of VPPs. In the test, more than 100,000 participating systems were jointly dispatched during the 7 PM – 9 PM peak demand window. During that period, these behind-the-meter batteries sent an average of 539 megawatts back to the grid, accounting for about 1.9% of CAISO net peak during the test period..." [**INSTITUTE FOR ENERGY ECONOMICS and FINANCIAL ANALYSIS**](https://ieefa.org/resources/case-virtual-power-plants?ref=calregulatory.com) - **There is No Mystery Surcharge Driving Up California's Gasoline Costs:** "If refiners are earning exceptionally high profits in California, then why are they shutting down their operations in the state? You would think that companies would want to expand their production where they earn excessively high profits. The answer, of course, is that companies are not earning enormous profits in California." [**PACIFIC RESEARCH INSTITUTE**](https://www.pacificresearch.org/there-is-no-mystery-surcharge-driving-up-californias-gasoline-costs/?utm%5Fmedium=email&%5Fhsenc=p2ANqtz-959nrh-7%5F8qfYkXEU%5FLwf7F6Wggmw-FP1WNNu3Z0X2RM4GwKGMwX9GrmUH6VNUtoiSiWzUMzYAZrEPs8Z5bq1qbuRQLw&%5Fhsmi=390008614&utm%5Fcontent=390008614&utm%5Fsource=hs%5Femail) - **Trump Offshore Drilling Plan Focuses on Santa Barbara Coast:** "The Trump administration is proposing to offer six lease sales off the coast of California between 2027 and 2030 as part of its five-year offshore drilling plan, the *Washington Post* [reported](https://www.washingtonpost.com/climate-environment/2025/11/10/offshore-drilling-california-gulf-alaska/?ref=calregulatory.com). The proposed lease sales would primarily be offshore from Santa Barbara County, the *New York Times* [reported](https://www.nytimes.com/2025/11/11/climate/offshore-drilling-california-trump-newsom.html?ref=calregulatory.com), where Sable Offshore Corp. is looking to restart three drilling rigs in federal waters. Governor **Gavin Newsom** [said](https://thehill.com/policy/energy-environment/5601148-newsom-trump-california-offshore-drilling-plans/?ref=calregulatory.com) offshore oil drilling is 'overwhelmingly opposed by members of all political parties in the state of California.' He called it 'dead on arrival in California.'" [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/trump-offshore-drilling-plan-focuses?ref=calregulatory.com) ### January 1, 2026 Electric Rate Updates: PG&E, SCE, and SDG&E URL: https://www.calregulatory.com/january-1-2026-electric-rate-updates-pg-e-sce-and-sdg-e/ Last updated: 2025-12-18T16:16:23.000Z PG&E, SCE, and SDG&E each filed advice letters for preliminary implementation of their consolidated revenue requirement and rate changes on **January 1, 2026**. - These filings pull together every CPUC- and FERC-approved (or expected) cost change effective at the start of 2026. - The utilities will submit **final** consolidated ALs before January 1 that provide a more accurate projection of their rates. - Protests to all three submissions are due **December 8**. **INSTANT ANALYSIS**: Collectively, the filings show three very different rate paths heading into 2026\. PG&E’s early numbers place considerable upward pressure on Direct Access/Community Choice Aggregator customers; SCE’s updates lean toward broad relief across its portfolio, and SDG&E’s increases reflect a mix of wildfire costs, ERRA updates, and weaker sales. Of course these are preliminary estimates, as the utilities' late-December true-ups will determine how much of this picture holds. --- ### PG&E Preliminary Annual Electric True-Up PG&E filed [Advice Letter 7762-E](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7762-E.pdf?ref=calregulatory.com) as its preliminary Annual Electric True-Up and projects a **6.2%** decrease in the system-average bundled electric rate but a **23.2%** increase for Direct Access and Community Choice Aggregator customers. PG&E requests approval to recover approximately **$2.0 billion** in forecast December 31, 2025 undercollections across numerous balancing accounts, including [ERRA](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com)\-related accounts, the Portfolio Allocation Balancing Account, the Modified Transition Cost Balancing Account, and wildfire- and public-purpose-related accounts. The filing also incorporates revenue-requirement changes stemming from recent CPUC decisions (e.g., wildfire mitigation, non-wildfire insurance, transmission adjustments, and the 2022 Wildfire Mitigation and Catastrophic Events account) as well as pending requests related to: - Gas Advanced Metering Infrastructure; - Transmission Revenue Requirement Memorandum Account; and - Diablo Canyon extended operations. PG&E will submit a final true-up submission in late December reflecting all Commission decisions issued by mid-December and updated recorded balances (this presumably will include the[ pending Cost of Capital PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com); see our summary of that item [here](https://www.calregulatory.com/monday-aggregate-cost-of-capital-affordability-senate-bill-1221/)). PG&E's preliminary filing also explains how distribution, generation, [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com), public-purpose, wildfire, and non-bypassable charges will be allocated consistent with prior CPUC rulings. Below are illustrative rates. _This post is for paying subscribers only._ ### MONDAY AGGREGATE: Cost of Capital; Affordability; Senate Bill 1221 URL: https://www.calregulatory.com/monday-aggregate-cost-of-capital-affordability-senate-bill-1221/ Last updated: 2025-12-30T22:37:02.000Z Welcome to a jam-packed week of November regulatory activity. Today's slate has the CPUC navigating competing pressures through controlled incrementalism: - Maintaining financial stability for utilities while tightening evidentiary standards for cost recovery; - Expanding program flexibility without loosening oversight; and - Advancing legislative mandates through provisional first steps rather than comprehensive overhauls. The seven proposed decisions below span utility finance, wildfire costs, gas transition, and renewable procurement but share a common regulatory philosophy: the burden of proof sits with utilities, continuity trumps recalibration, and ratepayer protection means scrutinizing billions in requested recovery while preserving credit quality. ***Also, please see our preview of the November 20 CPUC voting meeting*** [***here***](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-preview/)***, which we will provide same-day analysis and results for on Thursday.*** --- ### COST of CAPITAL **Administrative Law Judge Lakey** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K323/587323962.PDF?ref=calregulatory.com) establishing the 2026 cost of capital for PG&E, SoCalGas, SCE, and SDG&E by setting each company’s authorized capital structure, long-term debt costs, preferred equity costs, return on equity, and overall rate of return. - The PD opts for continuity, rejecting nearly all utility and intervenor proposals to shift capital structures and instead maintains the existing equity ratios for each utility. For all four companies, the PD assigns a **52%** common-equity layer, modest preferred-equity shares, and the remainder as long-term debt. The PD then authorizes utility-specific embedded debt costs, adopts uncontested preferred-equity costs, and sets ROEs ranging from **9.73%** to **9.98%** across the utilities. - The PD navigates extensive debates over whether California’s wildfire exposure, clean-energy mandates, regulatory lag, and macroeconomic conditions warrant higher ROEs or increased equity layers. The utilities argued that rising capital needs, wildfire liability exposure, and cash-flow pressures justify upward adjustments. Intervenors countered that risks are not unique relative to national peers, that California utilities benefit from substantial statutory protections (including [Assembly Bill 1054](https://www.singletonschreiber.com/theblog/how-does-ab-1054-work-blog?ref=calregulatory.com)), and that high equity layers impose unnecessary costs on ratepayers. - After reviewing varying financial model results ([Discounted Cash Flow](https://www.investopedia.com/terms/d/dcf.asp?ref=calregulatory.com), [Capital Asset Pricing Model](https://www.investopedia.com/terms/c/capm.asp?ref=calregulatory.com), and [Risk Premium](https://en.wikipedia.org/wiki/Risk%5Fpremium?ref=calregulatory.com)), the PD gives the greatest weight to Discounted Cash Flow-based ranges and rejects the utilities’ use of [Empirical Capital Asset Pricing Model](https://test.shareok.org/items/9b284c0f-7a95-4bf7-bb7b-22f3fa3af6f6?ref=calregulatory.com) (ECAPM) and [After-Tax Weighted Average Cost of Capital](https://www.atlas.org/spaces/solve/after-tax-wacc-calculation-guide-7aFFDDJdm1wGQrnLyqataG?ref=calregulatory.com) (ATWACC) adders. _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: Interconnection Reform; Gas AMI; SoCalGas Rates URL: https://www.calregulatory.com/wednesday-aggregate/ Last updated: 2025-12-01T17:31:10.000Z Today's briefing blends macro-policy (Rule 21) with infrastructure accountability (gas AMI, the Sempra Utilities' Cost Allocation Proceeding), and notable housekeeping (transmission, Union Island, Diablo Canyon). Collectively these items provide a snapshot of alternating currents at the CPUC: electrification reform on one side and the unwinding of the legacy gas-system on the other. --- ### Rule 21 Distribution-Level Interconnection Parties recently filed reply comments in response to the [Commission rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M576/K867/576867418.PDF?ref=calregulatory.com) [whose aim](https://www.stoel.com/insights/publications/cpuc-opens-rulemaking-to-modernize-rule-21-interconnection-procedures?ref=calregulatory.com) is to modernize [Rule 21](https://www.cpuc.ca.gov/Rule21/?ref=calregulatory.com), which governs how Distributed Energy Resources and electric vehicles connect to the distribution grid. Across reply comments, parties converge on the need for near-term reform to clear procedural bottlenecks that delay clean-energy projects and threaten eligibility for federal tax credits. Most stakeholders (including the [Solar Energy Industries Association](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486756.PDF?ref=calregulatory.com), Vote Solar, the [Interstate Renewable Energy Council](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K455/586455858.PDF?ref=calregulatory.com), [NRDC](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K578/586578960.PDF?ref=calregulatory.com), [PearlX](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472603.PDF?ref=calregulatory.com), and the [Vehicle-Grid Integration Council](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K578/586578964.PDF?ref=calregulatory.com)) urge the Commission to prioritize two fixes: - Reforming "Screen Q," which pushes many projects into the CAISO’s lengthy transmission-level queue; and - Enforcing utility accountability for missed interconnection timelines. Clean-energy advocates support measurable penalties and a first-phase decision by mid-2026, while utilities favor a collaborative approach focused on automation, portals, and clearer processes. **Instant Analysis:** This rulemaking is the state’s central arena for interconnection reform, linking distributed generation, storage, and EV integration under one modernization push. The CPUC faces strong pressure to fix Screen Q, enforce utility accountability, and clarify how vehicle-to-grid systems are treated under Rule 21\. Interconnection reform is no longer niche policy housekeeping but a true test of California’s ability to translate clean-energy ambition into procedural competence before 2026 tax-credit windows close. --- ### PG&E Advanced Metering Infrastructure PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates filed a [supplemental statement](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K578/586578915.PDF?ref=calregulatory.com) supporting settlement of PG&E’s Comprehensive Gas Advanced Metering Infrastructure (GAMI) Replacement Program case. The settlement addresses three scoping issues: - PG&E’s responsibility for early module failures; - Cost allocation between shareholders and ratepayers; and - Treatment of undepreciated investments in retired modules. PG&E maintained that premature failures were due to battery life, not mismanagement, while the advocacy groups argued for shared responsibility and cost disallowances. Under the agreement, the parties cut PG&E’s 2023–2026 capital spending by about **$65 million**, reduced expenses by **$7.1 million**, and removed **$1.049 million** in return on equity tied to **$9.83 million** in undepreciated failed equipment. The compromise (about **$17 million** below PG&E’s original request) balances risk between customers and shareholders and resolves the disputed issues without litigation. The joint filing asserts the settlement is reasonable, consistent with prior CPUC decisions, and in the public interest because it ensures accountability while enabling progress toward PG&E’s next-generation Gas AMI 2.0 system. **Instant Analysis**: This settlement reflects a course correction in PG&E’s handling of its failed gas metering technology. After years of contention over who should pay for prematurely failing AMI modules, consumer advocates secured modest but meaningful concessions (roughly **$73 million** in combined reductions and the removal of shareholder returns on undepreciated assets). This shows a growing regulatory insistence on shared accountability for asset underperformance: utilities must demonstrate prudence, not merely technical inevitability, when infrastructure fails early. Future technology-replacement cases (e.g., grid sensors, communications upgrades) could face similar scrutiny, emphasizing lifecycle transparency, warranty recovery, and cost-sharing discipline over blanket ratepayer coverage. --- ### Sempra Utilities' Cost Allocation Proceeding In our November 10 [Monday Aggregate](https://www.calregulatory.com/monday-aggregate-socalgas-cap-rates-iou-distribution-planning-the-future-of-cas-base-services-charge/), we summarized parties' protests and responses to the September Cost Allocation Proceeding filing of SoCalGas/SDG&E (the Sempra Utilities). Recall that, with the new CAP application, the Sempra Utilities seek to revise natural gas rates, modify storage allocations, and adjust rate-design elements effective **January 1, 2027**. Parties raise concerns about rate impacts, storage reductions, embedded cost methodologies, allocation fairness, and insufficient justification for key proposals. Below are micro-summaries of their remarks. The Southern California Generation Coalition (SCGC)'s [protest](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M587/K015/587015946.PDF?ref=calregulatory.com) has since surfaced on the CPUC's website. Below is a short summary of their position. - SCGC contends that SoCalGas misleadingly compares its proposed 2027–2029 rates to “normalized” (rather than actual) September 2025 rates, giving a false impression of decreases when, by SCGC’s analysis, certain rates (e.g., electric-generation transmission-level service) would actually *increase* roughly **23%**. The coalition also challenges SoCalGas’s plan to replace the storage and balancing regime adopted in the 2024 CAP settlement, noting reductions in total storage inventory, injection, and withdrawal capacities without sufficient justification. - Further, SCGC opposes SoCalGas’s reallocation of **$116 million** in backbone transmission costs (plus safety-program expenses) to local transmission (an idea rejected in two prior CAPs) and its proposal to cut available backbone transmission service capacity in triennial open seasons from the current 3,775 MMcfd to 110% of forecasted design standards. - SCGC also objects to SoCalGas’s plan to use over-collections from the Noncore Storage Balancing Account to offset a **$4 million** undercollection in the Firm Access Storage Rights account, calling it an improper ratepayer subsidy for a failed off-system delivery program. **Instant Analysis**: This proceeding is shaping up to be one the most contentious rate cases in years. Across the board, parties are challenging the transparency, internal logic, and evidentiary support of the Sempra Utilities' application. SCGC adds particular force to these objections by accusing SoCalGas of misleading rate comparisons (using “normalized” rather than actual 2025 data) to imply rate decreases that may, in fact, be *increases* for electric generators. SCGC also targets SoCalGas's plan to abandon the 2024 storage and balancing framework, which had been painstakingly negotiated, and criticizes proposed reductions in storage inventory and backbone transmission capacity as inadequately justified and potentially harmful to reliability. In short, representatives of every major customer group see Sempra’s embedded-cost reallocations as opaque, self-serving, or both. Even Shell Energy North America's partial praise for scheduling reforms underscores how narrow the utilities’ defensible ground may be. This case now functions as an early stress test of post-electrification gas economics, where shrinking load, aging infrastructure, and legacy cost recovery are colliding. --- ### SDG&E 2026 ERRA Forecast **Administrative Law Judge Lirag** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K455/586455828.PDF?ref=calregulatory.com) approving SDG&E's Forecast 2026 Energy Resource Recovery Account submission. The PD authorizes a total of **$824.1 million**, a large increase from $122.3 million in 2025. The increase stems largely from higher Portfolio Allocation Balancing Account (PABA) costs and lower market price benchmarks. The PD finds SDG&E’s forecasts reasonable, covering procurement, local generation, competition transition, and GHG allowance returns, with 10% increases expected for bundled customers and 30% to 40% increases for unbundled customers. The PD also adopts SDG&E’s 2026 Electric Sales Forecast of **17,432 GWh**, derived from California Energy Commission demand modeling, and authorizes 2026 [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) rates. The PD resolves disputes over pre-2019 banked Renewable Energy Credits (RECs) by requiring SDG&E to use only post-2018 RECs unless separately approved. The PD directs SDG&E to implement the new rates effective **January 1, 2026** via advice letter. Comments are due **December 1**. The earliest the CPUC will consider this item is **December 4**. **Instant Analysis**: This PD showcases the CPUC’s continued tolerance for steep procurement cost increases when justified by market benchmarks and balancing account true-ups, even amid affordability pressures. The 10% to 14% bundled rate hike reflects structural shifts (especially in PABA accounting and Resource Adequacy/REC valuation) rather than discrete utility mismanagement. Still, it underscores how volatile market benchmarks can translate directly into double-digit retail swings. The PD's guardrails on pre-2019 RECs show the Commission’s sensitivity to transparency and fairness in cost allocation, even as it largely affirms SDG&E’s modeling. --- ### SDG&E Mid-Term Reliability Contracts SDG&E filed Advice Letter 4755-E (available [here](https://www.sdge.com/rates-and-regulations/tariff-information/advice-letters?ref=calregulatory.com)) to obtain approval of two battery energy storage contracts with Golden Fields Solar VI, LLC: a 44 megawatt, 4-hour system and a 48 MW 8-hour system. Both are 15-year power purchase tolling agreements expected online by **June 1, 2027**. The projects were selected through SDG&E’s Tranche 3 Integrated Resource Planning RFO, evaluated using a least-cost/best-fit methodology and verified by PA Consulting as Independent Evaluator. SDG&E requests cost recovery via the [Power Charge Indifference Adjustment](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/power-charge-indifference-adjustment?ref=calregulatory.com) (2023 vintage for the 4-hour system and 2021 vintage for the 8-hour system). **Instant Analysis:** These contracts mark SDG&E’s continued move toward storage-centric reliability solutions, illustrating how utilities are using multi-duration battery portfolios to satisfy long-lead and zero-emission mandates. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4328.JPG) ### Transmission Costs On November 4, 2025 PG&E [met with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K376/586376821.PDF?ref=calregulatory.com) advisors to **Commissioner Matt Baker** to discuss its application (A.24-09-015) for recovery of recorded expenditures through the Transmission Revenue Requirement Reclassification Memorandum Account (TRRRMA). PG&E explained that the TRRRMA proceeding is intended to prevent double recovery of costs while allowing the company to reconcile jurisdictional mismatches between CPUC and FERC rates. PG&E emphasized that the company has already refunded over **$1.36 billion** under FERC’s TO18-20 settlement (which resolved disputes over Common, General, and Intangible plant allocations) and that PG&E is now seeking CPUC authorization to recover up to **$472.8 million** in costs previously reviewed in other rate cases. PG&E asserted that these costs were incurred, audited, and approved for recovery in both CPUC and FERC contexts, providing extensive supporting documentation, including invoices and ledger data. The company argued its showing meets the burden of proof and that recovery through the TRRRMA is reasonable, consistent with Commission precedent (including a similar SCE case), and ensures no double counting. **Instant Analysis**: PG&E is using the TRRRMA as a jurisdictional bridge: a mechanism to true-up costs between CPUC and FERC without appearing to double-dip. By highlighting the $1.36 billion in FERC refunds as evidence of good faith while seeking CPUC recovery of previously vetted costs, PG&E frames its filing as procedural housekeeping rather than new spending. --- ### Union Island Pipeline On November 5, 2025 California Resources Production Corporation (CRPC) [met with](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K376/586376820.PDF?ref=calregulatory.com) **Commissioner Karen Douglas**'s Chief of Staff, **Kourtney Vaccaro**. At issue is a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) that denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of CRPC for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. (*More details on the PD are available in our* [*November 30 CPUC Voting Meeting Preview*](https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-preview/)). CRPC urged the Commission to withdraw the PD, arguing that it contains significant legal, procedural, and factual deficiencies. CRPC asserted that the PD departed from established CPUC precedent, applied an incorrect legal standard, and resolved issues not designated as threshold matters, thereby denying parties an opportunity to address them. CRPC also cited factual inaccuracies arising from what it viewed as an incomplete evidentiary record. In addition, CRPC emphasized the potential environmental and economic impacts if the Union Island Pipeline were forced to cease operations, including the loss of local jobs, loss of royalty income for roughly 200 San Joaquin County landowners, and increased reliance on imported natural gas that could raise greenhouse-gas emissions. **Instant Analysis**: CRPC's outreach underscores how consequential the Union Island denial could be for the company’s in-state gas operations and for local producers tied to its network. By stressing job losses, royalty impacts, and higher greenhouse emissions from out-of-state imports, CRPC is reframing the issue as one of economic and environmental harm rather than legal qualification. But the CPUC’s PD rests squarely on jurisdictional and evidentiary grounds (whether CRPC meets the statutory definition of a “gas corporation” with valid franchises and active operations). --- ### Diablo Canyon Cost Recovery **Administrative Law Judge Michelle Cooke** issued a [ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K598/586598100.PDF?ref=calregulatory.com) that denies a motion by Californians for Green Nuclear Power (CGNP) seeking to disqualify **ALJ Jack Chang** from PG&E's 2026 Diablo Canyon cost-recovery proceeding (*see our update* [*here*](https://www.calregulatory.com/californians-for-green-nuclear-power-file-motion-to-disqualify-alj-in-diablo-canyon-cost-case/) *for additional details.*) The ruling concludes that no bias or financial conflict exists and leaves ALJ Chang assigned to the Diablo Canyon proceeding. (*CGNP has a Substack post* [*here*](https://greennuke.substack.com/p/cpuc-we-dont-need-no-stinkin-physics) *that responds.*) **Instant Analysis:** The CPUC maintains that any rulings issued against CGNP in this proceeding were for procedural reasons (and not motivated by bias). ### MID-WEEK NEWS CODEX: Western Gateway Pipeline; Biofuels' Slow Growth; Arrival of EDAM and Markets+ URL: https://www.calregulatory.com/mid-week-news-codex-western-gateway-pipeline-biofuels-slow-growth-arrival-of-edam-and-markets/ Last updated: 2025-12-01T17:31:29.000Z - **20 New EV Charging Ports Installed in Long Beach, CA:** "PowerFlex recently collaborated with the Los Angeles County Internal Services Department and the Los Angeles County Development Authority to install 20 Level 2 electric vehicle charging ports at the LACDA Carmelitos community in Long Beach, CA. While 20 EV charging ports might not sound like that much, they are part of a much larger goal Los Angeles County has to install 15,000 EV chargers on its own properties by 2035." [**CLEAN TECHNICA**](https://cleantechnica.com/2025/11/11/20-new-ev-charging-ports-installed-in-long-beach-ca/?ref=calregulatory.com) - **CAISO's EDAM and SPP's Markets+ Arrive to Tame the Wild West:** "In the first half of 2026, the West will shortly have a new day-ahead market and an expansion of the SPP RTO (more on that in part 2). By 2027, a competing day-ahead market, and by 2028, most of the West will be participating in one or the other, while sure-to-be-acrimonious decisions on the future of CAISO should have reached their denouement. The guiding element across all of these initiatives is a unified (or at least polycentric) West via the expansion of markets to enable more efficient scheduling and operations across the interconnection." [**EXPORTS**](https://blog.gridstatus.io/western-markets-evolution-2025/?ref=calregulatory.com) - **Coastal Commission Refuses Permits for Diablo Canyon Without Additional Land Conservation**: "The California Coastal Commission declined Pacific Gas and Electric’s request for a federal consistency certification and a state coastal development permit, both of which are needed for a new 20-year operating license for the Diablo Canyon Power Plant. The Commission did not accept its staff recommendation to approve the requests at the November 6, 2025 [meeting](https://www.coastal.ca.gov/meetings/agenda/?ref=calregulatory.com#/2025/11), but instead said PG&E must place thousands of acres of land into conservation for approval of the coastal development permit." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/coastal-commission-refuses-permits?ref=calregulatory.com) - **Comparing the Esmeralda 7 Solar Project to the Diablo Canyon Nuclear Facility:** "[**Sammy Roth**’s claim that the Esmeralda 7 Solar Project would](https://www.climatecoloredgoggles.com/p/trump-is-canceling-solar-now-too?ref=calregulatory.com) 'produce' 6.2 gigawatts compared to Diablo Canyon’s 2.2 GW might suggest solar’s superiority. However, this overlooks the difference between capacity (maximum potential output) and generation (actual electricity produced). On a typical fall day, Esmeralda would average 1.34 GW, while Diablo Canyon delivers a steady 2.2 GW across 24 hours. This analysis compares the two facilities, highlighting nuclear’s reliability and efficiency over solar’s variability and land-intensive design." [**A PRAGMATIC APPROACH to ENERGY**](https://kclapp.substack.com/p/comparing-the-esmeralda-7-solar-project) - **Oil Extraction Reduces Methane Seepage:** "If oil extraction was resumed, it would reduce the amount of leakage of methane and other reactive organic compounds, whether the leaks are through naturally occurring vents, or through the thousands of dormant wells – many of which are so old they can’t easily even be found." [**CALIFORNIA POLICY CENTER**](https://californiapolicycenter.org/oil-extraction-reduces-methane-seepage/?ref=calregulatory.com) - **Open Season for Western Expansion – Kinder Morgan and Phillips 66 Launch Western Gateway Pipeline Connecting Midwest Supply to the Southwest and California:** "If built, the Western Gateway would, for the first time, supply California with refined fuels via pipeline directly from outside the state. This marks a pivotal shift for a region historically dependent on isolated in-state refineries and waterborne imports – offering new supply resilience for California, Arizona, and Nevada." [**STILLWATER ASSOCIATES**](https://stillwaterassociates.com/open-season-for-western-expansion-kinder-morgan-and-phillips-66-launch-western-gateway-pipeline-connecting-midwest-supply-to-the-southwest-and-california/?ref=calregulatory.com) - **Spreading the Cap-and-Trade Wealth:** "By extending the cap-and-trade program – now rebranded as [cap-and-invest](https://calmatters.org/environment/2025/09/climate-change-package-legislature/?ref=calregulatory.com) – California showed that it remains committed to smart decarbonization. Structuring the climate credit as a volumetric discount would align with that commitment." [**ENERGY at HAAS**](https://energyathaas.wordpress.com/2025/11/10/spreading-the-cap-and-trade-wealth/?ref=calregulatory.com) - **Talking in Tonnes, Negotiating in Dollars – the Politics of Carbon Markets in California:** "To keep prices low, will California continue to rely on lax accounting practices and low-quality offsetting projects, largely based outside the state? Or will concerns around costs motivate carbon-market design that explicitly limits costs and directs a larger share of funding to in-state activities that support California’s decarbonization agenda?" [**KLEINMAN CENTER for ENERGY POLICY**](https://kleinmanenergy.upenn.edu/events/talking-in-tonnes-negotiating-in-dollars-the-politics-of-carbon-markets-in-california/?ref=calregulatory.com) - **U.S. Biofuels Production Capacity Growth Slowed in 2024:** "Renewable diesel and other biofuels production capacity increased just 391 million gallons per year (gal/y) in 2024, less than one-third of the growth observed in 2022 and 2023\. In 2024, only two capacity additions came online, both in California: Phillips 66’s conversion of its Rodeo refinery to exclusively produce biofuels and the new Renewable Fuels LLC plant in Bakersfield. With the completed conversion, the Rodeo plant has a capacity of 767 million gal/y, up from 180 million gal/y in last year’s report. This increase makes it the second-largest renewable diesel plant in the United States, behind Diamond Green Diesel’s 982-million-gal/y plant in Norco, Louisiana." [**EIA**](https://www.eia.gov/todayinenergy/detail.php?id=66484&ref=calregulatory.com) ### November 20, 2025 CPUC Voting Meeting Preview: Undergrounding; SGIP Sunset; PG&E Zonal Electrification Pilot URL: https://www.calregulatory.com/november-20-2025-cpuc-voting-meeting-preview/ Last updated: 2026-01-05T01:07:47.000Z The CPUC’s **November 20** voting meeting features items that collectively illustrate a tightening focus on cost discipline, auditability, and program sunsets. From the closure of legacy incentive programs to the recalibration of market-transformation budgets and undergrounding rules, the CPUC's [agenda](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K499/586499801.pdf?ref=calregulatory.com) is indicative of a gradual shift from the open-ended experimentation of previous years to measured execution. Across numerous proceedings, the Commission appears to be injecting fiscal realism e.g., quantifiable benefits, verified compliance, and clear exit pathways. The true challenge for the agency, however, will be producing outcomes that convince ratepayers this course correction is working, and that California’s energy governance is accountable (in addition to being ambitious). Below are summaries of most key items. --- ### Undergrounding of Electrical Equipment [Draft Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850598.pdf?ref=calregulatory.com) updates and refines the CPUC’s [Senate Bill 884 program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com), which governs the expedited undergrounding of electric distribution lines by large utilities. The draft resolution builds on [Resolution SPD-15 ](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com)(2024) and aligns CPUC procedures with the [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com)’s 2025 guidelines for [10-year Electric Undergrounding Plans](https://energysafety.ca.gov/news/2025/02/20/energy-safety-adopts-10-year-electrical-undergrounding-plan-guidelines/?ref=calregulatory.com) (EUPs). The new resolution expands Phase 2 of the review process (covering cost applications and conditional approvals) by adding detailed data and audit requirements to ensure costs are just, reasonable, and ratepayer-protective. If Draft Resolution SPD-37 is adopted, utilities such as PG&E, SCE, and SDG&E would be obligated to: - Submit standardized project datasets, revenue-requirement models, and Key Decision-Making Metrics; - Justify any work outside of high-fire-threat areas; and - Include only projects with benefit-cost ratios ≥ 1 that meet specified project-level risk thresholds. The draft resolution also establishes new conditions for cost recovery, requiring that undergrounding projects outperform alternative mitigations, remain within approved cost and benefit thresholds, and satisfy Energy Safety performance standards. Additionally, the draft resolution introduces an annual EUP Audit to verify compliance and ensure costs are used and useful. A cumulative memorandum-account cost cap is added to prevent unlimited cost transfers. **Instant Analysis**: Draft Resolution SPD-37 trades speed for greater certainty: it slows execution but adds new oversight layers, in an effort to pursue undergrounding not merely as wildfire symbolism, but as infrastructure risk mitigation that can withstand audit, appeal, and political scrutiny. [Union criticism](https://capitolweekly.net/california-cant-afford-to-go-backward-on-wildfire-prevention/?ref=calregulatory.com), however, argues that this approach sacrifices urgency for bureaucracy by delaying shovel-ready work and weakening the state’s frontline defense against catastrophic fires. --- ### Self-Generation Incentive Program Ends If adopted, this [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M577/K291/577291720.PDF?ref=calregulatory.com) would close out the ratepayer-funded [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com) (SGIP) and establish procedures for returning unspent funds to customers while launching a "Greenhouse Gas Reduction Fund" (GGRF) version of the SGIP. As conceived, the GGRF would allocate **$280 million** in funds to provide solar-plus-storage incentives, specifically for low-income residential customers, including those served by public utilities. Unlike the original SGIP, which was financed through utility rate collections, the GGRF draws from Cap-and-Trade revenues. All new ratepayer-funded SGIP applications and waitlists will close on **December 30, 2025**, with unallocated funds refunded through annual Tier 1 advice letters using existing rate true-up mechanisms. (*Tier 1 filings take effect automatically, unless staff objects.*) Utilities must return remaining funds by 2033, and new projects will have a shortened two-year performance-based incentive period. The PD also grants up to four additional six-month extensions for delayed non-residential equity projects and removes the COVID-era “Stay on Cancellation” policy. (*The latter policy temporarily paused the automatic cancellation of SGIP projects that were delayed due to pandemic-related disruptions, allowing participants more time to complete installations*.) **Instant Analysis**: This PD formally winds down two decades of ratepayer-funded SGIP activity and shifts the program toward a state-funded future. The PD closes the books cleanly (returning unused funds, shortening incentive timelines, and tightening oversight) while focusing on low-income customers with the new GGRF-backed incentives. --- ### PG&E Zonal Electrification Pilot at California State University Monterey Bay This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K687/581687721.PDF?ref=calregulatory.com) grants PG&E's motion to withdraw its application (A.22-08-003) for a [zonal electrification pilot project](https://csumb.edu/news/news-listing/east-campus-may-become-californias-largest-electrification-project/?ref=calregulatory.com) at California State University Monterey Bay. - PG&E had sought approval to substitute a planned gas-pipeline replacement with an all-electric conversion of several hundred campus dwellings, capitalizing the costs like a regulatory asset so shareholders could earn a return. - The project aimed to test building-level electrification as a substitute for gas-infrastructure investment, advancing California’s decarbonization goals. After protracted procedural delays, PG&E exercised its contractual right to terminate the project, citing safety risks and a 2026 remediation deadline that conflicted with the regulatory timeline. Several parties (including TURN, Natural Resources Defense Council, Sierra Club, and the Environmental Defense Fund) opposed the withdrawal, arguing that PG&E’s rationale was vague and possibly aimed at avoiding an adverse outcome. Others, such as Indicated Shippers/[Agricultural Energy Consumers Association](https://agenergyca.org/?ref=calregulatory.com), supported withdrawal, saying the issues could be better handled in broader proceedings like the [Long-Term Gas System Planning docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com). The PD finds the withdrawal reasonable and in the public interest since PG&E’s termination renders the project moot. Still, the PD preserves policy value: it directs PG&E to file a “lessons-learned” report within 90 days, to disclose this record in future electrification or decarbonization filings for three years, and to make the evidentiary record available for use in later proceedings. **Instant Analysis**: This PD demonstrates pragmatism regarding experimental electrification projects – it allows PG&E to abandon a pilot that became impractical, while salvaging its informational and policy value. Significantly, this proceeding revealed an enduring friction over cost allocation, as PG&E's plan would've spread electrification costs across all gas ratepayers for a localized benefit zone. That discussion will surely carry over into the Long-Term Gas Planning proceeding as [Senate Bill 1221 implementation](https://www.cpuc.ca.gov/industries-and-topics/natural-gas/sb-1221-implementation?ref=calregulatory.com) picks up steam. --- ### Mobilehome Electrification Initiative [This PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K961/583961250.PDF?ref=calregulatory.com) establishes a joint Mobilehome Park Electrification Pilot Initiative with the California Energy Commission. Under the pilot, PG&E, SCE, and SDG&E will partner with the CEC’s [Equitable Building Decarbonization](https://www.energy.ca.gov/programs-and-topics/programs/equitable-building-decarbonization-program?ref=calregulatory.com) (EBD) program to fully electrify selected mobilehome parks while converting their submetered systems to direct, utility-owned electric service under the existing [Mobilehome Park Utility Conversion Program](https://www.cpuc.ca.gov/regulatory-services/safety/mhp/mobilehome-park-utility-upgrade-program?ref=calregulatory.com) (MHP UCP). - Participating parks must agree to permanently retire gas infrastructure, replace appliances with efficient electric models, and receive necessary in-home rewiring and panel upgrades. The goal is to study the technical, legal, and cost implications of full electrification and inform future modifications to the MHP UCP. - The PD directs utilities to coordinate with CEC staff and regional administrators but prohibits them from installing new gas infrastructure or recovering additional ratepayer funding. Instead, the program will leverage non-ratepayer sources, primarily the EBD program’s **$567 million** budget supported by state and federal funds. - Tenant protections mirror those in the MHP UCP and EBD guidelines, ensuring residents are informed, protected from rent hikes, and supported during construction. **Instant Analysis**: By merging the Mobilehome Park Utility Conversion Program with the CEC’s Equitable Building Decarbonization initiative, the Commission is testing how to scale end-to-end electrification without burdening ratepayers. The PD seems to represent a broader intent to retire small gas systems, leverage federal [Inflation Reduction Act](https://en.wikipedia.org/wiki/Inflation%5FReduction%5FAct?ref=calregulatory.com) funds, and coordinate cross-agency decarbonization in disadvantaged communities. --- ### Energy Efficiency Market Transformation The CPUC is scheduled to review competing proposed decisions to address energy efficiency market transformation. If adopted, **Commissioner Matt Baker**'s[ alternate proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K301/581301683.PDF?ref=calregulatory.com) (APD) would approve ratepayer funding for only one "Market Transformation Initiative," or MTI (the [Room Heat Pump program](https://calmta.org/room-heat-pumps/?ref=calregulatory.com)), while denying the[ California Market Administrator](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K575/586575760.PDF?ref=calregulatory.com) (CalMTA)'s proposed [Induction Cooktop MTI](https://calmta.org/resourcereport/induction-cooking-mti-plan/?ref=calregulatory.com) and related future initiatives. Commissioner Baker's APD authorizes a six-year six-year budget of **$54.87 million** (2026–2031), which is about half the amount recommended by the Administrative Law Judge [in a competing PD](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K575/586575760.PDF?ref=calregulatory.com). The APD orders CalMTA to: - File annual reports; - Submit a 2028 Tier 2 advice letter detailing its transition to non-profit status and plans for seeking non-ratepayer funding (*Tier 2 filings are reserved for substantive but routine matters*); - Provide the CPUC a perpetual license to its internal cost-effectiveness tool; and - Undergo annual audits by the [CPUC’s Audit Branch](https://www.cpuc.ca.gov/about-cpuc/divisions/utility-audits-risk-and-compliance-division/utility-audits-branch?ref=calregulatory.com). By rejecting **$27.6 million** for the Induction Cooktop MTI and **$139 million** in unspecified future work, the APD narrows CalMTA’s scope, aligns funding with ratepayer affordability under [Executive Order N-5-24](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com), and conditions future MTIs on demonstrated fiscal transparency and diversified funding sources. The CPUC was originally set to consider this item on October 30 but delayed action until **November 20**. **Instant Analysis**: By authorizing only the Room Heat Pump initiative and cutting the total program budget nearly in half, the APD redefines what “market transformation” will mean under heightened affordability concerns. The move aligns with Executive Order N-5-24, reinforcing a shift toward targeted, measurable electrification investments over expansive decarbonization pilots. The strengthened audit, non-profit-transition, and non-ratepayer-funding requirements point to a future in which CalMTA must operate more like a public-benefit enterprise than a ratepayer-funded laboratory. (*Note that, typically, commissioner APDs tend to win out in the voting process over ALJ PDs.*) --- ### Avoided Cost Calculator This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K959/583959221.PDF?ref=calregulatory.com) revises the [Avoided Cost Calculator](https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight?ref=calregulatory.com) (ACC) process and increases its consultant budget from $350,000 to **$1.2 million** per year. The ACC, which quantifies avoided generation, transmission, and emissions costs for Distributed Energy Resources, will now follow a streamlined biennial update cycle. This cycle will align with the CPUC’s [Integrated Resource Planning](https://www.cpuc.ca.gov/irp/?ref=calregulatory.com) Transmission Planning Process portfolio when the "Preferred System Plan" is unavailable. As a reminder, the Commission develops two key portfolios in the IRP process: - The Preferred System Plan, which shows the optimal mix of resources to meet climate and reliability goals; and - The Transmission Planning Process "base-case" portfolio, a closely related dataset sent to the CAISO for use in planning its transmission buildout. The revised ACC process removes automatic evidentiary hearings and multiple comment rounds but preserves workshops and allows hearings if factual disputes arise, to deliver faster, more consistent updates. **Instant Analysis**: This proposal represents an attempt to modernize the CPUC’s cost-effectiveness framework for DERs, by replacing procedural inertia with tighter coordination and current data inputs. The budget increase reflects growing model complexity, inflation, and the expanding role of DER valuation in grid planning. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4313.JPG) ### Distributed Energy Resources This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K961/583961198.PDF?ref=calregulatory.com) denies a [petition](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M563/K203/563203670.PDF?ref=calregulatory.com) filed by the [California Efficiency + Demand Management Council ](https://cedmc.org/?ref=calregulatory.com)to modify a 2019 decision ([D.19-05-019](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M293/K833/293833387.PDF?ref=calregulatory.com)), which had established the "[Total Resource Cost](https://eecoordinator.info/wp-content/uploads/2021/08/2019%5FSEEC%5FPresentation%5FTRC-for-the-Rest-of-Us-Breaking-Down-Cost-Effectiveness.pdf?ref=calregulatory.com)" (TRC) test as the primary framework for evaluating Distributed Energy Resources. The Council sought to replace the TRC with the "Program Administrator Cost" test for budget allocations, arguing that TRC penalizes high-upfront-cost measures. The PD finds the petition procedurally deficient and untimely. Major parties including Cal Advocates, PG&E, SCE, SoCalGas, and SDG&E opposed the petition, asserting that its arguments belonged in current DER or energy-efficiency proceedings (not [this rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M116/K116/116116537.PDF?ref=calregulatory.com), which was launched in 2014). NRDC and Recurve supported the petition. **Instant Analysis**: By rejecting the Council’s petition, the Commission's message seems to be that debates over cost-effectiveness frameworks, however imperfect, will not be reopened without compelling new evidence or timely justification. The PD also suggests that broader policy shifts, such as executive orders or auditor critiques, do not automatically warrant retroactive regulatory changes. For stakeholders, the apparent message is that any future push to recalibrate DER valuation or affordability metrics must occur within active proceedings. --- ### Mid-Term Reliability [Draft Resolution E-5428](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K052/584052019.PDF?ref=calregulatory.com) approves eight new mid-term reliability contracts and one amendment submitted by SCE under its 2025 procurement plan. The portfolio includes solar-plus-storage projects in Kern and Riverside Counties and a solar project in Arizona, totaling about 498 megawatts, plus a 75-MW amendment to the [Gateway battery facility in San Diego](https://www.powermag.com/worlds-largest-for-now-battery-storage-project-online-in-california/?ref=calregulatory.com) that extends its delivery date to 2027 following a 2024 thermal event investigated by the CPUC and the Environmental Protection Agency. Collectively, these contracts supply roughly 151 MW of effective capacity toward SCE’s obligations under the CPUC's original "mid-term reliability" decision ([D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com)) and a supplemental procurement decision ([D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com)). The solar agreements also contribute to SCE’s Diablo Canyon Replacement and Renewable Portfolio Standard targets. Draft Resolution E-5428 finds the contracts consistent with SCE’s 2024 RPS Procurement Plan, competitively priced, and procured through a transparent, least-cost/best-fit process verified by independent evaluator Sedway Consulting. Costs will be recovered through the Portfolio Allocation Balancing Account (the 2021 sub-account for solar and 2023 for storage) with all ratepayers sharing benefits and costs. Contract prices and cost data are confidential, pursuant to the Public Utilities Code. **Instant Analysis:** By approving SCE’s solar-plus-storage portfolio and extending the [Gateway BESS](https://en.wikipedia.org/wiki/Gateway%5FEnergy%5FStorage?ref=calregulatory.com) contract after a [2024 fire](https://response.epa.gov/site/site%5Fprofile.aspx?site%5Fid=16485&ref=calregulatory.com), the Commission is demonstrating some flexibility toward operational realities. The confidential pricing underscores a cautious stance toward market sensitivity, which is par for the course on these types of agreements. --- ### **Bioenergy Market Adjusting Tariff** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K161/586161556.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)), which had extended the [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) (BioMAT) program through December 31, 2025. In their petition, the Association sought to remove or extend that sunset date to 2035 and make several programmatic changes, arguing the program supports wildfire mitigation, waste reduction, and air-quality goals. - The PD finds that the BioMAT, which was created under Senate Bill 1122 (2012) to procure 250 megawatts of small-scale bioenergy, is underused, high-cost, and duplicative of other procurement mechanisms such as the Renewables Portfolio Standard, Renewable Market Adjusting Tariff, BioRAM, and Qualifying Facility contracts. - Only about 21% (51 MW) of the authorized 250 MW has been subscribed since 2016, despite numerous rule changes. Energy prices under BioMAT (12.8 ¢/kWh to 20 ¢/kWh) substantially exceed other renewable options (which are approximately 8 ¢/kWh). The PD concludes that continuing the program would conflict with the Governor’s Executive Order N-5-24 on affordability, which directs agencies to sunset underperforming or high-cost initiatives. **Instant Analysis:** Some critics would argue, perhaps rightly, that the Governor’s Executive Order N-5-24 carries more than a trace of performative self-protection for a leader whose [national aspirations are well known](https://apnews.com/article/newsom-trump-california-governor-2028-white-house-42b6b5f7d546b76b284c018290cb76e1?ref=calregulatory.com). Nevertheless, the CPUC seems to be treating the governor's affordability directive as substantive policy rather than symbolic gesture. This PD serves as additional proof. --- ### Union Island Pipeline This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denies a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD finds that CRPC does not currently qualify as a “gas corporation” or “public utility” under California law because it no longer holds valid franchise rights in Antioch and Brentwood (those expired in 2021), and it stopped transporting gas in May 2023. The PD also cites ongoing litigation in which Antioch argues CRPC abandoned its pipeline interests, concluding that CRPC does not own, control, or operate the full pipeline and therefore cannot dedicate it to public use. The PD denies CRPC’s request to substitute a subsidiary into the application and the cities’ request to pause the proceeding, but grants CRPC’s motion to keep financial documents sealed for three years. **Instant Analysis**: This PD shows the CPUC’s unwillingness to extend public utility privileges to entities that lack clear, current control of infrastructure or local operating rights. The PD also reinforces that dormant or speculative operations cannot satisfy statutory definitions of “gas corporation” or “public utility.” (*For more info on this item, please see our* [*November 7 Aggregate*](https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/)*, which details CRPC's recent* [*motion*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273786.PDF?ref=calregulatory.com) *to reopen the record.*) --- ### **Crude Oil Transportation** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K610/584610997.PDF?ref=calregulatory.com) authorizes Crimson California Pipeline, LP to raise its crude-oil transportation rates on its Southern System by 26.35%, retroactive to August 1, 2024, with interest. The PD finds the increase just and reasonable after Crimson removed parent-company [CorEnergy](https://corenergy.reit/strategy/?ref=calregulatory.com)'s finances from its filing and adopted a 60/40 equity-to-debt ratio, 12% cost of debt, and 15% return on equity, consistent with *Bluefield* and *Hope* standards for financial soundness. According to the PD, a smaller 10% increase would have left Crimson operating at a loss. **Instant Analysis**: By approving a 26.35% increase (more than double the statutory 10% self-implementation cap) the Commission is telegraphing that maintaining safe, solvent operations outweighs short-term rate stability. The PD also establishes an apparent precedent: parent or affiliate financials cannot be used to inflate cost recovery. But once excluded, the CPUC will still accommodate reasonable equity returns to prevent underinvestment or safety degradation. ### MONDAY AGGREGATE: SoCalGas CAP Rates; IOU Distribution Planning; the Future of CA's "Base Services Charge" URL: https://www.calregulatory.com/monday-aggregate-socalgas-cap-rates-iou-distribution-planning-the-future-of-cas-base-services-charge/ Last updated: 2025-12-01T17:31:54.000Z On Monday's radar: - Protests to the Sempra Utilities' September Cost Allocation Proceeding showcase opposition over how utilities will allocate infrastructure costs as throughput declines under electrification pressure. - Autumn rate volatility suggests that commodity swings, not delivery charges, drive C&I cost risk, with SoCalGas procurement rebounding 50% in November after three months of decline. - On the electricity/distribution side, independent engineers' assessments of all three major investor-owned utilities reveal grid planning systems straining under the speed of electrification demands, particularly from transportation loads that dominate project pipelines but materialize unpredictably. ### SOCALGAS RATES On Friday, several key stakeholders filed protests or responses to the September Cost Allocation Proceeding (CAP) [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K104/582104341.PDF?ref=calregulatory.com) filed by SoCalGas/SDG&E (the Sempra Utilities). With the new CAP application, the Sempra Utilities seek to revise natural gas rates, modify storage allocations, and adjust rate-design elements effective **January 1, 2027**. Parties raise concerns about rate impacts, storage reductions, embedded cost methodologies, allocation fairness, and insufficient justification for key proposals. Below are micro-summaries of their remarks. - **TURN:** The Utility Reform Network [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K143/586143326.PDF?ref=calregulatory.com) that the Sempra Utilities' embedded cost approach would improperly shift a greater portion of costs onto residential customers, diverging from long-run marginal cost principles. TURN also objects to SoCalGas’s plan to increase fixed residential customer charges (from **$5** to **$20** for non-CARE customers by 2029) and to **$10** for [CARE](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com) customers, calling the justification inadequate and reminiscent of earlier proposals that the CPUC has already rejected. TURN argues further that the utilities have double-counted certain plant costs by including Asset Retirement Obligations in rate-base calculations, and requests that the Commission compel them to submit an alternative scenario excluding those costs. - **INDICATED SHIPPERS**: The Indicated Shippers (a coalition that includes large industrial gas users such as Chevron, Phillips 66, and Marathon) [warn](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486704.PDF?ref=calregulatory.com) that SoCalGas’s cost-allocation proposals could yield substantial increases for noncore customers, including a **20.5%** rise in commercial and industrial transmission-level service rates. The Indicated Shippers assert that Sempra’s filings are opaque and fail to justify these increases in light of the company’s concurrent claims of an overall rate decrease. The Shippers also challenge proposed storage reductions (from **119.5** to **118.8 billion** cubic feet of working capacity) and narrower withdrawal rights, which they argue could threaten system reliability and raise price volatility. The Shippers' protest emphasizes that the utilities have not addressed how their storage plans interact with the state’s biennial review of the Aliso Canyon natural gas storage facility, particularly given the [CPUC Energy Division’s 2025 recommendation to reduce its capacity by **10 Bcf**](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/natural-gas/aliso-canyon/2025%5Faliso%5Fcanyon%5Fbiennial%5Fassessment.pdf?utm%5Fsource=chatgpt.com). - **CAL ADVOCATES**: Cal Advocates [identifies](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K578/586578911.PDF?ref=calregulatory.com) a wide range of contested issues, ranging from the utilities’ storage and balancing framework and weather-design standards to their demand forecasts, embedded cost studies, and proposed fixed-charge increases. Cal Advocates questions whether the Sempra Utilities' proposals for rate allocation, storage use, and backbone transportation service are just and reasonable. - **CITY of LONG BEACH**: Long Beach, which operates its own municipal gas system serving half a million people, [points out](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486702.PDF?ref=calregulatory.com) that transmission rates have risen over **300**% in the last decade and that SoCalGas’s proposals risk further burdening customers already struggling with high energy costs. The city argues that the Sempra Utilities' filing lacks transparency and fails to include a sufficiently detailed cost-of-service model disaggregating customer classes. The city also warns that the proposed adjustments to storage and balancing allocations could reduce reliability for municipal customers who depend on SoCalGas storage fields to meet winter demand. Long Beach further objects to the proposed expansion of [Rule 23](https://www.calregulatory.com/weekend-news-codex-2/) ("Continuity of Service and Interruption of Delivery"), which would extend core priority service to electric generators up to 10 megawatts, potentially worsening curtailment risk for existing wholesale customers. - **SHELL ENERGY NORTH AMERICA (SENA)**: SENA [focuses](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K376/586376801.PDF?ref=calregulatory.com) on SoCalGas’s proposed revisions to Backbone Transportation Service (BTS) and [Rule 30](https://www.calregulatory.com/weekend-news-codex-2/) ("Transportation of Customer-Owned Gas") scheduling procedures. SENA notes that the utilities’ plan to cap firm BTS sales at **110%** of design-standard capacity and to prioritize firm nominations during all intraday cycles could address past operational concerns that allowed interruptible customers to jump ahead of firm shippers (i.e., obtain capacity before) later in the same gas day. **INSTANT ANALYSIS**: SoCalGas/SDG&E face an uphill battle convincing regulators and stakeholders that their 2027 rate and storage proposals are justified. Nearly every intervenor raises transparency, fairness, and timing concerns. A common refrain is distrust of Sempra’s embedded-cost framework and skepticism toward its accelerated schedule. This proceeding has potential to be a referendum on how California’s gas utilities will allocate shrinking throughput costs in the era of mass electrification. --- ### ADDITIONAL NATURAL GAS RATE UPDATES SoCalGas recently posted its [October 2025](https://www.socalgasenvoy.com/ebb/attachments/1762556578344%5F10-1-2025%5FRate%5FSummary.pdf?ref=calregulatory.com) and [November 2025](https://www.socalgasenvoy.com/ebb/attachments/1762556606532%5F11-1-2025%5FRate%5FSummary.pdf?ref=calregulatory.com) commercial and industrial gas rate summaries. Below is our four-month retrospective. - From August to November 2025, SoCalGas’s C&I rate summaries reveal notable swings in core gas procurement prices and moderate-but-steady variation in delivery components. The Non-Residential Core Procurement Charge declined through early fall before rebounding in November to the tune ofa **50%** increase. - SoCalGas's crossover rate (G-CPNRC) held flat at **36.665 ¢** from October through November after falling from 42.853 ¢ in September, indicating that procurement volatility might trace back to the base commodity rather than balancing service. - For core commercial service (G-10), base rates eased slightly through October but then rose in November, tracking the procurement rebound. Similar upticks appear in the air-conditioning and gas-engine schedules. - Across noncore tiers, distribution charges hovered within a narrow band, indicating stability in transportation margins even amid commodity turbulence. Transmission Level Service (GT-3/GT-4/GT-5) remained near **25 ¢**/therm class average throughout, and backbone transportation reservation rates held constant at **$0.57976** per Dth/day (albeit with looming CAP and Annual True-Up increases on the horizon). **INSTANT ANALYSIS:** SoCalGas’s autumn rate pattern provides a glimpse into how commodity volatility dominates cost risk for C&I customers. After three straight months of falling procurement charges, November brought a dramatic 50% rebound, reversing prior savings and tightening margins for noncore users. Delivery, transmission, and public-purpose charges remained steady, suggesting that transportation infrastructure costs are not the source of fluctuation. A deep negative buy-back rate reflects oversupply conditions and low system demand, hinting at possible storage congestion or weak downstream offtake. While October represented a temporary price trough, November’s spike suggests that gas-supply markets are turning, with SoCalGas procurement costs re-coupling to broader wholesale volatility while delivery components stay inert. --- On PG&E's end, a multi-month forecast is available below (source documents can be found [here](https://www.pge.com/tariffs/en/rate-information.html?ref=calregulatory.com#tabs-db55ae8d8e-item-d2a3158b47-tab)). __**PG&E**Covered Entities - Volumetric Class-Average RatesNovember 2025 - June 2026 Natural Gas Rate Outlook $/therm (Includes PPP Surcharge)__ | Rate Schedule | Nov 2025 | Dec 2025 | Jan 2026 | Feb 2026 | Mar 2026 | Apr 2026 | May 2026 | Jun 2026 | | ------------- | -------- | -------- | -------- | -------- | -------- | -------- | -------- | -------- | | **G-NT-D** | $0.864 | $0.864 | $0.762 | $0.762 | $0.765 | $0.658 | $0.658 | $0.658 | | **G-NT-T** | $0.343 | $0.343 | $0.350 | $0.350 | $0.351 | $0.351 | $0.351 | $0.351 | | **G-NT-BB** | $0.097 | $0.097 | $0.117 | $0.117 | $0.118 | $0.118 | $0.118 | $0.118 | | **G-EG** | $0.263 | $0.263 | $0.289 | $0.289 | $0.289 | $0.289 | $0.289 | $0.289 | | **G-EG-BB** | $0.030 | $0.030 | $0.065 | $0.065 | $0.066 | $0.066 | $0.066 | $0.066 | __**PG&E**Non-Covered Entities - Volumetric Class-Average RatesNovember 2025 - June 2026 Natural Gas Rate Outlook $/therm (Includes PPP Surcharge + GHG Adder)__ | Rate Schedule | Nov 2025 | Dec 2025 | Jan 2026 | Feb 2026 | Mar 2026 | Apr 2026 | May 2026 | Jun 2026 | | ------------- | -------- | -------- | -------- | -------- | -------- | -------- | -------- | -------- | | **G-NT-D** | $1.011 | $1.011 | $0.851 | $0.851 | $0.853 | $0.747 | $0.747 | $0.747 | | **G-NT-T** | $0.490 | $0.490 | $0.438 | $0.438 | $0.439 | $0.439 | $0.439 | $0.439 | | **G-NT-BB** | $0.245 | $0.245 | $0.205 | $0.206 | $0.206 | $0.206 | $0.206 | $0.206 | | **G-EG** | $0.410 | $0.410 | $0.377 | $0.377 | $0.378 | $0.378 | $0.378 | $0.378 | | **G-EG-BB** | $0.177 | $0.177 | $0.153 | $0.153 | $0.154 | $0.154 | $0.154 | $0.154 | January 2026 changes assume increases for PG&E's 2023 General Rate Case decision ([D.23-11-069](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M520/K896/520896345.pdf?ref=calregulatory.com)); 2026 Cost of Capital ([A.25-03-010](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M559/K099/559099245.PDF?ref=calregulatory.com)); Wildfire and Gas Safety costs ([A.23-06-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M511/K547/511547762.PDF?ref=calregulatory.com)); Wildfire Mitigation and Catastrophic Events ("WMCE," [A.22-12-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M499/K888/499888007.PDF?ref=calregulatory.com)); Advanced Metering Infrastructure ([A.24-03-011](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M527/K230/527230482.PDF?ref=calregulatory.com)) and transmission revenue requirements. March 2026 assumes the effects of the 2023 WMCE ([A.23-12-001](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M521/K134/521134366.PDF?ref=calregulatory.com)), and August 2026 assumes: - Recovery of the 2024 WMCE ([A.24-11-009](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M546/K561/546561470.PDF?ref=calregulatory.com)); - Billing Modernization recovery begins ([A.24-10-014](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M543/K837/543837551.PDF?ref=calregulatory.com)); and - The recovery of PG&E's 2011-2014 Gas Transmission and Storage capital expenditures ([D.22-07-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M494/K580/494580839.PDF?ref=calregulatory.com)) ends. **INSTANT ANALYSIS**: PG&E’s rate trajectory continues to be shaped by overlapping wildfire, safety, and modernization cost cycles that will raise rates in Q1 2026 before lowering mid-year. Covered entities benefit from a clearer seasonal drop-off, while non-covered entities face persistently higher therm costs due to GHG adders and broader capital recovery alignment. --- ### DISTRIBUTION PLANNING In our [Friday aggregate](https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/) we reported on PG&E's [*2025 Distribution Planning Advisory Group*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [(DPAG)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [*Independent Professional Engineer*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [(IPE)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [*Report*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com). The report, filed in the Commission's High DER Future rulemaking, suggested that PG&E is entering a period of accelerated stress, driven by surging load requests and mass electrification, with an acute need to improve how it responds to real-world demand. - SCE's equivalent report is available [here](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K143/586143334.PDF?ref=calregulatory.com). SCE's report confirms that electrification is driving a dramatic expansion in grid needs (a 69% jump in one year and 250% growth over five). While SCE’s load-forecasting process is robust and compliant with CPUC reforms, it also reveals mounting uncertainty in how fast transportation and building electrification loads will actually materialize. Known-load data show projects increasing in size but slipping in completion, with only about 12% fully energized and 78% either completed or deferred. - Electric vehicle and port electrification now dominate the pipeline, suggesting that half of SCE’s projected near-term load growth is transport-related. A "Borrow Forward" forecasting method, which effectively decouples SCE’s embedded loads from [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) constraints, could inflate future demand projections if project materialization rates remain weak. The IPE’s recommendations (tracking pending loads alongside known ones and better integrating DER-based mitigation) point toward a more agile, data-verified planning regime. As with PG&E, SCE's report highlights a system straining under the velocity of electrification ambitions, where forecast integrity and load realization, not modeling sophistication, may determine the success of any grid modernization efforts. SDG&E's report, available [here](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486697.PDF?ref=calregulatory.com), shows a jump from 25 to 52 identified grid needs, along with a 37% rise in total known-load additions (driven largely by commercial and transportation electrification), which indicates intensifying distribution-capacity pressure. While about half of SDG&E's needs were mitigated through operational fixes like load transfers, the remaining 22 planned projects (notably 10 new circuits and three new substations) confirm a serious buildout is underway. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4306.JPG) ### DEMAND FLEXIBILITY On October 31, 2025 Cal Advocates [held an ex parte meeting](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K129/586129384.PDF?ref=calregulatory.com) with advisors to CPUC **Commissioner John Reynolds** to discuss the future of California’s Base Services Charge (BSC), formerly known as the Income-Graduated Fixed Charge (IGFC). - Cal Advocates expressed support for the BSC concept but urged the Commission to promptly open a new rulemaking to revise and expand it. The office argued that the BSC approved in a 2024 decision ([D.24-05-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K686/531686019.PDF?ref=calregulatory.com)) failed to adequately lower volumetric electricity rates, especially given that PG&E and SCE rates have risen more than 30% since 2022, while the adopted BSC only reduces volumetric charges by 8% to 13%. - Without enlarging the fixed charge, Cal Advocates warned, California risks undermining affordability and electrification goals. Cal Advocates recommends allowing additional fixed costs (such as non-marginal distribution expenses) to be recovered through the BSC, noting this could expand PG&E’s eligible cost share from 12% to 31.5% of its revenue requirement. Cal Advocates also urged updates to income tier definitions and verification methods to ensure customers are accurately placed in low-, moderate-, and high-income brackets. The office highlighted that working groups on implementation and income verification are already active but said a new proceeding should focus solely on BSC issues to enable timely reforms. ### WEEKEND NEWS CODEX: Geothermal; Seams Coordination; Vehicle-to-Grid Potential URL: https://www.calregulatory.com/weekend-news-codex-2/ Last updated: 2025-12-01T17:32:10.000Z - **California Can't Get Out of its Own Way on Geothermal:** "The state has enormous untapped potential — and a growing need for electricity. California has shut down all but one of its nuclear power plants over the past few decades. In recent years, persistent drought has made the state’s hydroelectric stations less dependable. Solar [generation has soared](https://www.canarymedia.com/articles/solar/solar-is-crushing-gas-in-california-this-year?ref=calregulatory.com), and a growing fleet of batteries has helped steady the supply when sun-soaked days threaten to overwhelm the grid with electrons and dark nights send panels’ production plummeting. But the state [remains reliant](https://www.caiso.com/todays-outlook/supply?ref=calregulatory.com) on natural gas and power imports from neighboring states to meet surging demand. To achieve its carbon-cutting goals and bring down electricity rates that [are more than double](https://www.eia.gov/electricity/monthly/epm%5Ftable%5Fgrapher.php?t=epmt%5F5%5F6%5Fa&ref=calregulatory.com) that of nearby states, California needs to increase its supply of clean, firm generation." [**CANARY MEDIA**](https://www.canarymedia.com/articles/geothermal/california-newsom-veto-bill-environmental-reviews?ref=calregulatory.com) - **FERC Staff Issues Whitepaper on Seams Coordination in the Western Interconnection**: "...key issues we recommend the parties address in seams coordination include: (1) modeling of transmission availability and use in the West; (2) coordination to maintain reliability and manage congestion; and (3) coordination to enhance the economic benefits of transactions across regions. We understand that these are difficult issues that will require time to address." [**FERC NEWS**](https://www.ferc.gov/news-events/news/ferc-staff-issues-whitepaper-seams-coordination-western-interconnection?ref=calregulatory.com) - **How EVs Can Fix the Grid and Lower Your Electric Bill:** "The Natural Resources Defense Council has estimated that if California V2G’ed all of the 14 million EVs it’s expected to have by 2035, it could [power every home in the state for three days](https://www.nrdc.org/bio/max-baumhefner/how-electric-cars-and-trucks-improve-grid-reliability?ref=calregulatory.com)." [**GRIST**](https://grist.org/solutions/how-evs-can-fix-the-grid-and-lower-your-electric-bill/?ref=calregulatory.com) - **Interview with Energy Economist Ahmad Faruqui – Debunking the Solar "Cost-Shift" Myth:** "When you have goals, ambitious goals, which are laudable, which California does have — the goals have been very aggressive; by 2045, they want 100% renewable and carbon-free — that is something to aspire to, and it is good to have that North Star. However, if you lose the roadmap on how to get there and you start doing things that are counterintuitive and counterproductive, then you’re going to create problems. And that’s what has happened." [**LAKIS POLYCARPOU**](https://www.linkedin.com/pulse/debunking-solar-cost-shift-myth-lakis-polycarpou-qe7re/?trackingId=Bf5Y5sxc7g14RiT216tRWw%3D%3D&ref=calregulatory.com) - **Lines for Gas Coming to California:** "As in-state production of crude collapses, the intake capacity of seaport facilities will have to be increased to accommodate more tankers, requiring a major infrastructure investment. And as [refinery capacity](https://www.energy.ca.gov/data-reports/energy-almanac/californias-petroleum-market/californias-oil-refineries?ref=calregulatory.com) drops below in-state demand for gasoline and diesel fuel, it will be necessary to import refined gasoline. This not only would require different facilities to receive, store, and distribute imported gasoline instead of crude oil, it would also have to be gasoline refined to California’s very exacting and unique formulations." [**CALIFORNIA GLOBE**](https://californiaglobe.com/fr/ringside-lines-for-gas-coming-to-california/?ref=calregulatory.com) - **Santa Barbara Denies Permit Transfer to Sable in Preliminary Vote:** "The Santa Barbara County Board of Supervisors [voted](https://santabarbara.legistar.com/LegislationDetail.aspx?ID=7719768&GUID=8E7B2342-70D5-43DD-A9EF-732C9C5CF51A&Options=&Search=&ref=calregulatory.com) to deny the transfer of operating permits from ExxonMobil to Sable Offshore Corp. that cover the Santa Ynez Unit, a gas plant, and the Las Flores Pipelines. The Supervisors voted 4-1 to prepare written findings to support the decision and will have a final vote on December 16, 2025\. The transfer of permits is a key step in restarting the Santa Ynez Unit, which has been shut since the 2015 Refugio oil spill." [**CALIFORNIA ENERGY JOURNAL**](https://www.californiaenergytransition.com/p/santa-barbara-denies-permit-transfer?ref=calregulatory.com) - **SCE's $28B Spending Plan Centers on Wildfires, Reliability:** "SCE President and CEO Steven Powell noted that the utility hasn’t seen the same level of demand from data centers as other utilities, but pitched SCE’s more moderate load growth as a potential boon to investors. He expects sales to grow 1% to 3% a year over the next four years, driven primarily by strong electric vehicle adoption, residential growth and increased demand from commercial sectors such as manufacturing, logistics and defense." [**UTILITY DIVE**](https://www.utilitydive.com/news/southern-california-edison-wildfire-earnings/804704/?ref=calregulatory.com) ### FRIDAY AGGREGATE: Resource Adequacy Priorities; Residential Rate-Design Debates; Demand Surges URL: https://www.calregulatory.com/friday-aggregate-resource-adequacy-priorities-residential-rate-design-debates-demand-surges/ Last updated: 2025-12-16T19:58:50.000Z Common themes in today's briefing center on how California will price, plan, and pay for its hyper-ambitious energy transition. - The CPUC's [new Resource Adequacy rulemaking](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K934/583934825.PDF?ref=calregulatory.com) heard from multiple parties, with Slice-of-Day transactability, Unforced Capacity, Loss of Load Expectation, and numerous other key subjects under the microscope. - Debates in SCE's General Rate Case Phase II cover fixed charges and demand-based pricing, with SCE advocating for cost-based electrification tools while [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) and [SEIA](https://seia.org/?ref=calregulatory.com) question legality and customer readiness. [TURN](https://www.turn.org/?ref=calregulatory.com) injects Net Energy Metering disputes into the mix. - A technical skirmish over pre-2019 banked Renewable Energy Credits in SCE's 2026 ERRA Forecast raises the question of whether cost-indifference principles can be rewritten outside of formal policy proceedings. - As planning reports from all three investor-owned utilities confirm that electrification will drive massive grid investment, PG&E is struggling to keep pace with demand surges, which raises serious questions about whether planning cycles can match the speed of California's clean-energy ambitions. ### Parties Provide Initial Responses to New Resource Adequacy Rulemaking Multiple parties filed responses to the CPUC's [Resource Adequacy successor docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K934/583934825.PDF?ref=calregulatory.com), which launched last month. Below are micro-summaries from select parties. - **CAISO**: The CAISO [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273752.PDF?ref=calregulatory.com) the Commission's move toward an [Unforced Capacity](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/resource-adequacy-homepage/workshop-3-caiso%5Fpresentation-track-3b2-ucap-overview.pdf?ref=calregulatory.com)\-based Resource Adequacy framework, and urges updates to storage qualifying capacity calculations to better reflect operational realities. - **CAL ADVOCATES**: Cal Advocates [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K143/586143296.PDF?ref=calregulatory.com) the new rulemaking but urges the Commission to revise its schedule to add formal comment periods for the [Loss of Load Expectation](https://docs.energytransitionmodel.com/main/loss-of-load-expectation/?ref=calregulatory.com) study and its inputs, and to allow more time for stakeholders to respond to party proposals. - **CALIFORNIA COMMUNITY CHOICE ASSOCIATION (CALCCA)**: CalCCA [urges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K043/586043313.PDF?ref=calregulatory.com) the Commission to prioritize fixing [Slice-of-Day](https://www.ascendanalytics.com/blog/californias-slice-of-day-framework-understanding-impacts-on-resource-adequacy-and-resource-value?ref=calregulatory.com) (SOD) transactability in the new RA rulemaking, and to modify the schedule so parties can update proposals after the Energy Division issues its SOD transactability report. CalCCA also asks the rulemaking to (i) include load forecasting, (ii) clarify how Central Procurement Entities should use local RA data, (iii) align Maximum Import Capability rules with SOD, and (iv) address Demand Response/Distributed Energy Resources/microgrid counting. - **PG&E**: PG&E [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834138.PDF?ref=calregulatory.com) the new rulemaking but asks to split Track 1 so most refinements are filed in January 2026 and to delay SOD transactability proposals until after the Energy Division SOD report. PG&E also prioritizes updates to RA compensation data, load-migration rules, self-shown resource remarketing, Demand Response export eligibility, and RA treatment of large load facilities. - **SCE**: SCE [supports](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834123.PDF?ref=calregulatory.com) the successor docket but asks the Commission to expand the scope to include Demand Response accreditation and off-peak import rules. - **TURN**: TURN [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813743.PDF?ref=calregulatory.com) that the CPUC’s Resource Adequacy program must begin accounting for greenhouse gas emissions from capacity resources, as current rules allow load-serving entities to rely on fossil-based reliability resources without any emissions attribution. ### PG&E General Rate Case Phase 2 A new PG&E [motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273785.PDF?ref=calregulatory.com) asks the CPUC to adopt a schedule for the separated Real-Time Pricing (RTP) track of its [General Rate Case Phase II](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M541/K493/541493803.PDF?ref=calregulatory.com). Following an earlier ruling that split RTP into its own track, PG&E proposes a two-step process. - First, PG&E seeks expedited approval of a “Stop-Gap” plan to extend the current Hourly Flex Pricing pilots, which are set to expire on **December 31, 2027**. In PG&E's view, this will ensure that customers continue to have RTP options until the utility’s billing modernization is completed, which is not expected until 2030\. PG&E plans to submit testimony for this Stop-Gap proposal by **January 30, 2026**, aiming for a final CPUC decision by November 2026 so implementation can begin in 2027. - Second, PG&E proposes a longer-term schedule to develop and implement permanent post-pilot RTP rates. This second phase would begin with updated testimony in late 2027, incorporating cost estimates, system upgrades, and lessons from pilot evaluation results and the CPUC’s Enhanced Demand Response rulemaking. PG&E argues that its approach balances administrative efficiency with the need to maintain uninterrupted customers' RTP options. **INSTANT ANALYSIS**: PG&E seems to be saying that full-scale dynamic pricing cannot happen on any timeline but its own. If the CPUC accepts this structure, customers may not see post-pilot RTP rates for several years, underscoring how legacy billing infrastructure is shaping California’s rate-design trajectory as much as regulatory intent. --- ### SCE General Rate Case Phase 2 Parties filed opening briefs in SCE's General Rate Case Phase II ([A.24-03-019](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M528/K409/528409332.PDF?ref=calregulatory.com)) to address three main issues: - SCE’s proposed TOU-D-PRIME Plus rate; - Baseline allowance treatment; and - Transmission marginal costs. SCE [argues](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820188.PDF?ref=calregulatory.com) that its new optional PRIME Plus rate, which features a **$49** fixed charge and on-peak demand charge, better reflects cost causation, supports electrification, and should be approved. [Cal Advocates](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K043/586043301.PDF?ref=calregulatory.com) and [SEIA](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813720.PDF?ref=calregulatory.com) oppose it, arguing the rate misaligns with real grid stress, lacks evidence of customer demand or understanding, and includes non-marginal distribution costs in the fixed charge in violation of law. Both groups argue that existing dynamic rates or volumetric TOU structures are superior. TURN [limits its brief](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K129/586129346.PDF?ref=calregulatory.com) to baseline allowances. TURN urges the Commission to require SCE to include behind-the-meter Net Energy Metering generation in baseline usage calculations. In TURN's view, excluding this solar production artificially lowers measured average usage, leading to reduced baseline allowances that disadvantage non-solar customers. SCE counters that such a change exceeds statutory authority and should be considered in a broader rulemaking. SEIA also presses for adoption of a **$73/kW-year** marginal transmission capacity cost for SCE, using a methodology previously approved for PG&E, while SCE and Cal Advocates say the proposal is premature and outside scope. Cal Advocates further opposes using the [Avoided Cost Calculator](https://www.canarymedia.com/articles/policy-regulation/the-avoided-cost-calculator-the-controversial-metric-at-the-center-of-californias-solar-net-metering-fight?ref=calregulatory.com) to set export credits in the Vehicle-to-Grid settlement. **INSTANT ANALYSIS:** The evolution of this discussion may offer key insights into how far the CPUC might go in shifting residential rate design toward cost-based electrification tools like fixed charges and demand components. SCE is pushing PRIME Plus as a new form of residential pricing (with a higher fixed charge, demand charge, and lower volumetric rates). Cal Advocates and SEIA both argue the proposal is misaligned with real grid stress, is unsupported by customer data, and is potentially unlawful due to the inclusion of non-marginal distribution costs in the fixed charge. TURN injects NEM into the discussion, with another variation of the ongoing [cost-shift](https://www.canarymedia.com/articles/solar/californias-rooftop-solar-is-a-benefit-not-a-cost-to-the-state?ref=calregulatory.com) argument. --- ### SCE ERRA FORECAST In reply briefs for SCE's [2026 ERRA Forecast application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363585.PDF?ref=calregulatory.com), the California Community Choice Association (CalCCA) [defends](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273781.PDF?ref=calregulatory.com) its proposal to value all banked Renewable Energy Credits (RECs), including those generated before 2019, at the Market Price Benchmark (MPB) in the year they are retired. - CalCCA urges the Commission to harmonize REC treatment across all investor-owned utilities, notes inconsistencies in prior ERRA cases, and asserts that its proposal does not create double-charging but simply credits departed customers for their past contributions. CalCCA also states that issues related to its rehearing request for a 2025 decision ([D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com)), which was denied, are now moot. - SCE’s [reply](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472541.PDF?ref=calregulatory.com) strongly opposes CalCCA, arguing that precedent expressly limits REC valuation to post-2018 procurement and supports valuing pre-2019 banked RECs at zero for PCIA purposes. In Edison's view, CalCCA is attempting to rewrite policy in a non-policy setting, which creates double-payment risks for bundled customers, and ignores complexities in REC vintaging and cost allocation. - SCE also asserts that CalCCA’s arguments on RA MPB and retroactive ratemaking improperly attack D.25-06-049\. On rate impacts, SCE argues Power Charge Indifference Adjustment volatility is the result of corrected RA MPB methodology and historical swings have also benefited departing load customers. Last, SCE maintains its October Update corrections to its RA modeling were technical fixes, not policy shifts, and asks the Commission to approve its **$4.689 billion** revenue requirement and associated PCIA and balancing account recovery. **INSTANT ANALYSIS**: The dispute over pre-2019 banked RECs raises the question of whether ERRA is a policy forum and how far the CPUC will stretch “indifference.” CalCCA is pushing the Commission to require utilities to credit the value of older banked RECs to departed customers using current-year MPBs, arguing that this approach simply honors what customers already paid for and should be standardized across IOUs. Edison characterizes this as an attempt to retroactively rewrite PCIA rules, which violates bundled customer indifference, directly contradicts prospective-only REC valuation that the CPUC established in a 2019 decision ([D.19-10-001](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M318/K167/318167258.PDF?ref=calregulatory.com)), and would create double-payment and cost-allocation distortions. The CPUC’s handling of this matter may demonstrate how tightly it intends to police procedural boundaries and the limits of cost neutrality. --- ### DISTRIBUTION PLANNING In our November 5 [Wednesday Aggregate](https://www.calregulatory.com/wednesday-aggregate-transmission-planning-sce-rates-biomethane-costs/), we reported on draft "*Electrification Impacts Study: Part 2*" reports that [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834115.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820156.PDF?ref=calregulatory.com) filed in the CPUC's High DER Future proceeding ([R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com)). The utilities' reports show that electrification will require massive-but-manageable upgrades to the state's distribution grid, with costs that can be partially offset by load growth and demand flexibility. SDG&E also provided [its draft report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K486/586486686.PDF?ref=calregulatory.com). SDG&E's analysis shows that equity scenarios increase infrastructure needs and costs the most, while demand flexibility reduces them by lowering peak loads. --- Separately, PG&E filed its [*2025 Distribution Planning Advisory Group*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [(DPAG)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [*Independent Professional Engineer*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [(IPE)](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com) [*Report*](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K472/586472545.PDF?ref=calregulatory.com). The report evaluates and verifies PG&E’s 2025 Grid Needs Assessment (GNA) and Distribution Upgrade Project Report, which together outline distribution system needs and planned investments for the 2025–2026 Distribution Investment and Deferral Framework cycle. The IPE methodology for reviewing PG&E’s planning includes how the utility forecasts load growth, how it incorporates DERs, how it models circuit-level conditions using [AMI](https://www.ibm.com/think/topics/advanced-metering-infrastructure?ref=calregulatory.com)\-based hourly load profiles, and how it identifies grid deficiencies in capacity, voltage support, reliability, and resiliency. The report notes procedural changes, such as the elimination of deferral solicitations under a 2024 CPUC decision ([D.24-10-030](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M544/K154/544154869.PDF?ref=calregulatory.com)), and highlights that PG&E expanded its planning horizon for GNA to 13 years. The report also summarizes the volume and types of grid needs (over 1,000 total deficiencies), examines planned investments to address them, evaluates PG&E’s known load tracking and forecasting accuracy, and provides recommendations, particularly around tracking pending loads, refining data transparency, and assessing whether planned projects remain necessary as conditions evolve. **INSTANT ANALYSIS**: PG&E is entering a period of accelerated stress, driven by surging load requests and mass electrification. And while its planning tools are improving, PG&E risks running behind real-world demand unless it tightens validation of load materialization, incorporates pending load tracking, and more aggressively confirms whether planned upgrades are still timely and sufficient. --- ### UNION ISLAND PIPELINE Last month, **Administrative Law Judge Jeffrey Lee** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K958/583958837.PDF?ref=calregulatory.com) denying a [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M514/K688/514688334.PDF?ref=calregulatory.com) of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. The PD (which will be considered by the Commission no earlier than **November 20**) finds that CRPC does not currently qualify as a “gas corporation” or “public utility” under California law because it no longer holds valid franchise rights in Antioch and Brentwood (those expired in 2021), and it stopped transporting gas in May 2023. The PD also cites ongoing litigation in which Antioch argues CRPC abandoned its pipeline interests, concluding that CRPC does not own, control, or operate the full pipeline and therefore cannot dedicate it to public use. The PD denies CRPC’s request to substitute a subsidiary into the application and the cities’ request to pause the proceeding, but grants CRPC’s motion to keep financial documents sealed for three years. In response, CRPC has [filed a motion to reopen the record](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273786.PDF?ref=calregulatory.com), arguing that new evidence undermines key findings in the proposed decision. CRPC points to the City of Antioch’s Second Amended Cross-Complaint in related litigation, which acknowledges that CRPC or an affiliate currently owns or controls the Antioch portion of the pipeline. CRPC argues that this directly contradicts the PD's conclusion that it lacks ownership and control and says it could not have submitted the new evidence earlier because the cross-complaint was only received after the CPUC deemed the proceeding submitted on October 10, 2025. **INSTANT ANALYSIS**: CRPC is making a last-minute push to salvage its CPCN request by introducing evidence that appears to contradict one of the PD's foundational determinations. This is a strategic but narrow play by CRPC: while the new cross-complaint from Antioch supports CRPC’s ownership claims, it does not address the other deficiencies cited in the PD (namely, the absence of valid municipal franchise rights and the cessation of gas deliveries since 2023). --- ### CODA Please see recent standalone pieces from CRI: - A seemingly routine electrical upgrade at PG&E's Hinkley Compressor Station has potential to [become a test case](https://www.calregulatory.com/routine-upgrade-or-policy-precedent-pg-es-hinkley-compressor-station-collides-with-general-order-177/) for how California will handle major gas infrastructure investments as the state moves away from fossil fuels. - [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273755.PDF?ref=calregulatory.com) and [SoCalGas/SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820206.PDF?ref=calregulatory.com) filed responses to an Administrative Law Judge ruling in the CPUC's Long-Term Gas Planning docket ([R.24-09-012](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com)), providing detailed cost and operational data on gas distribution infrastructure ([LINK](https://www.calregulatory.com/natural-gas-utilities-submit-detailed-gas-distribution-cost-data/)). ### Routine Upgrade or Policy Precedent? PG&E's Hinkley Compressor Station Collides with General Order 177 URL: https://www.calregulatory.com/routine-upgrade-or-policy-precedent-pg-es-hinkley-compressor-station-collides-with-general-order-177/ Last updated: 2025-12-01T17:32:39.000Z A seemingly routine electrical upgrade at PG&E's Hinkley Compressor Station has potential to become a test case for how California will handle major gas infrastructure investments as the state moves away from fossil fuels. --- On November 3, 2025 a [prehearing conference convened](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834136.PDF?ref=calregulatory.com) for PG&E’s application to obtain a [Certificate of Public Convenience and Necessity (CPCN)](https://en.wikipedia.org/wiki/Certificate%5Fof%5Fpublic%5Fconvenience%5Fand%5Fnecessity?ref=calregulatory.com) for upgrades at the Hinkley station. **Administrative Law Judge Maria Sotero** noted that the case is subject to CEQA and a draft [Mitigated Negative Declaration](https://nevadacountyca.gov/FAQ.aspx?QID=862&ref=calregulatory.com) has already been issued. PG&E stated that the scope is limited to obtaining the CPCN and environmental approval. [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) emphasized that, due to significant project costs and timing prior to an approved General Rate Case, cost reasonableness and affordability must be examined in this proceeding. [TURN](https://www.turn.org/?ref=calregulatory.com) initially raised concerns about need and demand assumptions but withdrew some earlier objections, instead supporting review of project necessity and cost scope. - The parties and ALJ discussed whether cost recovery should be addressed now or deferred to a GRC, with PG&E asserting that while cost estimates and caps fall within CPCN review under [General Order 177](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/administrative-law-judge-division/documents/general-orders/go%5F177%5Fgas%5Finfrastructure.pdf?ref=calregulatory.com),\* actual cost recovery should occur in rate cases. - TURN cautioned against creating a “chicken-and-egg” problem where CEQA approval of only the full-scale project could later preclude authorizing a smaller, less costly alternative. - Both TURN and Cal Advocates also raised concerns over potential stranded assets in light of declining gas demand and state decarbonization goals. TURN later clarified that, based on discovery and technical discussions, it no longer views the project as related to gas throughput capacity,\*\* though broader stranded asset questions remain relevant. ALJ Sotero requested clarity from PG&E on whether any project components are tied to gas throughput or station capacity, suggesting PG&E file supplemental information explaining each equipment component’s purpose and whether it is affected by throughput. PG&E agreed to provide this through a motion to supplement the record. PG&E requested an expedited schedule due to emerging equipment reliability issues at the station and noted it may seek emergency treatment under GO 177 if conditions worsen. Cal Advocates opposed schedule acceleration, arguing for adequate review time. **INSTANT ANALYSIS**: This proceeding could inform how the state will treat major gas investments under GO 177\. It is a platform for serious discussions about cost scope, stranded assets, procedural pace, and whether "throughput-independent" equipment still risks becoming a stranded asset in a declining-gas future. ### FOOTNOTES - **\***GO-177, [which arose in 2022](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K705/499705675.PDF?ref=calregulatory.com), requires gas utilities to obtain a CPCN before building certain large infrastructure projects, although it contains an "emergency exemption." - **\*\***Throughput refers to the volume of natural gas flowing through a pipeline or compressor station over time (i.e., how much gas the facility is transporting or processing). Projects associated with increasing throughput are designed to expand capacity or move more gas; projects considered “throughput-independent” are those needed simply to keep the facility operational, regardless of how much gas flows through it. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4232-1.JPG) ### Natural Gas Utilities Submit Detailed Gas Distribution Cost Data URL: https://www.calregulatory.com/natural-gas-utilities-submit-detailed-gas-distribution-cost-data/ Last updated: 2025-12-01T17:32:56.000Z [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K273/586273755.PDF?ref=calregulatory.com) and [SoCalGas/SDG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820206.PDF?ref=calregulatory.com) (the Sempra Utilities) filed responses to an Administrative Law Judge ruling in the CPUC's Long-Term Gas Planning docket ([R.24-09-012](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M542/K029/542029029.PDF?ref=calregulatory.com)), providing detailed cost and operational data on gas distribution infrastructure. PG&E completed Excel templates covering pipeline replacement, regulator station upgrades, and maintenance for 2021-2024, noting that it often does not track data exactly in the form requested and in some cases had to reformat or estimate based on internal systems. Its filings show average annual pipeline replacement spending of approximately **$653 million**, with average costs of: - **$33,700** per service for main replacement projects; - **$35,000** per service for service-only programs; and - Nearly **$3.9 million** per mile of main replaced. According to PG&E, project planning timelines often exceeded 1,000 days before construction. --- SoCalGas/SDG&E submitted similar datasets, structured according to the same CPUC templates, reporting significantly higher total replacement expenditures: over **$1.26 billion** across four years for SoCalGas alone, and lower maintenance costs per service than PG&E. SoCalGas reported approximately **$22,400** per service under main replacement programs, **$54,800** per service for service-only jobs, and **$2.53 million** per mile of main replaced, with faster planning timelines (392 days for main projects and 107 days for service-only work). SDG&E submitted its cost templates separately as attachments but follow the same methodology. --- All three utilities emphasized that the data are historical, not ratemaking forecasts, and in some cases required adjustments because utility tracking systems do not natively align with the CPUC’s template structure. ### **INSTANT ANALYSIS** These filings confirm how expensive and slow California’s gas-distribution replacement machine has become, and how uneven performance is across utilities. PG&E spent $653 million annually with extended timelines, while SoCalGas had double the total spend but greater throughput, and completed more work at lower per-unit cost and in less time. That contrast may invite scrutiny of whether higher throughput should be rewarded, or whether all such capital spending should be constrained under [Senate Bill 1221](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB1221&ref=calregulatory.com)’s managed-contraction framework. The Commission is now assembling data that provides nominal "apples-to-apples" visibility into the scale of invested capital for the critical infrastructure supporting California’s gas network. That dataset will influence decision-making as the state marches toward a strategic contraction of the network. ### WEDNESDAY AGGREGATE: Transmission Planning; SCE Rates; Biomethane Costs URL: https://www.calregulatory.com/wednesday-aggregate-transmission-planning-sce-rates-biomethane-costs/ Last updated: 2025-12-01T17:33:19.000Z Below are several items on our radar: - The CPUC is mapping hypothetical resource portfolios to physical transmission busbars; - SCE is absorbing a **$932 million** accounting swing from collapsing Resource Adequacy values; - Utilities are reframing electrification as rate stabilization rather than grid stress; - A new distribution framework is about to formalize “least-regrets” early grid buildouts; and - Biomethane policy is forcing a core question: will California socialize gas infrastructure like it did renewables, or are affordability concerns too dire? --- ### INTEGRATED RESOURCE PLANNING **Administrative Law Judge Colin Rizzo** [issued a ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820145.PDF?ref=calregulatory.com) in the Integrated Resource Planning docket inviting parties to submit comments on the preliminary busbar mapping of electricity resource portfolios for use in the CAISO's 2026-2027 Transmission Planning Process. ALJ Rizzo's ruling follows a [September 30 ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M582/K082/582082526.PDF?ref=calregulatory.com) that asked for input on proposed portfolios (a massive number of parties filed October 31 reply comments on that ruling, which are available [here](https://apps.cpuc.ca.gov/apex/f?p=401:57::::::&ref=calregulatory.com)). The current ruling seeks feedback specifically on how resources are being assigned to transmission busbars, a key step in aligning resource planning with transmission needs CPUC staff will host a webinar on **November 12** to explain the preliminary mapping results. Comments on the latest ruling are due **November 21**. **INSTANT ANALYSIS**: The CPUC is moving from abstract resource portfolios into the physical realities of the transmission system, asking parties to weigh in on how planned resources are mapped to specific busbars for the CAISO’s 2026–2027 Transmission Planning Process. That placement determines whether projects are considered deliverable, where grid upgrades are triggered, and who pays for them. With no reply comments allowed and a short fuse (November 21), stakeholders will need to highlight misalignments, push for preferred interconnection assumptions, or defend against siting that might disadvantage their portfolios. In short, this comment opportunity could be a low-profile (but high-leverage) moment where modeling choices start to harden into infrastructure decisions. --- ### SCE RATES SCE filed Advice Letter 5664-E (available [here](https://www.sce.com/regulatory/regulatory-information/advice-letters?ref=calregulatory.com)) to notify the CPUC that its Energy Resource Recovery Account balance exceeded the 4% "Trigger Point" in September 2025 and was expected to exceed the statutory 5% Assembly Bill 57 threshold by October 31 (*SCE filed the advice letter on October 30, FYI*). The trigger was reached because the ERRA and Portfolio Allocation Balancing Account (PABA) balances reflect updated Market Price Benchmarks for retained Resource Adequacy and Renewable Portfolio Standard resources, which were significantly lower than the forecast values that were used to set 2025 rates. As of September 30, SCE's ERRA trigger balance showed an undercollection of **$280 million** (or 4.8% of its 2024 generation revenues), above the trigger level. The primary causes were true-ups tied to final 2025 Market Price Benchmarks: Resource Adequacy benchmark values dropped by 34-72% compared to forecasts, and RPS values fell about 10%, creating large accounting adjustments between the ERRA and the PABA. Notably, SCE does not seek a rate change at this time. It states that the balance will resolve when new 2026 ERRA Forecast rates take effect on **January 1, 2026**, pending a final decision in [A.25-05-008](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363585.PDF?ref=calregulatory.com) (which is expected on **December 18**). Those rates will incorporate the year-end ERRA and PABA balances, eliminating the undercollection. **INSTANT ANALYSIS**: The trigger was caused not by out-of-control spending but by an October 1 true-up to 2025 Market Price Benchmarks (via a steep collapse in Resource Adequacy values, down 34–72% from forecasts), which shifted nearly **$932 million** between ERRA and PABA. This is not rate shock but rather a signal of procurement volatility and accounting whiplash inside SCE’s portfolio. The bet is that once 2026 ERRA rates are implemented, the undercollection will disappear. But if the CPUC misses its December deadline on SCE’s ERRA forecast application, (or balances worsen in during the next several weeks), the situation could result in a trigger application with legitimate rate impacts. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4123.JPG) --- ### DISTRIBUTED ENERGY RESOURCES [PG&E](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K834/585834115.PDF?ref=calregulatory.com) and [SCE](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820156.PDF?ref=calregulatory.com) each filed draft "*Electrification Impacts Study: Part 2*" reports in the CPUC's High DER Future proceeding ([R.21-06-017](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M390/K664/390664433.PDF?ref=calregulatory.com)). The reports show that electrification will require massive-but-manageable upgrades to the state's distribution grid, with costs that can be partially offset by load growth and demand flexibility. - Both utilities model scenarios through 2040 and find total distribution investments of about **$12** to **$13 billion** for SCE and **$23** to **$31 billion** for PG&E. - Secondary system costs (service transformers and new customer connections) make up the majority of future spending, and both utilities note that project volumes must scale five to 10 times above historical levels. The utilities claim that equity scenarios modestly increase costs but do not significantly strain grid infrastructure. - The utilities also claim that demand flexibility (especially when orchestrated at the circuit level) can defer **$1** to **$1.8 billion** in upgrades and cut local peaks by up to 1.4 gigawatts (SCE) or approximately 2.8 GW systemwide (PG&E), while helping keep future rates flat (or even reduce distribution rates by up to 25% by 2040), as electrification spreads fixed costs over more load. Both studies frame electrification not as a grid crisis, but as a logistical and planning challenge requiring faster execution, workforce and supply-chain scaling, and better tools to manage flexible loads. **INSTANT ANALYSIS**: Demand flexibility (electric-vehicle load shifting, storage dispatch, HVAC modulation) is now a genuine capital deferral tool. When applied at the circuit level (not just system peaks), the utilities claim that demand flexibility can shave 1–3 gigawatts off local peaks and defer $1–2 billion in upgrades, but only if it’s “orchestrated,” meaning utilities control it like firm capacity, not voluntary “demand response.” Additionally, utilities are framing electrification not as a threat, but as a rate stabilizer. --- ### DISTRIBUTION PLANNING The CPUC issued [Draft Resolution E-5414](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K850/585850473.PDF?ref=calregulatory.com), which approves with modifications a joint proposal from PG&E, SCE, and SDG&E to implement a uniform scenario planning framework within the annual "*Distribution Planning and Execution Process*," starting in the 2025–2026 cycle. - The framework establishes three standardized load scenarios: low, base, and high, premised on consistent use of [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) forecasts and pending load categories (A–C), to help utilities identify distribution grid needs under varying future conditions. - Utilities would then use these scenarios to inform a single investment plan, guided by a transparent “decision-logic” structure (drawn from SCE’s model) that explains when to advance, defer, or resize projects depending on whether High or Base scenario needs emerge. - The draft resolution rejects fully utility-specific frameworks and instead imposes a common structure across all three investor-owned utilities, while allowing utility-specific implementation details. The draft resolution also requires that all planned projects be tied to a scenario and justified in the "*Distribution Upgrade Project Report*," with utilities reporting grid needs for each scenario in the "*Grid Needs Assessment*" both before and after mitigations. - Draft Resolution E-5414 declines to mandate additional scenarios like demand flexibility or policy compliance in this initial cycle but leaves room to add them later once methodologies mature. The earliest the CPUC will consider this item is **December 4**. **INSTANT ANALYSIS**: This draft resolution formalizes scenario planning in utility distribution planning. Starting in the 2025–2026 cycle, PG&E, SCE, and SDG&E must run Low, Base, and High load scenarios (tied to pending load categories and [IEPR](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com) forecasts) and translate them into asingle investment plan using transparent logic. That means utilities now have formal CPUC backing to plan proactively for electrification-driven load growth but must justify every project by pointing to which scenario (especially High) triggered it, and show how it differs from the Base case. - If adopted, Draft Resolution E-5414 would effectively authorize a “least-regrets” early grid buildout while installing guardrails against overbuilding. Demand flexibility, DER policy compliance, and more aggressive scenarios are deferred to future cycles. - For stakeholders, this is where distribution planning shifts from reactive upgrades to probabilistic infrastructure strategy. Pending load data becomes a capital driver, and early substation and circuit buildouts can now be justified under High Scenario logic, provided they are transparently disclosed. This item pairs well with the pending load frameworks of [Draft Resolution E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K748/585748983.PDF?ref=calregulatory.com), which the CPUC is also scheduled to consider on December 4 (see our summary [here](https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/)). --- ### BIOMETHANE In November 3 reply comments, parties in the CPUC's Biomethane Standards proceeding ([R.13-02-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M050/K674/50674934.PDF?ref=calregulatory.com)) continued to provide input on how to reduce interconnection costs for biomethane projects. Parties largely agree on the need for efficiency and process improvements but diverge over whether ratepayers should bear more of the costs. - **PG&E**: PG&E [acknowledges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813702.PDF?ref=calregulatory.com) that rate-basing interconnections could reduce developer costs by avoiding the federal tax treatment, but warns that shifting these costs to ratepayers requires further analysis to ensure actual customer benefit. PG&E instead emphasizes process improvements e.g., standardized interconnection skid designs, modularization, third-party construction options, and selective deployment of reverse compression. PG&E also notes that many developers face delays unrelated to utility activity, which increase standby costs. - **SoCalGas/SDG&E (Sempra Utilities):** The Sempra Utilities[ support ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813710.PDF?ref=calregulatory.com)allowing utilities to rate-base interconnection facilities, claiming it would eliminate the 24% tax gross-up under federal income tax rules that developers currently pass through in biomethane pricing. SoCalGas/SDG&E argue that rate-basing could lower overall costs without compromising safety, and they also support rate-basing reverse-flow compression equipment to improve system flexibility. At the same time, the Sempra Utilities push back against developers’ criticisms of utility supervisory fees, arguing such oversight is essential for safe construction and compliance with federal and CPUC standards. - **Dairy Cares**: [Dairy Cares](https://www.dairycares.com/?ref=calregulatory.com) [opposes](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K836/585836125.PDF?ref=calregulatory.com) broad rate-basing of interconnection costs but supports expanding the [Biomethane Monetary Incentive Program](https://www.socalgas.com/sustainability/renewable-gas/biomethane-monetary-incentive-program?ref=calregulatory.com) instead. Dairy Cares argues that utilities should only recover interconnection-related costs from ratepayers when a direct, systemwide benefit can be demonstrated under the Public Utilities Code. If rate-basing is expanded, Dairy Cares recommends applying strict cost controls and clear benefit thresholds in a dedicated proceeding. - **Sierra Club**: The Sierra Club [urges](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K129/586129334.PDF?ref=calregulatory.com) the Commission to reject rate-basing and any expansion of subsidies for interconnection or the incentive program. It argues that biomethane is costly, delivers uncertain climate benefits compared to electrification, and relies on finite organic waste resources. Sierra Club stresses that ratepayers could face more than **$1.5 billion** annually in biomethane costs under existing procurement mandates and objects to increasing that burden through interconnection subsidies. Sierra Club also opposes proposals for “backflow” compression investments without rigorous cost-benefit and climate analysis. - **Leadership Counsel for Justice and Accountability (LCJA):** [LCJA ](https://leadershipcounsel.org/?ref=calregulatory.com)[argues ](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813709.PDF?ref=calregulatory.com)strongly against shifting interconnection or related infrastructure costs to ratepayers. LCJA contends that developers (not customers) should continue to pay these expenses, particularly given rising affordability concerns for low-income households. LCJA also opposes expanding non-ratepayer-funded incentives such as the Biomethane Monetary Incentive Program, arguing that limited public funds should instead support decarbonization and affordability programs for low-income customers. **INSTANT ANALYSIS**: The tensions in this proceeding place the CPUC at a pivotal decision point: whether to socialize biomethane infrastructure costs like it did for renewables or to act with abundant caution as serious affordability concerns continue to mount. --- ### CODA Don't miss our recent standalone posts on: - PG&E's [advice letter filings](https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/) for natural gas transportation rates effective **January 1, 2026**; - The [latest twists and turns](https://www.calregulatory.com/ivanpah-officially-in-regulatory-limbo/) with the Ivanpah solar facility; - [Stakeholders' comments](https://www.calregulatory.com/cpuc-proposes-administrative-changes-to-utility-gas-procurement-incentive-mechanisms/) in the CPUC's Natural Gas Price Spike investigation regarding PG&E's Core Procurement Incentive Mechanism and SoCalGas's Gas Cost Incentive Mechanism; and - A [motion](https://www.calregulatory.com/californians-for-green-nuclear-power-file-motion-to-disqualify-alj-in-diablo-canyon-cost-case/) from Californians for Green Nuclear Energy to disqualify the judge in PG&E's latest Diablo Canyon cost-recovery proceeding. Additionally our [Monday Aggregate](https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/) from November 3 covers a new proposed decision in the above-mentioned Diablo Canyon proceeding, SDG&E's proposed natural gas rates for January 1, and more. ### PG&E Files Natural Gas Rate and PPP Surcharge Updates URL: https://www.calregulatory.com/pg-e-files-natural-gas-rate-and-ppp-surcharge-updates/ Last updated: 2025-12-18T16:30:29.000Z PG&E filed [Advice Letter 5139-G](https://www.pge.com/tariffs/assets/pdf/adviceletter/GAS%5F5139-G.pdf?ref=calregulatory.com) to implement its Annual Gas True-Up for natural gas transportation rates effective **January 1, 2026**. The filing reconciles balances in various transportation balancing accounts for core and noncore customers, updates revenue requirements, and projects 2026 transportation Public Purpose Program (PPP) surcharge revenues. PG&E estimates a total 2026 gas transportation revenue requirement of **$5.96 billion**, which is a slight decrease from current levels. This includes higher end-use transportation and storage costs but a significant reduction in PPP surcharge revenue needs. PG&E projects an overall **$208 million** undercollection across its gas transportation balancing accounts by the end of 2025, which it seeks to amortize in 2026 rates. Major drivers of account balances include undercollections in the Core Fixed Cost Account, overcollections in noncore accounts, [Assembly Bill 32 ](https://ww2.arb.ca.gov/resources/fact-sheets/ab-32-global-warming-solutions-act-2006?ref=calregulatory.com)implementation fees, hazardous substance cleanup costs, wildfire mitigation-related adjustments, and cost adjustments from other proceedings such as cost-of-capital, Advanced Metering Infrastructure, and wildfire cost recovery decisions. A separate filing in late December will consolidate final authorized revenue requirements and updated balancing account forecast. Protests are due **November 20**. **INSTANT ANALYSIS**: Per PG&E's outlook, core residential and small commercial customers will see modest decreases, largely due to lower Public Purpose Program surcharges. Industrial and electric generation customers may receive deeper reductions (–8% to –17%) as PG&E amortizes undercollections and resets balancing account recoveries. As with previous years, a separate PG&E filing in December will finalize revenue requirements and balancing account forecasts (and modify many of these projections). PG&E - January 1, 2026 Average End-User Natural Gas Transportation Rates and PPP Surcharges ($/th) | | Sept 2025 | Jan 2026 | Change | | | | | | -------------------------- | --------- | -------- | ------ | ----- | ------ | ----- | ------- | | | Trans | G-PPPS | Total | Trans | G-PPPS | Total | % | | RETAIL CORE | | | | | | | | | Residential Non-CARE | 2.261 | .143 | 2.404 | 2.244 | .121 | 2.366 | \-1.6% | | Small Commercial Non-CARE | 1.483 | .128 | 1.612 | 1.437 | .106 | 1.544 | \-4.2% | | Large Commercial | .924 | .104 | 1.028 | .855 | .085 | .940 | \-8.6% | | NGV1 (uncompressed) | .975 | .062 | 1.037 | .908 | .048 | .956 | \-7.8% | | NGV2 (compressed) | 2.618 | .062 | 2.679 | 2.572 | .048 | 2.620 | \-2.2% | | RETAIL NONCORE | | | | | | | | | Industrial Distribution | .800 | .153 | .953 | .665 | .128 | .794 | \-16.7% | | Industrial Transmission | .408 | .082 | .490 | .372 | .066 | .438 | \-10.6% | | Industrial Backbone | .163 | .082 | .245 | .139 | .066 | .205 | \-16.1% | | Electric Gen: Transmission | .410 | \-- | .410 | .377 | \-- | .377 | \-8.1% | | Electric Gen: Backbone | .177 | \-- | .177 | .153 | \-- | .153 | \-13.9% | | NGV4 Dist (uncompressed) | .800 | .062 | .862 | .665 | .048 | .714 | \-17.2% | | NGV4 Trans (compressed) | .394 | .062 | .456 | .361 | .048 | .410 | \-10.1% | | WHOLESALE CORE & NONCORE | | | | | | | | | Alpine Natural Gas | .265 | \-- | .265 | .292 | \-- | .292 | +10.2% | | Coalinga | .266 | \-- | .266 | .294 | \-- | .294 | +10.3% | | Inland Energy | .283 | \-- | .283 | .314 | \-- | .314 | +10.8% | | Palo Alto | .260 | \-- | .260 | .287 | \-- | .287 | +10.1% | | West Coast Gas – Castle | .717 | \-- | .717 | .635 | \-- | .635 | \-11.5% | | WC Gas – Mather Dist | 1.032 | \-- | 1.032 | .869 | \-- | .869 | \-15.8% | | WC Gas – Mather Trans | .268 | \-- | .268 | .296 | \-- | .296 | +10.3% | _This post is for paying subscribers only._ ### Group Files Motion to Disqualify ALJ in Diablo Canyon Cost Case URL: https://www.calregulatory.com/californians-for-green-nuclear-power-file-motion-to-disqualify-alj-in-diablo-canyon-cost-case/ Last updated: 2025-12-01T17:33:55.000Z Earlier today, [Californians for Green Nuclear Power](https://cgnp.org/?ref=calregulatory.com) (CGNP) filed a [motion](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K815/585815625.PDF?ref=calregulatory.com) requesting the disqualification of [**Administrative Law Judge Jack Chang**](https://www.usfca.edu/faculty/jack-chang?ref=calregulatory.com) from PG&E's latest Diablo Canyon cost-recovery application (A.25-03-015). - CGNP argues that ALJ Chang has demonstrated bias and a lack of impartiality through several procedural decisions that harmed ratepayers and undermined grid reliability. - CGNP points specifically to ALJ Chang's denial of two CGNP motions (both submitted a day late), including one seeking to amend the scoping memo to enable payments to Diablo Canyon for providing synchronous [grid inertia](https://greennuke.substack.com/p/why-is-grid-inertia-important), a service CGNP says is critical for preventing such blackout events as the fatal Iberian Peninsula outage in April 2025. - CGNP claims that three denials blocked them from submitting direct testimony on synchronous grid inertia and from receiving intervenor compensation. CGNP also calls into question ALJ Chang's judicial temperament with a claim that Chang demonstrated discourteous behavior during a July 2025 site tour of the Diablo Canyon facility. CGNP's **Gene Nelson** cites his own [October 20, 2025 comments](http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K704/584704035.PDF?ref=calregulatory.com) in this proceeding, which note: > I have concerns that Dr. Chang brings an apparent bias against nuclear power advocates such as myself (which perhaps extends to opposing Diablo Canyon extended operations) into this proceeding. During July and August, 2025, he denied a pair of CGNP's motions while ignoring CGNP's July 11, 2025 Motion to Amend the Scoping Memo. Supporting my contention, I've appended Dr. Chang's self-written LinkedIn resume with some annotations. > His highlights at the top of his resume include "Administrative Law Judge," "Renewable Hydrogen," and "Solar Development." I also include a reference to Dr. Chang's [solar power advocacy article from August, 2019 ](https://www.pv-tech.org/wp-content/uploads/legacy-publication-pdfs/2de94901db-initiatives-for-california-to-overcome-its-challenges-in-the-sun.pdf?ref=calregulatory.com)written while he served as a Market Research and Energy Policy Intern for Strategen. I believe it is a conflict of interest to have a self-described renewable energy advocate serve as a CPUC ALJ for the Diablo Canyon 2026 Cost Proceeding. Dr. Chang should have recused himself from this assignment. CGNP formally asks the CPUC to remove ALJ Chang from the proceeding. **INSTANT ANALYSIS**: While this motion is procedurally doomed and highly unlikely to result in the ALJ's disqualification, it nevertheless gives CGNP another procedural tool to elevate deeper disputes regarding grid inertia, nuclear reliability compensation, and perceived ideological leanings within the regulatory process. ### CPUC Proposes Administrative Changes to Utility Gas Procurement Incentive Mechanisms URL: https://www.calregulatory.com/cpuc-proposes-administrative-changes-to-utility-gas-procurement-incentive-mechanisms/ Last updated: 2025-12-01T17:34:12.000Z As part of the CPUC's investigation into the causes and consequences of the Winter 2022-2023 natural gas price spike ([I.23-03-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M503/K823/503823381.PDF?ref=calregulatory.com)), Commission staff recently issued "[White Paper Part II](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K485/585485854.PDF?ref=calregulatory.com)." The paper focuses on how the utilities' gas procurement incentive mechanisms (PG&E's **Core Procurement Incentive Mechanism**, or CPIM, and SoCalGas's **Gas Cost Incentive Mechanism**, or GCIM) performed during the crisis. - The paper expands the CPUC's investigation, examining whether storage practices, **Independent Storage Provider** (ISP) contracts, and gas-electric market interactions contributed to extraordinary price volatility. Staff concludes that storage withdrawals generally aligned with cold-weather demand rather than with price-driven market withholding, and that inventories across PG&E, SoCalGas, and ISPs declined significantly over the winter. However, according to the paper, questions remain about whether ISPs operate within a competitive market environment (particularly as PG&E’s core procurement department is mandated to procure large volumes of storage from them). - The paper also finds that high gas prices, particularly in December 2022, directly translated into higher electricity prices in the CAISO's markets, given the reliance on gas-fired generation as the marginal price-setting resource. Wholesale market costs soared from $12.6 billion in 2021 to **$21.6 billion** in 2022, leading to noticeable increases in retail bills for PG&E and SCE customers. The paper says that statistical modeling confirms a strong correlation (over **0.9**) between gas and electricity prices in both northern and southern California service territories, while also showing that volatility during Winter 2022–23 was the highest in recent years. Major stakeholders recently filed comments offering varying degrees of support, criticism, and alternative policy proposals. Their positions are summarized below. ### [**PG&E**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K836/585836114.PDF?ref=calregulatory.com) PG&E agrees with Staff’s conclusions that its hedging activities and the CPIM did not contribute to gas price spikes. PG&E's supports the paper's three administrative recommendations: 1. Filing a Tier 1 advice letter to clarify CPIM details in its tariffs (*a Tier 1 filing takes effect immediately upon submission and used for routine matters*); 2. Aligning approval processes for shareholder awards across utilities via Tier 2 advice letter (*a Tier 2 filing does not take effect until CPUC staff reviews it*); and 3. Establishing a fixed annual filing deadline for CPIM reports. PG&E also clarifies that any savings from sales at the citygate or border were due to optimization of contracted physical capacity (not speculative trading) and emphasizes that financial hedges reduced costs for core customers. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4223.JPG) ### [**The Utility Reform Network (TURN)**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K813/585813699.PDF?ref=calregulatory.com) TURN supports Staff’s recommendations and underscores that procurement incentive mechanisms significantly affect ratepayer costs because PG&E and SoCalGas are among the largest gas purchasers in the West. TURN argues for greater alignment and transparency between the CPIM and GCIM, calling both mechanisms overly complex and lacking synchronization in reporting timelines. TURN also notes that hedging lowered customer costs (especially PG&E’s financial hedges, which offset high gas prices) and supports Staff’s proposals to clarify tariff descriptions and standardize oversight, but believes deeper reforms may require a new CPUC proceeding. ### [**SoCalGas**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820168.PDF?ref=calregulatory.com) SoCalGas supports the three administrative recommendations but defends the effectiveness of the GCIM, stating that it is transparent, timely, and already includes an established shareholder award process through application rather than advice letter. SoCalGas agrees to improve tariff descriptions but argues that broader changes to procurement incentives should be taken up in a future proceeding. ### [**Sierra Club**](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M586/K143/586143248.PDF?ref=calregulatory.com) Sierra Club takes the strongest position, arguing that the incentive mechanisms are fundamentally “broken.” It notes that SoCalGas has received shareholder rewards every year for decades without ever paying a penalty, even during periods of high customer bills. Sierra Club urges the CPUC to suspend shareholder rewards immediately and replace the current incentive structures with a fuel-cost-sharing mechanism that better aligns with state climate policy and ratepayer interests. If replacement is not immediate, Sierra Club recommends at least a moratorium on shareholder rewards until a future proceeding reexamines the mechanisms ### **INSTANT ANALYSIS** The white paper's recommended moves wouldn't change how utilities profit from gas purchasing yet but they might enhance transparency and set the stage for a new battle. TURN and Sierra Club are already pushing for deeper reform (or even a suspension of utility rewards). CPUC staff indicates that anything beyond the paper's recommended procedural fixes will require a new phase, or an altogether new proceeding. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4221.JPG) ### Ivanpah Officially in Regulatory Limbo URL: https://www.calregulatory.com/ivanpah-officially-in-regulatory-limbo/ Last updated: 2025-12-01T17:34:29.000Z The CPUC issued [Draft Resolution E-5429](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M586/K132/586132670.PDF?ref=calregulatory.com), which rejects (without prejudice) PG&E's [request](https://www.pge.com/tariffs/assets/pdf/adviceletter/ELEC%5F7485-E.pdf?ref=calregulatory.com) to terminate its Power Purchase Agreements with Solar Partners II and VIII, the owners of the Ivanpah Solar Electric Generating Station. PG&E had sought approval to pay the project owners to end the contracts early, arguing this would reduce costs for ratepayers by removing uneconomic renewable contracts from its portfolio under the CPUC's [Voluntary Allocation and Market Offer](https://avaenergy.org/wp-content/uploads/2022/05/4%5FVoluntary%5FAllocation%5Fand%5FMarket%5FOffer%5FVAMO%5FPresentation%5FDraft%5Fq7p7o3.pdf?ref=calregulatory.com) process. The U.S. Department of Energy supported PG&E's request, noting it would help repay the remaining **$1.6 billion** federal loan and potentially make way for redevelopment of the Ivanpah site with newer, lower-cost technologies. (*The loan in question refers to a federally guaranteed financing package, i.e., private lender money backed by the DOE, which was used to build Ivanpah and has not been fully repaid.*) However, Draft Resolution E-5429 concludes that approving the contract terminations now would pose unacceptable risks. The draft resolution finds the agreements were developed through a fair procurement process and aligned with PG&E's renewable portfolio needs. The draft resolution argues that recent shifts in federal policy (e.g., the rollback of clean energy tax credits, new tariffs on imported equipment, and changes to land-use rules for solar and wind projects) create substantial uncertainty about whether new renewable resources will be built in time to replace Ivanpah's capacity. This uncertainty, the draft resolution holds, threatens grid reliability at a time when California faces rising electricity demand from electrification, data centers, and hydrogen development. Additionally, the draft resolution notes that ratepayers have already funded more than **$333 million** in transmission infrastructure to support Ivanpah, and terminating the contracts now, without a concrete replacement project, risks stranding those investments. In the CPUC's view, this risk potentially outweighs the savings PG&E estimates from the contract buyouts. By denying PG&E's request without prejudice, the draft resolution leaves the door open for PG&E to resubmit termination agreements in the future if there is a clear replacement plan (or greater certainty about resource development). In the meantime, if Ivanpah defaults on its obligations, PG&E retains the ability to terminate the contracts without paying compensation. The earliest the CPUC will consider this item is **December 4**. ## **INSTANT ANALYSIS** This draft resolution quietly confirms what’s been implied for a long time: Ivanpah isn’t being kept alive because it’s successful, it’s being kept alive because the state is worried about losing megawatts and leaving federally guaranteed debt stranded. In short, PG&E asked for permission to pay off and terminate its PPAs for two of Ivanpah’s three units (Southern California Edison is said to be [in discussions](https://energynewsbeat.co/ivanpah-solar-project-in-california-to-shut-down-costing-2-2-billion-with-no-land-reclamation-finalized/?ref=calregulatory.com) that could lead to the third unit’s closure). This request was backed by the DOE, which still has outstanding loan-guaranteed financing on the project. DOE anticipated that termination would accelerate loan repayment and potentially clear the site for redevelopment with new technologies. But the CPUC's draft resolution reads as a quasi-confession of the following points. - Under California’s very own policy conditions, grid reliability has become too fragile to remove *any* existing/politically-permissible generation (even expensive, underperforming generation). - California’s dogged adherence to its own policy (and its staunch refusal to harmonize with shifting federal policy, even slightly) makes the prospect of replacement resources uncertain. Which leaves the following policy contortion: Ivanpah is too uneconomic to keep, but too risky to kill. ### MONDAY AGGREGATE: Diablo Canyon; Distribution Planning; SDG&E's 2026 Natural Gas Rates and PPP Surcharge URL: https://www.calregulatory.com/monday-aggregate-diablo-canyon-distribution-planning-sdg-es-2026-natural-gas-rates-and-ppp-surcharge/ Last updated: 2025-12-01T17:34:49.000Z Here is what's on our Monday radar. (*For a full review of last week's CPUC voting meeting, go* [*here*](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/)*.*) Today's items present a microcosm of California’s reliability strategy and how it's running on multiple tracks simultaneously: extending nuclear baseload at Diablo Canyon, mapping new load before it arrives (distribution planning), and cautiously testing new financing mechanisms for electrification. ## DIABLO CANYON COST RECOVERY **Administrative Law Judge Chang** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K820/585820128.PDF?ref=calregulatory.com) approving PG&E's request to recover **$382.233 million** in 2026 customer rates to support the continued operation of the Diablo Canyon Power Plant under the extension authorized by [Senate Bill 846](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-are-nuclear-electric-cost/senate-bill-846?ref=calregulatory.com#:~:text=As%20directed%20by%20SB%20846,%2C%202030%20%28Unit%202%29.&text=PG%26E%20has%20operated%20Diablo%20Canyon,Luis%20Obispo%20County%2C%20since%201985.) and prior CPUC decisions. The authorized revenue requirement reflects forecasted operations and maintenance costs, statutory fees, nuclear fuel, and required substitution capacity for planned outages, offset by market revenues from power sales. Costs are allocated across the service territories of PG&E, SCE, and SDG&E. The PD continues the regulatory framework established in a 2023 decision ([D.23-12-036](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M521/K496/521496276.PDF?ref=calregulatory.com)), which authorized Diablo Canyon Power Plant operations until 2029/2030 pending federal license approvals. The PD also incorporates directives from later decisions requiring PG&E to justify costs and differentiate clearly between: - "Transition" or preparatory costs paid by government funding (e.g., the SB 846-authorized **$1.4 billion** state loan); and - Extended operation costs recoverable from ratepayers. The PD finds PG&E's 2026 O&M forecast (totaling **$563.9 million**) to be reasonable but directs PG&E to provide more detailed justification for any projects over **$1 million** in future filings. - The PD also approves statutory payments required under SB 846, including **$113.97 million** in Fixed Management Fees; **$266.566 million** in Volumetric Performance Fees; and **$75 million** for a liquidated damages fund, which protects ratepayers against unreasonable outage replacement power costs. - The PD also adopts PG&E's proposed methodology to escalate the Fixed Management Fee using the Consumer Price Index (CPI-U) rather than the electricity capital cost index previously used, finding the CPI-U more stable and appropriate for a non-capital payment. Last, the PD approves PG&E's calculated non-bypassable charge to recover net Diablo Canyon Power Plant costs from all customers, including those served by Community Choice Aggregators and Direct Access providers. PG&E forecasts a slight reduction in average system rates in 2026 (but only net of high expected market revenues and full facility availability). Comments on this item are due **November 20**. The earliest the CPUC will consider the PD is **December 4**. **INSTANT ANALYSIS**: The CPUC is institutionalizing Diablo Canyon's extended life as a cost-managed reliability asset. Rate impacts appear to be minimal (*under PG&E's assumptions of high market revenues and full facility availability*) and the non-bypassable charge remains intact. For CCAs, DA providers, and large customers, Diablo Canyon costs are becoming an embedded part of the rate landscape. --- ## DISTRIBUTION PLANNING The CPUC issued [Draft Resolution E-5413](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K748/585748983.PDF?ref=calregulatory.com), which approves with modifications a joint proposal submitted by PG&E, SCE, and SDG&E to create a "pending loads" category in the utilities' distribution planning process. This new process would capture anticipated (but not-yet-certain) electrical demands (more specific than statewide forecast trends, but less certain than formal service requests). The draft resolution aims to improve medium-term distribution grid planning (years two through five), allowing utilities to proactively identify where load growth is likely to occur so upgrades can be planned in advance without unnecessary overbuilding. The draft resolution implements a uniform, four-hour tier framework statewide (based largely on Edison's proposal but using PG&E's detailed criteria), which classifies pending loads based on data quality and confidence: - **Category A:** High-confidence, customer-driven projects with specific load, location, timeline, and permit data (these may exceed the [Integrated Energy Policy Report](https://www.energy.ca.gov/data-reports/reports/integrated-energy-policy-report-iepr?ref=calregulatory.com), or "IEPR," forecast); - **Category B1**: Medium-confidence customer projects (also allowed to exceed the IEPR forecast); - **Category B2**: Study-based or regulatory-driven load projections using customer-related data (cannot exceed the IEPR unless located in a "hot spot"); and - **Category C**: Low-confidence early-stage projects or general studies (may only assist in disaggregating IEPR forecasts, never exceed them). Draft Resolution E-5413 also formally defines hot spots (geographic areas with multiple pending or known loads and infrastructure constraints) and allows certain Category B2 load forecasts in these areas to exceed the IEPR cap to support proactive grid investments. Utilities must identify and justify these hot spots annually in their [Grid Needs Assessment](https://www.pge.com/assets/pge/docs/about/doing-business-with-pge/GNA.pdf?ref=calregulatory.com) and [Distribution Upgrade Project Report](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M576/K519/576519221.PDF?ref=calregulatory.com) filings and report all pending loads by category, location, projected in-service year, and data source. While Draft Resolution E-5413 allows utility-specific data sources, it requires PG&E, SCE, and SDG&E to adopt the same structure, criteria, and reporting standards beginning in the 2025-2026 planning cycle. SDG&E, which initially proposed only using medium-/heavy-duty vehicle electrification forecasts, must incorporate customer-based pending load data similar to PG&E and SCE. Last, the draft resolution strengthens oversight and reporting, requiring annual updates, standardized data tracking, and a formal evaluation in 2027 on how many pending loads became actual service requests plus timing accuracy and risk mitigation where loads do not materialize. The earliest the Commission will consider this item is **December 4**. **INSTANT ANALYSIS**: If adopted, this draft resolution would help modernize the CPUC's planning toolkit for the age of data centers and electrified infrastructure. While the draft resolution doesn't greenlight spending, it builds the process for a more transparent, anticipatory grid-planning regime. Future money will likely move first in Categories A and B1, because those are the early indicators of where utilities will break ground and where developers and large customers will be expected to co-invest or align. --- ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/IMG_4224.JPG) ## SDG&E NATURAL GAS RATES for JANUARY 1, 2026 SDG&E filed Advice Letter 3463-G (available [here](https://tariffsprd.sdge.com/sdge/filings/?utilId=SDGE&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to update its natural gas transportation rates effective January 1, 2026\. - For core customers, SDG&E proposes a net **$12.3 million** decrease, driven mainly by a reduction in a Core Fixed Cost Account undercollection, partially offset by increases in SDG&E's Safety Enhancement Capital Cost Balancing Account and Residential Uncollectible Balancing Account. - For noncore customers, SDG&E seeks a **$7.5 million increase**, primarily due to undercollections in the Residential Uncollectible, Safety Enhancement, and Greenhouse Gas Balancing accounts. Overall, total gas transportation revenue requirements would rise by **$4.1 million** (**0.5%**), translating to a **0.4%** increase for core customers and a **2.9%** increase for noncore customers. SDG&E will file a final version of its request prior to January 1 that consolidates all authorized revenue-requirement changes. Protests are due **November 20**. Below are illustrative rates in $/therm. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/rates-deluxe.png) --- ## SDG&E PUBLIC PURPOSE PROGRAM RATES SDG&E also filed Advice Letter 3462-G (available [here](https://tariffsprd.sdge.com/sdge/filings/?utilId=SDGE&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to update its Public Purpose Program (PPP) gas surcharge rates, which fund state-mandated programs e.g., low-income assistance, energy efficiency, and research & development. SDG&E's updated surcharge rates will take effect January 1, 2026\. SDG&E proposes to increase PPP revenue recovery to $85.9 million (up about $10.2 million from 2025). Major cost drivers include: - **$23.6 million** for the [California Alternate Rates for Energy](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com) (CARE) low-income discount program; - **$15.1 million** for the [Energy Savings Assistance](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/energy-savings-assistance?ref=calregulatory.com) program; - Approximately **$30.8 million** for energy efficiency; - **$14.4 million** for a new [San Diego Regional Energy Network](https://sdcommunitypower.org/programs/ren/?ref=calregulatory.com); - **$1.2 million** for RD&D; - **$0.7 million** for a statewide Market Transformation program; and - **$0.1 million** CPUC and California Department of Tax and Fee Administration costs. Below are the anticipated changes. Protests to this filing are due **November 20**. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/11/PPP-Deluxe2.png) ## CLEAN-ENERGY FINANCING **Administrative Law Judge Toy** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K815/585815581.PDF?ref=calregulatory.com) that approves with modifications a Tariff On-Bill financing pilot advanced by SCE. The PD rejects similar proposals from SDG&E, SoCalGas, and Silicon Valley Clean Energy. The [Tariff On-Bill concept](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-expands-on-bill-financing-options-for-non-residential-energy-utility-customers-2023?ref=calregulatory.com) allows customers to install clean-energy upgrades (e.g., heat pumps and efficiency measures) with no upfront cost, paying instead through a fixed charge on their utility bill tied to the property, not the individual. The PD finds Edison's proposal to be the only one sufficiently developed to test this model. The PD limits participation to approximately 200 residential sites and requires bill neutrality (meaning customers' total bills must not increase as a result of participating). The PD adds further customer protections, savings verification requirements, and reporting rules. PG&E did not propose a pilot. The rejected proposals had design flaws or did not align with CPUD directives. Comments on this item are due **November 20**. The earliest the CPUC will consider this item is **December 4**. **INSTANT ANALYSIS**: This PD is a cautious green light, not a broad endorsement. If SCE's pilot demonstrates real savings, low defaults, and manageable administrative costs, tariffed on-bill financing could become a new cost-recovery tool for electrification, especially for households that can't access credit or capital. --- ## MID-TERM RELIABILITY The CPUC issued [Draft Resolution E-5428](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K052/584052019.PDF?ref=calregulatory.com), which authorizes SCE's request to enter eight new Mid-Term Reliability resource contracts and one amendment to an existing battery storage contract. These agreements arose from Phases [2](https://www.sce.com/about-sce/energy-procurement/solicitations/2022-mr-rfo?ref=calregulatory.com) and [3](https://www.sce.com/about-sce/energy-procurement/solicitations/2023-mr-rfo?ref=calregulatory.com) of Edison's Mid-Term Reliability Request for Offers and include a mix of solar photovoltaic projects and co-located (or standalone) Battery Energy Storage Systems. These projects were developed by [EDF Renewable Energy](https://www.edf-re.com/?ref=calregulatory.com), [Intersect Power](https://www.intersect.com/?ref=calregulatory.com), and [Leeward Renewable Energy ](https://www.lreus.com/?ref=calregulatory.com)and will provide renewable energy, Resource Adequacy capacity (or both), with contract terms ranging from 10 to 15 years, and expected online dates beginning in 2026 and 2027. Draft Resolution E-5428 also approves an amendment to the [Gateway battery storage contract](https://www.powermag.com/worlds-largest-for-now-battery-storage-project-online-in-california/?ref=calregulatory.com) to extend its delivery deadline following a 2024 thermal incident at the facility that the CPUC and EPA are currently investigating. These contracts count toward Edison's procurement obligations under the CPUC's original "mid-term reliability" decision ([D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com)) and a supplemental procurement decision ([D.23-02-040](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M502/K956/502956567.PDF?ref=calregulatory.com)) that arose when the state was experiencing a reliability gap in the middle of this decade due to: - The retirement of gas plants and the (since-reversed) decommissioning of the Diablo Canyon Power Plant; - Delays in new clean resources due to supply-chain problems and other issues; and - The need to bridge the system from now through the realization of long-term decarbonization goals. The earliest the Commission will consider this item is **November 20**. Contract costs are confidential. **INSTANT ANALYSIS**: These contracts strengthen SCE's compliance posture but they also highlight how dependent California's reliability strategy has become on large-scale solar-plus-storage procurement. The Gateway extension is a reminder that battery safety and operational risk are now serious reliability variables, not edge cases. ### CRI Now Available as a LinkedIn Newsletter URL: https://www.calregulatory.com/cri-now-available-as-a-linkedin-newsletter/ Last updated: 2025-11-01T18:50:23.000Z We are rolling out occasional CRI content on LinkedIn. See [embedded link](https://www.linkedin.com/pulse/results-october-30-2025-cpuc-voting-meeting-michael-cade-fse4c?ref=calregulatory.com) below to subscribe. You can also follow us on [X](https://x.com/calregulatory?ref=calregulatory.com) and [Blue Sky](https://bsky.app/profile/calregulatory.bsky.social?ref=calregulatory.com). ### WEEKEND NEWS CODEX: Energy Budgets Cut; STACK/PG&E Agreement; Edison Trims CapEx Forecast URL: https://www.calregulatory.com/weekend-news-codex/ Last updated: 2025-12-01T17:35:23.000Z Some energy links for weekend reading. - **An Introduction to Carbon Pricing**: "For many carbon pricing advocates, the use of revenue raised by the pricing mechanism is of secondary concern to the price itself, though the use of revenue is also very important. Broadly speaking, there are two main options. The first is for activities related to greenhouse gas mitigation, such as clean energy research, development, and deployment. Most proceeds from California’s cap and trade program, for instance, to go the [Greenhouse Gas Reduction Fund](https://ww2.arb.ca.gov/our-work/programs/california-climate-investments/california-climate-investments-funded-programs?ref=calregulatory.com), which in turn funds various emissions reduction programs. [According](https://lao.ca.gov/Publications/Report/4811?ref=calregulatory.com) to the California Legislative Analyst Office, the largest outlay of funds from the Greenhouse Gas Reduction Fund from 2013 (when it started) to 2023 (the date of the cited source) has been for the high speed rail, which is statutorily required to receive at least 25% of the funds. Now that is a whole other blog post. The other option is some kind of revenue recycling." [**Michael Goff**](https://goff.substack.com/p/an-introduction-to-carbon-pricing) - **California Slashes Energy Agency Budgets Due to Deficit:** "Environmental protection expenditures for CARB shrank from $2.5 billion in 2023-2024 to $1.4 billion in 2024-2025 to the new budget’s $956 million. Similar cuts were made to State Water Resources Control Board allocations—to $1.9 billion in the current budget from $2.7 billion in 2023-2024\. 'Efficiency reductions' in state operations and vacancies are listed at $25.4 million for CARB and $12 million for the California Energy Commission. The CEC’s budget includes $1.4 billion from special funds and federal funds, again down significantly from CEC’s estimated prior-year expenditure level of $2.8 billion. This was largely due to the expiration of one-time funding, the \[Legislative Analyst's Office\] said." [**California Energy Markets**](https://www.newsdata.com/california%5Fenergy%5Fmarkets/bottom%5Flines/california-slashes-energy-agency-budgets-due-to-deficit/article%5F76f6d45b-c7fe-46db-98b4-5bcabf3d6296.html?ref=calregulatory.com) - **CPUC Approves Agreement Between PG&E, STACK to Facilitate New Data Center:** "Under the agreements, STACK will design, procure and construct a new switching station that is needed to support the large load associated with the planned data center. Once completed, STACK will transfer ownership of the Ringwood Switching Station to PG&E. The switching station is anticipated to be operational by April 2026\. STACK will pay the upfront costs associated with connecting to the grid, but those costs could later be refunded once the data center generates sufficient revenues. The estimated cost for the switching-station project is $85.9 million." [**California Energy Markets** ](https://www.newsdata.com/california%5Fenergy%5Fmarkets/regulation%5Fstatus/cpuc-approves-agreement-between-pg-e-stack-to-facilitate-new-data-center/article%5F7db4fc81-5097-40bc-912e-56bf9ca3b2b6.html?ref=calregulatory.com) - **Discerning What Drives Rate Increases is More Complex Than Shown in LBLN Study:** "The renewables policy team at Lawrence Berkeley National Laboratory released [a study](https://www.sciencedirect.com/science/article/pii/S1040619025000612?ref=calregulatory.com#bib40) maintaining that it identifies the primary drivers of rate increases in the U.S...This time the authors may have stretched a bit too far. Unfortunately this study is much more about correlation than causality." [**Economics Outside the Cube**](https://mcubedecon.com/2025/10/21/discerning-what-drives-rate-increases-is-more-complex-than-shown-in-lbnl-study/?ref=calregulatory.com) - **Edison International Trims Capex Forecast After Rate Case:** "Executives of Edison International Inc., the parent company of Southern California Edison, have lowered the top end of their four-year capital spending plan forecast by $3 billion while lifting the floor of the rate base growth range they expect. The capex update from President and CEO **Pedro Pizarro** and CFO **Maria Rigatti** came shortly after California regulators approved Edison International’s latest general rate case and alongside third-quarter results, which showed [a net profit of $888 million, up from $577 million in the same period of last year](https://download.edison.com/406/files/202510/20251028-news-release.pdf?ref=calregulatory.com), on operating revenues of more than $5.7 billion. Edison’s leaders now expect they’ll spend between $28 billion and $29 billion from this year through 2028 versus their previous guidance of $27 billion to $32 billion. The revised plan trims the company’s projected spending growth each year of the plan, including a $700 million drop this year to $6.8 billion." [**Transmission & Distribution World** ](https://www.tdworld.com/utility-business/news/55326738/edison-international-trims-capex-forecast-after-rate-case?ref=calregulatory.com) - **ExxonMobil Challenges California Climate Reporting Laws on Speech Grounds:** "ExxonMobil is challenging California’s greenhouse gas emissions reporting laws as a violation of the company’s right to free speech. The company is asking the court to block implementation of [SB 253](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB253&ref=calregulatory.com) and [SB 261](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202320240SB261&ref=calregulatory.com), scheduled to take effect in 2026\. Exxon [filed the lawsuit](https://www.courtlistener.com/docket/71751076/exxon-mobil-corporation-v-sanchez/?ref=calregulatory.com) in the U.S. District Court for the Eastern District of California on October 24, 2025." [**California Energy Journal**](https://www.californiaenergytransition.com/p/exxonmobil-challenges-california?ref=calregulatory.com) - **Making Energy Emissions More Transparent – CAISO's Accounting and Reporting Approach:** "When you flip on a light switch, you likely don’t think about where the electricity comes from—or its climate impact. But for many states and organizations, including utilities, independent power producers, and balancing authorities, tracking greenhouse gas emissions is essential. To improve transparency around emissions from market dispatch, stakeholders have proposed the Accounting and Reporting approach. This framework helps load-serving entities and other organizations better understand the GHG emissions associated with their electricity consumption, especially under state policies that regulate emissions outside of cap-and-trade systems. The new method also supports voluntary reporting and corporate climate goals." [**CAISO**](https://www.caiso.com/about/news/energy-matters-blog/making-energy-emissions-more-transparent-caisos-accounting-and-reporting-approach?ref=calregulatory.com) - **Natural Gas Weekly Update:** "The price at PG&E Citygate in Northern California rose 20 cents, up from $3.59/MMBtu last Wednesday to $3.79/MMBtu yesterday. The PG&E Citygate price was the highest among major pricing hubs nationwide this report week. Temperatures in the [Sacramento Area](https://www.weather.gov/wrh/Climate?wfo=sto&ref=calregulatory.com) fell 2°F this report week to 61°F, leading to 26 HDDs, 10 HDDs more than last week. The price at SoCal Citygate in [Southern California](https://www.eia.gov/special/disruptions/socal/summer/?ref=calregulatory.com) increased 45 cents from $3.20/MMBtu last Wednesday to $3.65/MMBtu yesterday. In California, residential sector natural gas consumption rose 6% (0.1 billion cubic feet per day \[Bcf/d\]) from last week, according to LSEG Data." [**EIA**](https://www.eia.gov/naturalgas/weekly/?ref=calregulatory.com) - **Report Says California Energy Policies a "Clear and Present Threat to National Security"; Calls for Federal Intervention:** "The report outlines policy options 'to mitigate the actions of California and protect the security interests of the U.S. as related to California as related to petroleum and refinery assets.' These include the president declaring 'California oil production pipelines, terminals, ports, refineries, and all related infrastructure as essential assets…' under the Defense Protection Act. The president could also provide temporary relief to California producers, operators, and refiners under the national Emergencies Act. Lastly, the report states that the president 'may have constitutional powers for protecting California gasoline production and other petroleum assets, potentially through operation of the Supremacy Clause of the U.S. Constitution.'" [**California Energy Journal**](https://www.californiaenergytransition.com/p/report-calls-california-energy-policies?ref=calregulatory.com) - **Santa Barbara County Votes to Shut Down Onshore Oil Operations:** "The Santa Barbara County Board of Supervisors [voted](https://santabarbara.legistar.com/LegislationDetail.aspx?ID=7705094&GUID=A0A78855-C3C4-4594-8C58-5AB29C7B1859&Options=&Search=&ref=calregulatory.com) on October 21, 2025 to proceed with its plan to shut down the local oil industry. The county supervisors voted 3-2 to end the issuance of any new well permits for onshore oil operations in the county and to begin the process for an amortization study to determine an appropriate period to phase out existing oil and gas facilities and operations. The votes comes after the supervisors [voted](https://www.californiaenergytransition.com/p/santa-barbara-county-supervisors-5e4?ref=calregulatory.com) in May 2025 to develop a framework to end oil operations in the county." [**California Energy Journal**](https://www.californiaenergytransition.com/p/santa-barbara-county-votes-to-end?ref=calregulatory.com) - **The Fast Lane to Electric Vehicle Charging:** "Why is it so flipping hard to build an EV charging station? Frustrated developers point to [coordination complexity and permitting paralysis ](https://www.eenews.net/articles/why-is-the-feds-ev-charger-rollout-so-slow-these-people-know/?ref=calregulatory.com#:~:text=Utilities%20move%20slowly,-When%20the%20topic&text=That's%20because%20state%20DOTs%20are,necessary%20for%20a%20NEVI%20station.)as the primary culprits. California has been a particularly challenging landscape to navigate. Back in 2021, Electrify America estimated that it was taking 26% longer to permit a DC fast charging station in California (as compared to the rest of the country) and 47% longer to connect to the grid." [**Energy at Haas**](https://energyathaas.wordpress.com/2025/10/27/the-fast-lane-to-electric-vehicle-charging/?ref=calregulatory.com) - **Viewpoint – California Must Consider Emissions from Foreign Oil:** "The recently passed [SB 237](https://leginfo.legislature.ca.gov/faces/billTextClient.xhtml?bill%5Fid=202520260SB237&ref=calregulatory.com) streamlines the approval process for oil drilling in Kern County in an effort to increase oil production and help stabilize California’s gasoline and oil markets. The law originated as part of a series of California Energy Commission [recommendations](https://www.californiaenergytransition.com/p/cec-recommends-maintaining-refinery?ref=calregulatory.com) in response to [plans to close two refineries](https://www.californiaenergytransition.com/p/valero-to-close-benicia-refinery?ref=calregulatory.com) and fears of a gasoline shortfall. The recommendation to increase oil drilling in Kern received almost [immediate opposition](https://www.documentcloud.org/documents/26048777-environmental-groups-respond-to-governors-proposal/?ref=calregulatory.com) from environmental groups concerned about preserving 'California’s life-saving health, climate, and environmental protections.' They argued that the law’s exemptions from the California Environmental Quality Act 'would gravely harm the air we breathe and water we drink around the state, but have no impact on refinery closures or gas prices.'" [**California Energy Journal**](https://www.californiaenergytransition.com/p/viewpoint-californias-energy-and?ref=calregulatory.com) ### FRIDAY AGGREGATE: Looming 2026 Electric Rate Battles; SoCalGas Transmission Integrity Work; Diablo Canyon Cost Disputes URL: https://www.calregulatory.com/friday-aggregate-looming-2026-electric-rate-battles-socalgas-transmission-integrity-work-diablo-canyon-cost-disputes/ Last updated: 2025-11-25T05:31:51.000Z Below is our end-of-week roundup. - Cal Advocates proposes expanding the income-graduated fixed charge. - SoCalGas announces major transmission line capacity reduction. - Nuclear opponents challenge PG&E's Diablo Canyon cost recovery. - Commissioner John Reynolds questions PG&E rate-increase justifications at public participation hearings. For a full summary of yesterday's voting meeting, go [here](https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/). ## INCOME-GRADUATED FIXED CHARGE In a [recent series of ex parte meetings](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K485/585485726.PDF?ref=calregulatory.com) with Commission personnel, the Public Advocates Office at the CPUC ([Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com)) argued for expanding and improving the "Base Services Charge," which was previously known as the Income-Graduated Fixed Charge. Cal Advocates offered that, while the Base Services Charge (adopted in a 2024 decision, [D.24-05-028](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M531/K686/531686019.PDF?ref=calregulatory.com)) was intended to lower volumetric rates, rapid increases in utility rates since 2022 have offset those reductions, leaving customers with net increases in bills. To meet affordability and electrification goals, Cal Advocates urged the CPUC to begin a new rulemaking to revise the [Base Services Charge](https://www.sce.com/save-money/rates-financing/residential-rate-plans/bsc?ref=calregulatory.com), expanding eligible fixed costs (e.g., non-marginal distribution costs), redefining income tiers, improving the income verification process, and adjusting rate design. Cal Advocates also noted that utilities like SDG&E already include most eligible fixed costs, while PG&E currently includes only about 12% of its revenue requirement in the Base Services Charge, though this could grow to over 30% if the rules expand. Finally, Cal Advocates emphasized that higher fixed charges would still preserve conservation signals because volumetric rates remain high. **INSTANT ANALYSIS:** Cal Advocates wants a new rulemaking to expand the Base Services Charge to cover more fixed utility costs and to reset the income tiers that determine who pays what. Their message is that the Base Services Charge barely made a dent in rising rates, and without a larger fixed charge, California risks missing its social and electrification goals. This could be the first indication that the CPUC may reopen rate-design battles in 2026, potentially reshaping how utilities recover billions in distribution costs and how much customers see in per-kWh charges. --- ## SOCALGAS TRANSMISSION INTEGRITY SoCalGas provided notice on its [Envoy messaging system](https://www.socalgasenvoy.com/index.jsp?ref=calregulatory.com#nav=/Public/ViewExternal.showHome) that it will reduce operating pressure on its Line 4000 pipeline from **November 1, 2025 to December 18, 2025** as part of its Transmission Integrity Management Program. This unplanned pressure reduction is required for safety compliance after a [Pipeline and Hazardous Materials Safety Administration](https://www.phmsa.dot.gov/?ref=calregulatory.com) (PHMSA) inspection found conditions requiring immediate repair. To fully assess and address the issues, SoCalGas must perform direct pipeline examinations, including excavation, coating removal, pipe body inspection, and engineering evaluation. Any remediation identified during this process could extend the duration. Because of this reduced pressure, Northern Zone capacity will drop by 620 million cubic feet per day during this period. **INSTANT ANALYSIS**: A 620 MMcf/d capacity cut on Line 4000 directly tightens supply into SoCalGas’s Northern Zone during early winter 2025 and coincides with higher seasonal demand. While safety-driven and in proper compliance with PHMSA, it introduces operational and price risk for gas-fired generators, storage operators, and large end-users reliant on Northern Zone deliveries. Because the work window extends through mid-December, the timing could intersect with winter reliability planning, [Aliso Canyon](https://www.socalgas.com/sustainability/pipeline-and-storage-safety/aliso-canyon-storage-facility?ref=calregulatory.com) withdrawal protocols, and [Gas Cost Incentive Mechanism](https://www.publicadvocates.cpuc.ca.gov/press-room/reports-and-analyses/monitoring-and-evaluation-report-of-southern-california-gas-company-gas-cost-incentive-mechanism?ref=calregulatory.com) performance metrics. If inspections uncover more serious integrity issues, the outage could last longer than planned. --- ## DIABLO CANYON COST RECOVERY The [Alliance for Nuclear Responsibility](https://a4nr.org/?ref=calregulatory.com) filed a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486351.PDF?ref=calregulatory.com) of a 2024 CPUC decision ([D.24-12-033](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M550/K462/550462685.PDF?ref=calregulatory.com)), which authorized $723 million in cost recovery for PG&E to support extended operations of the Diablo Canyon Power Plant from 2023-2025\. The Alliance argues that D.24-12-033 was based on now-invalid Resource Adequacy Market Price Benchmark values. After D.24-12-033, the Commission adopted [D.25-06-049](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K242/571242473.PDF?ref=calregulatory.com) in the [ERRA/PCIA Reform docket](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M557/K860/557860748.PDF?ref=calregulatory.com), which found the prior Market Price Benchmark methodology flawed and vulnerable to manipulation and replaced it with a much lower 2025 Market Price Benchmark of **$11.21/kW-month** instead of the $42.54 used in the Diablo Canyon cost forecast. Because the Public Utilities Code shields PG&E's costs from reasonableness review if they stay within a 115% forecast, the Alliance says using the outdated, inflated Market Price Benchmark would improperly protect more than **$160 million** from scrutiny. The Alliance adds further that the 2024 final Market Price Benchmark used in D.24-12-033 was incorrect and should be replaced with Energy Division's updated figure of **$26.26/kW-month**. The Alliance proposes reducing PG&E's approved revenue requirement to approximately **$582 million**. **INSTANT ANALYSIS:** If this petition succeeds, PG&E could see more than $160 million brought back under reasonableness review, perhaps opening the door for broader challenges to Diablo Canyon cost recovery in 2026 General Rate Case and [Energy Resource Recovery Account](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-costs/what-is-an-energy-resource-recovery-account-proceeding?ref=calregulatory.com) proceedings. If the petition fails, utilities might claim precedential authority to use market-price benchmarks (even discredited ones) to shield their revenue requirements from scrutiny. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/10/IMG_4157.JPG) ## PG&E GENERAL RATE CASE The CPUC convened public participation hearings this month to gather feedback on PG&E's [request](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M566/K363/566363587.PDF?ref=calregulatory.com) to increase rates, starting in 2027\. Commissioner **John Reynolds**, ALJs **Elizabeth Fox** and **John Larsen** presided over the first day and were joined on the second day by Commissioner **Matt Baker**. They outlined PG&E's request to fund its operations and infrastructure needs from 2027-2030, which would lead to increases in electric rates (**5%** in 2027 and **6.1%** annually thereafter). Natural gas rates are projected to decline slightly in 2027. Commissioner Reynolds stressed that, while wildfire mitigation and modernization of the grid are essential, not every dollar PG&E proposes is justified. He questioned how PG&E could simultaneously claim rapid growth of its rate base (over 50% in five years) yet also promise that rates will grow more slowly than inflation. He [added](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486359.PDF?ref=calregulatory.com): > I'm...mindful that when PG&E pledges that rates will remain stable for years to come, that rates are currently unaffordable for many residents of this state.· Stable rates will not offer respite to those who are struggling to pay their bills. The floor opened to dozens of speakers: residents, small business owners, and ratepayers across PG&E's service territory spoke on issues spanning wildfire concerns, slow grid upgrades, and power shutoffs. Full transcripts are available [here](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K486/585486359.PDF?ref=calregulatory.com) and [here](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K485/585485936.PDF?ref=calregulatory.com). ### Results of October 30, 2025 CPUC Voting Meeting URL: https://www.calregulatory.com/results-of-october-30-2025-cpuc-voting-meeting/ Last updated: 2025-12-18T16:26:42.000Z Below is a review of the CPUC's Thursday, October 30 business meeting. Note that the decisions and resolutions summarized here reflect final, redlined language changes that the Commission distributed earlier this week. Wherever applicable, we incorporated those changes into our final summaries. (*See our meeting preview* [*here*](https://www.calregulatory.com/cpuc-voting-meeting-preview/) *to compare.*) ## STACK Infrastructure Transmission Service Request [Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M585/K393/585393718.pdf?ref=calregulatory.com) approves (with modifications) PG&E’s request to construct and energize new transmission facilities (including a 115-kilovolt Ringwood substation) to serve [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com)’s 90-megawatt data center in San Jose, at an estimated cost of **$85.9 million**. STACK Infrastructure is a major data-center developer supporting cloud computing, AI, and enterprise data storage. To protect ratepayers from stranded-cost risk, the resolution modifies PG&E’s refund process, capping annual refunds to 75% of actual net revenues from the customer (defined as the transmission component of the bill and per-meter charge) and adjusting for the Income Tax Component of Contribution. The refund eligibility period is extended from 10 to 15 years. This approach slows (but does not reduce) the total refund, which is expected to be fully repaid in approximately six years. The resolution also finds reasonable the use of actual cost payments, the removal of a 50% discount option, and other contract terms. [Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com) (a.k.a. the Public Advocates Office at the Commission) supported the modifications as necessary ratepayer protections, while a group of Community Choice Aggregators raised broader transparency issues that the Commission deferred to the [Rule 30 proceeding](https://www.cpuc.ca.gov/news-and-updates/all-news/cpuc-streamlines-electric-grid-connections-for-high-energy-users-like-data-centers-and-ev-chargers?ref=calregulatory.com). **INSTANT ANALYSIS**: This resolution illustrates how California’s accelerating data-center buildout is reshaping grid-planning norms. By lengthening refund timelines and tightening revenue-assurance requirements, the CPUC is saying that large-load customers must now share greater long-term risk before ratepayers assume costs. _This post is for paying subscribers only._ ### WEDNESDAY AGGREGATE: Integrated Resource Planning; Transportation Electrification; Long-Term Gas Planning URL: https://www.calregulatory.com/mid-week-aggregate-s/ Last updated: 2025-12-01T17:36:06.000Z Hello. Below are some notable CPUC items on our radar this week. ## Integrated Resource Planning CPUC **President Alice Reynolds** issued a [scoping memo and ruling](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K485/585485746.PDF?ref=calregulatory.com) in the new Integrated Resource Planning docket. Key milestones anticipated by this ruling include: - A February 2026 decision on near-term procurement and 2026-2027 CAISO Transmission Planning Process portfolios; - Load-serving entities' IRP filings in May 2026; - 2026-2027 Preferred System Plan development; and - April 2026 utility Bundled Procurement Plan updates. The scope also anticipates coordinating implementation of the [Reliable and Clean Power Procurement Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/long-term-procurement-planning/the-reliable-and-clean-power-procurement-program?ref=calregulatory.com) (RCPPP) if adopted, and evaluating compliance with prior procurement orders (including backstop procurement) if needed. ## Transportation Electrification **Administrative Law Judge Poirier** issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K972/584972262.PDF?ref=calregulatory.com) to tighten and simplify the state's Transportation Electrification framework. The PD consolidates multiple reporting requirements into one annual TE compliance report that is due annually on **June 30**. The PD eliminates the annual Vehicle Grid Integration stocktake adopted in a 2020 decision, [D.20-12-029](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M355/K794/355794454.PDF?ref=calregulatory.com)) and shifts any future VGI reporting refinements to a Q1 2026 forum. Recall that the stocktake was intended to give the CPUC and stakeholders a clear picture of the current breadth of TE and VGI efforts. (A "repository of information" as the [Vehicle-Grid Integration Council](https://www.vgicouncil.org/?ref=calregulatory.com) has said.) The PD continues the "Technical Assistance Program" (which was established[ in 2022](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M499/K005/499005805.PDF?ref=calregulatory.com)) with a **$36 million**, three-year budget, which is now fully decoupled from the paused "Funding Cycle One Behind-the-Meter Rebate Program." The PD stipulates that investor-owned utilities can recover pre-pause implementation costs from the latter program. Last, the PD removes the vehicle purchase requirement from Funding Cycle Zero medium- and heavy-duty programs to lower participation barriers but keeps the **December 31, 2026** sunset date. These programs include PG&E's [EV Fleet](https://www.pge.com/en/clean-energy/electric-vehicles/ev-fleet-program.html?ref=calregulatory.com) program, SCE's [Charge Ready Transport](https://crt.sce.com/overview?ref=calregulatory.com) program, and SDG&E's [Power Your Drive for Fleets Program](https://www.sdge.com/business/electric-vehicles/power-your-drive-for-fleets?ref=calregulatory.com). The earliest the Commission will consider this item is **December 4**. Comments are due **November 17**. ## Long-Term Natural Gas Planning SoCalGas recently provided [a summary](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K972/584972918.PDF?ref=calregulatory.com) of the CPUC's September 22 workshop in the Long-Term Natural Gas Planning workshop. The workshop focused on how California will forecast, plan, and decarbonize its gas system on a tight [Senate Bill 1221](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=202320240SB1221&ref=calregulatory.com) timeline. Recall that SB 1221 requires the CPUC to create neighborhood decarbonization zones that enable utilities to decommission gas infrastructure when at least 67% of customers in such a zone opt to electrify. Regulators, utilities, and advocates agreed that demand forecasts and rate signals are the hinge points of the gas transition. Modeling from the California Energy Commission described how forecasts shape system design, while the [Utility Reform Network](https://www.turn.org/?ref=calregulatory.com), the Natural Resources Defense Council, and the Sierra Club pushed for non-pipeline alternatives (NPAs), i.e., targeted electrification projects treated as regulatory assets instead of sunk pipeline costs. SoCalGas framed NPAs around safety and cost control; the City of Long Beach highlighted real-world electrification barriers in aging neighborhoods; and PG&E shared mixed results from its [Alternative Energy Program](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/meeting-documents/workshops/senate-bill-1221-workshop/pgne-sb-1221-presentation.pdf?ref=calregulatory.com) (a pilot meant that electrifies entire neighborhoods or zones in lieu of replacing at-risk gas infrastructure) and [Zonal Equity Electrification Program](https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/meeting-documents/workshops/senate-bill-1221-workshop/pgne-sb-1221-presentation.pdf?ref=calregulatory.com), a companion pilot focused on the equitable implementation of zonal electrification. While these projects electrify whole zones, they struggle to hit the 67% opt-in threshold. Tensions documented in SoCalGas's report include who pays, how costs are structured, and how quickly pilots will scale. ## Electrification The CPUC issued a [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K961/583961250.PDF?ref=calregulatory.com) to launch a Mobilehome Park Electrification Pilot Initiative. The PD directs PG&E, SCE, and SDG&E to work with the CEC's [Equitable Building Decarbonization Program](https://www.energy.ca.gov/programs-and-topics/programs/equitable-building-decarbonization-program?ref=calregulatory.com) to fully electrify select mobilehome parks. The pilot pairs utility-funded 200-amp service upgrades with CEC-funded behind-the-meter electrification, including heat pumps and induction appliances. All participating parks are required to permanently abandon natural gas. Priority will go to parks with existing utility service in under-resourced communities with full resident participation. Existing ratepayer funds will be used for these pilots. The earliest the CPUC will consider this item is **November 20**. Comments are due **November 6**. ## Wildfire Non-Bypassable Charge A new [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M584/K972/584972246.PDF?ref=calregulatory.com) from **ALJ Brandon Gerstle** establishes the 2026 Wildfire Fund Non-Bypassable Charge (WF NBC) at **$0.00591/kWh**, effective from January 1 through December 31, 2026, to collect **$908.9 million**. This amount reflects the statutory annual revenue requirement of $902.4 million under [Assembly Bill 1054](https://legiscan.com/CA/text/AB1054/id/2046243?ref=calregulatory.com) plus $6.5 million in a projected undercollection from previous years. AB 1054 established the WF NBC to provide a stable funding mechanism for California's Wildfire Fund, with PG&E, SCE, and SDG&E collecting and remitting funds to the Department of Water Resources (DWR). Since 2020, the CPUC has set the charge annually based on DWR's notices and revenue forecasts, via a collection-curve methodology to ensure revenue sufficiency. The rate has fluctuated slightly over time due to load forecasts and prior-year vacancies. The table below lists the NBC rates dating back to 2020. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/10/nbc.png) The PD orders each IOU to file a Tier 1 advice letter by **December 31, 2025** to implement the new charge. The earliest the CPUC will consider this item is **December 4**. Comments are due **November 13**. ## Wildfire Mitigation The Public Advocates Office at the CPUC ([Cal Advocates](https://www.publicadvocates.cpuc.ca.gov/?ref=calregulatory.com)) filed an [application for rehearing](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M585/K485/585485746.PDF?ref=calregulatory.com) of a decision last month ([D.25-09-008](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K558/581558207.PDF?ref=calregulatory.com)), which authorized **$1.064 billion** in cost recovery for PG&E's wildfire mitigation work. Cal Advocates argues that D.25-09-008 misapplied the law by accepting weak evidence and ignoring precedent. Cal Advocates contends that the CPUC wrongly relied on an Ernst & Young audit that only checked for accounting accuracy, and not whether costs were incremental to PG&E's General Rate Case. Cal Advocates argues further that D.25-09-008's acceptance of journal entries as proof of cost reasonableness is inadequate. The application for rehearing points to a SCE wildfire decision from last summer ([D.25-06-051](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M571/K383/571383364.PDF?ref=calregulatory.com)), where the Commission distinguished incrementality from reasonableness. By blurring that line, Cal Advocates argues, the PG&E decision risks double recovery. Cal Advocates also disputes PG&E's claim that balancing accounts inherently ensure fairness, noting that "Safety Infrastructure Protection Team" costs were largely existing labor. Cal Advocates asks the CPUC to reverse its cost-recovery approval and apply a proper legal standard. ## Public Purpose Program SoCalGas filed Advice Letter 6552-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)) to update its Public Purpose Program surcharge rates effective January 1, 2026\. The update is required annually under a 2004 CPUC decision ([D.04-08-010](https://docs.cpuc.ca.gov/PublishedDocs/WORD%5FPDF/FINAL%5FDECISION/39314.PDF?ref=calregulatory.com)) and Assembly Bill 1002, which direct the Commission to establish a natural gas surcharge to fund energy efficiency, low-income assistance, and research & development programs. The new rates are based on the adopted volumes and allocations from a decision last year ([D.24-07-009](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M536/K491/536491449.PDF?ref=calregulatory.com)) in SoCalGas's 2024 [Cost Allocation Proceeding](https://www.socalgas.com/regulatory/2024-Cost-Allocation-Proceeding?ref=calregulatory.com). The 2026 surcharge revenue requirement is projected to increase by **$78 million** (17%) compared to 2025, primarily due to a reduction in the [CARE](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/california-alternate-rates-for-energy?ref=calregulatory.com) Energy Account overcollection amortization and higher CARE subsidy forecasts. Program budgets include: - **$233.6 million** for CARE; - $**122.5 million** for [Energy Savings Assistance](https://www.cpuc.ca.gov/consumer-support/financial-assistance-savings-and-discounts/energy-savings-assistance?ref=calregulatory.com); - **$180.2 million** for energy efficiency (including Regional Energy Networks, market transformation, and [CHEEF](https://www.treasurer.ca.gov/caeatfa/cheef/?ref=calregulatory.com) financing); and - **$12.2 million** for RD&D. SoCalGas's adjustments also reflect amortizations from balancing accounts, including refunds from the Direct Assistance Balancing Account and minor overcollections and undercollections in the Research, Development, and Demonstration Gas Surcharge Account and the San Joaquin Valley Disadvantaged Communities Balancing Account. Revised PPP rates apply to both CARE and non-CARE customers across major classes, with notable increases for residential and commercial/industrial customers. Please see the table below for more detail. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/10/PPP.png) ## Biomethane SoCalGas filed an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M583/K959/583959234.PDF?ref=calregulatory.com) to develop a woody biomass pilot project under [Senate Bill 1440](https://legiscan.com/CA/text/SB1440/id/1821051?ref=calregulatory.com), which would convert almond orchard waste into bio-synthetic natural gas ([Bio-SNG](https://www.sciencedirect.com/topics/engineering/bio-synthetic-natural-gas?ref=calregulatory.com)). The selected developer, [West Biofuels LLC](https://www.westbiofuels.com/?ref=calregulatory.com), would build and operate the facility in Fresno and Kern Counties, producing about 750 MMbtu/day of biomethane for injection into SoCalGas's pipeline at Vasalia. The project would be funded with **$19.7 million** in Cap-and-Trade Proceeds. SoCalGas claims it would achieve a carbon intensity as low as −104 grams of carbon dioxide equivalent per megajoule with carbon capture, which would support state climate goals and create community benefits. SoCalGas plans to cover utility infrastructure costs and potentially enable a virtual pipeline for future Renewable Natural Gas producers. ## SoCalGas's Projected January 1, 2026 Natural Gas Transportation Rates SoCalGas recently filed Advice Letter 6548-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)), its Annual Regulatory Account Balance Update, which projects the company’s revenue requirement and natural gas transportation rates, effective **January 1, 2026**. Note that this is SoCalGas’s *initial* consolidated update **– a final, more comprehensive version will be filed in late December**. Please see our [October 27 summary](https://www.calregulatory.com/socalgas-annual-consolidated-rate-update-filing/) for more details. ![](https://storage.ghost.io/c/36/77/3677b301-4c92-43b7-8e2f-c7265d6b0b59/content/images/2025/10/iterograph_Tue-Oct-28-2025.png) ### SoCalGas Annual Consolidated Rate Update Filing URL: https://www.calregulatory.com/socalgas-annual-consolidated-rate-update-filing/ Last updated: 2025-12-18T16:32:10.000Z SoCalGas recently filed Advice Letter 6548-G (available [here](https://tariffsprd.socalgas.com/scg/filings/content/?utilId=SCG&bookId=GAS&flngStatusCd=Pending&ref=calregulatory.com)), its Annual Regulatory Account Balance Update, which projects the company’s revenue requirement and natural gas transportation rates, effective **January 1, 2026**. Note that this is SoCalGas’s *initial* consolidated update **– a final, more comprehensive version will be filed in late December**. For the time being, SoCalGas projects a net **$30.5 million** decrease in its 2026 transportation revenue requirement relative to current levels. Major drivers include large decreases in the Core Fixed Cost Account, the Greenhouse Gas Balancing Account (GHGBA), the Residential Uncollectible Balancing Account, and the elimination of Morongo Right of Way Memorandum Account amortization. SoCalGas anticipates that core customers will see a **$161.1 million** decrease, while noncore customers will see a **$34.8 million** *increase*, primarily due to a higher Noncore Fixed Cost Account undercollection. ### **Massive BTS Increase** Rates for backbone transportation service will likely see a major increase (**$208.2 million**) because SoCalGas is no longer amortizing a large prior overcollection in the Backbone Transmission Balancing Account. For now, this increase is projected at a whopping **51.2%**, although previous SoCalGas filings have suggested it will not quite reach that level. The company’s final consolidated advice-letter filing in December will provide greater clarity. _This post is for paying subscribers only._ ### CPUC Voting Meeting Preview: 10/30/25 URL: https://www.calregulatory.com/cpuc-voting-meeting-preview/ Last updated: 2025-12-01T17:36:55.000Z Welcome to California Regulatory Intelligence's inaugural briefing. The report below provides a summary of items the CPUC is scheduled to consider at its [**October 30, 2025** voting meeting](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M584/K825/584825369.pdf?ref=calregulatory.com). On Friday, we'll provide a full rundown of the meeting results, which will include: - Any final language changes to items under consideration (11th hour redline edits); - Notable commissioner comments from the dais; and - Whether the Commission delayed action on any items until a future meeting. More detail is provided in the summaries below. --- ## **STACK Infrastructure Transmission Service Request** [Draft Resolution E-5420](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K576/581576861.PDF?ref=calregulatory.com) approves (with modifications) PG&E’s request to build and energize new transmission infrastructure (including a 115-kilovolt Ringwood substation) to serve [STACK Infrastructure](https://www.stackinfra.com/?ref=calregulatory.com)’s 90-megawatt data center in San Jose, at an estimated cost of **$85.9 million**. STACK Infrastructure is a major data-center developer and operator that runs large-scale, high-capacity facilities to support cloud computing, AI, and enterprise data storage. To protect ratepayers from stranded cost risk, the draft resolution modifies PG&E’s proposed refund process, capping refunds to STACK at 75% of annual net transmission-related revenues, rather than allowing immediate full refunds under the standard "Base Annual Revenue Calculation" methodology used under [Electric Rules 15 and 16](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/infrastructure/electric-reliability/undergrounding-program-description/rule-20/cpuc-rule-20-undergrounding-programs-current-proceeding-r1705010/electric-tariff-rules-15-and-16-distribution-line-and-service-extensions?ref=calregulatory.com). The idea is that this approach slows, but does not reduce, the total refund amount, which is expected to be fully repaid in approximately six years. The draft resolution also approves some other terms as reasonable, e.g., requiring actual cost payments and removing a 50% discount option. While a group of Community Choice Aggregators raised concerns about transparency in the lead-up to the PD, the Commission finds that those issues are better addressed in the Rule 30 proceeding. **Instant Analysis**: This item is another indicator of how data centers are reshaping grid planning. By slowing down refund timelines for STACK’s $50 million interconnection, the CPUC is indicating that large transmission customers must share more risk with the broader system. ## **Undergrounding Distribution Equipment of Large Electrical Corporations** [Draft Resolution SPD-37](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K834/583834088.pdf?ref=calregulatory.com) refines and updates the [CPUC’s Senate Bill 884 undergrounding program](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division/risk-assessment-and-safety-analytics/electric-undergrounding-sb-884?ref=calregulatory.com), a framework designed to expedite the burial of distribution infrastructure in high fire-thread districts to reduce wildfire risk and improve reliability. The draft resolution aligns previously adopted Commission guidelines (via [Resolution SPD-15](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M526/K984/526984185.pdf?ref=calregulatory.com), from last year) with the [Office of Energy Infrastructure Safety](https://energysafety.ca.gov/?ref=calregulatory.com)’s [10-Year Undergrounding Plan Guidelines](https://energysafety.ca.gov/news/2025/02/20/energy-safety-adopts-10-year-electrical-undergrounding-plan-guidelines/?ref=calregulatory.com), clarifies cost-recovery procedures, and strengthens oversight. New changes include: - New Phase 2 requirements to ensure utilities provide sufficient project-level data; - Additional conditions for cost recovery (including benefit-cost ratio thresholds and limits on unit-cost variance); and - Explicit audit procedures for one-way balancing accounts to verify compliance before costs are recovered from ratepayers. Draft Resolution SPD-37 also establishes a memorandum account cost cap to limit financial exposure. **Instant Analysis**: The authorized refinements address the gap between preliminary cost estimates filed early in the project scoping process and actual costs incurred during construction, with goals to ensure ratepayer protections, transparency, and cost discipline while simultaneously advancing state wildfire goals. --- ## **Energy Efficiency Market Transformation** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K301/581301683.PDF?ref=calregulatory.com), from **Commissioner Matt Baker**, authorizes ratepayer funding for the California Market Transformation Administrator’s ([CalMTA](https://calmta.org/?ref=calregulatory.com)) [Room Heat Pump Market Transformation Initiative](https://calmta.org/room-heat-pumps/?ref=calregulatory.com) (MTI) but declines funding for an [Induction Cooktop MTI](https://calmta.org/resourcereport/induction-cooking-mti-plan/?ref=calregulatory.com). **Background** - CalMTA is an independent, statewide entity that designs and implements “market transformation” programs that are meant to shift entire markets toward cleaner, more efficient technologies. - The Room Heat Pump MTI is one of the first programs developed by CalMTA, which accelerates adoption of plug-in, 120-volt room heat pumps across the state. - The Induction Cooktop MTI was a strategic plan to transform California’s cooking appliance market, shifting from gas to efficient induction technology via upstream market actions rather than just rebates. It still remains a potential future initiative even though it its funding is declined in Commissioner Baker’s PD. The Baker PD (an alternative PD, or “APD”) sets a **$54.87 million** budget cap for 2026-2031, which is considerably lower than the **$102.4 million** set in **ALJ Julie Fitch’**s [competing PD](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K151/581151908.PDF?ref=calregulatory.com). The Baker APD also requires CalMTA to submit sensitivity analyses in future MTI applications to better understand market adoption drivers, and – starting with applications after 2028 – to demonstrate efforts to secure non-ratepayer funding. By December 31, 2028 CalMTA must file a Tier 2 advice letter with a nonprofit transition plan, an amended contract granting the CPUC a perpetual, no-cost license to CalMTA’s cost-effectiveness tool, and the results of an annual audit. The APD establishes annual reporting and audit requirements to ensure accountability, and any discontinuation of MTIs will require Tier 2 advice letters (*Tier 2 filings are reserved for substantive but routine matters, e.g., program updates, implementation plans, or compliance filings*). In rejecting the Induction Cooktop MTI and other proposed budget categories, the APD cites ratepayer affordability concerns, federal funding uncertainty, and a need to better align funding levels with performance and policy goals. This narrower authorization still fulfills the statutory obligation to support market transformation under the Public Utilities Code, while encouraging CalMTA to diversify funding sources over time and focus deployment on proven, high-value initiatives. **Instant Analysis:** Commissioner Baker’s APD declines to fund the Induction Cooktop MTI, citing affordability concerns and the need for stronger justification before expanding to new programs. The APD prioritizes the more cost-ready Room Heat Pump MTI. Costs will be borne by ratepayers of PG&E, SCE, and SDG&E. --- ## **PG&E Natural Gas Curtailment Procedures** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M582/K107/582107583.PDF?ref=calregulatory.com) authorizes PG&E’s application to revise its natural gas curtailment procedures, which brings them into alignment with procedures used by other major gas utilities. Previously, PG&E relied solely on localized curtailments to mange pressure on its system of more than 5,600 miles of transmission pipeline. This PD adds systemwide curtailment protocols, which were developed through extensive stakeholder workshops and negotiations with parties including TURN, Cal Advocates, and the Indicated Shippers. The new framework sequences curtailments in six prioritized customer groups: 1. Non-dispatched electric generation; 2. Partially dispatched generation; 3. Noncore industrial and refinery customer; 4. Additional noncore load; 5. Non-residential core customers; and 6. Residential and small commercial customers (but only in extreme emergencies). "In its prepared testimony," the PD states, "PG&E makes two important points – curtailing any core customers is highly unlikely and PG&E will exhaust all possible options to avoid curtailing any core customers before doing so." PG&E's design adheres to the principles of safety, effectiveness, simplicity, and alignment with SoCalGas and SDG&E. The PD authorizes changes to Gas Tariff Rules 1 ("[Definitions](https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS%5FRULES%5F1.pdf?ref=calregulatory.com)") and 14 ("[Capacity Allocation and Constraint of Gas Services](https://www.pge.com/tariffs/assets/pdf/tariffbook/GAS%5FRULES%5F14.pdf?ref=calregulatory.com)"), requires PG&E to notify noncore customers and update its systems; and directs continued coordination with the CAISO to minimize the need for curtailments. **Instant Analysis**: This PD modernizes PG&E’s natural gas curtailment framework by adding clear, systemwide procedures similar to those of SoCalGas and SDG&E. The PD prioritizes curtailments in a manner that protects core customers and grid reliability. ## **SCE: Diablo Canyon Replacement Bridge Swap Contracts** [Draft Resolution E-5419](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K690/581690331.PDF?ref=calregulatory.com) approves SCE’s request to execute two Diablo Canyon Replacement bridge swap contracts involving bundled [Portfolio Content Category 1](https://www.lawinsider.com/dictionary/portfolio-content-category-1?ref=calregulatory.com) (PCC-1) renewable energy credits (and energy). These are short-term energy transactions SCE uses to meet state procurement mandates that were established to replace output from the Diablo Canyon Power Plant when the facility was expected to retire. For energy to qualify as PCC-1, it must come from a Renewables Portfolio Standard-eligible resource (e.g., solar or wind farm) and be directly delivered into a California balancing authority (e.g., the CAISO). Additionally, the RECs must stay with the power (they cannot be sold separately). The approved purchase contract delivers approximately 1.7 million megawatt hours of bundled solar energy and RECs from June 2025 – May 2026 to help Edison meet its near-term Diablo Canyon Replacement procurement obligations, as established in 2021’s Mid-Term Procurement Decision ([D.21-06-035](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M389/K603/389603637.PDF?ref=calregulatory.com)) and related orders. The companion sell contract involves roughly 1.86 million MWh of solar and disadvantaged communities RECs over multiple years. Costs and benefits will be allocated to customers via the Portfolio Allocation Balancing Account, a cost-recovery mechanism the CPUC created to ensure that all customers who benefit from certain utility energy contracts pay their fair share of the costs, even if they have left the utility for another provider. And although a decision last month ([D.25-09-007](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M581/K576/581576925.PDF?ref=calregulatory.com)) eliminated future use of bridge contracts, the agreements here remain eligible because they were executed before that. SCE may pursue cost recovery in full. Contract price details are confidential for market reasons. **Instant Analysis:** These short-term contracts are intended to be a stopgap strategy that meets state clean-energy goals without disrupting reliability. Their costs will be allocated to both bundled and departing load customers responsible for this procurement, not just current SCE customers. ## **Modifications to the Self-Generation Incentive Program** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M577/K291/577291720.PDF?ref=calregulatory.com), issued by **Commissioner Karen Douglas**, initiates the endgame for California’s long-running [Self-Generation Incentive Program](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/demand-side-management/self-generation-incentive-program?ref=calregulatory.com), which has provided ratepayer-funded financial incentives for installing behind-the-meter clean-energy technologies e.g., battery storage and distributed generation. The CPUC’s SGIP statutory obligations are at their end, and the Commission considers the program to have served its purpose of jumpstarting customer-sited clean tech. Specifically, the PD establishes the framework for closing out the SGIP, launches the “Greenhouse Gas Reduction Fund” and makes various program changes. The Greenhouse Gas Reduction Fund will use cap-and-trade auction proceeds to support programs that reduce GHG emissions, particularly in disadvantaged communities. The PD sets **December 30, 2025** as the final application and waitlist deadline for the ratepayer-funded SGIP, defines fund allocation for Reservation Request Form submission (i.e., the moment when a project officially reserves or locks in its incentive funds from the program budget) and directs the annual repayment of unused funds to customers via existing mechanisms, with final repayment by **2033**. The PD shortens the SGIP’s Performance-Based Incentive period to two years for new projects and directs that non-residential equity projects may receive up to four additional extensions, under strict conditions. The PD establishes that low-income Residential Solar and Storage Equity participants are exempt from mandatory Demand Response participation. (Recall that this dedicated SGIP budget category provides incentives for low-income customers to install behind-the-meter solar and battery storage systems.) The PD also allows program modifications via the advice-letter process (in lieu of petitions for modification) and adopts a final SGIP Measurement and Evaluation plan. --- ## **Bioenergy Market Adjusting Tariff** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M580/K430/580430313.PDF?ref=calregulatory.com) denies a [petition for modification](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M558/K427/558427287.PDF?ref=calregulatory.com) filed by the [Bioenergy Association of California](https://bioenergyca.org/?ref=calregulatory.com) to modify a 2020 CPUC decision ([D.20-08-043](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M346/K112/346112503.PDF?ref=calregulatory.com)). In their petition, the Bioenergy Association of California sought to extend (or remove) the December 31, 2025 end date of the Commission’s [Bioenergy Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-sb-1122-biomat?ref=calregulatory.com) (BioMAT) program. **What is the Bioenergy Market Adjusting Tariff?** The BioMAT is a feed-in tariff program that allows small [bioenergy](https://en.wikipedia.org/wiki/Bioenergy?ref=calregulatory.com) projects (up to 5 megawatts) to sell renewable power to the investor-owned utilities at fixed contract prices. The PD finds that maintaining the program’s sunset date aligns with the state’s [Affordability Executive Order (N-5-24)](https://www.gov.ca.gov/wp-content/uploads/2024/10/energy-EO-10-30-24.pdf?ref=calregulatory.com) and overarching clean-energy priorities. The PD also finds that the BioMAT program has been chronically underutilized (only about 21% of the program’s 250 megawatt targets has been subscribed to since 2016) and that high per-MWh costs ($127 - $199) far exceed those of other renewable procurement mechanisms. According to the Commission, multiple BioMAT program modifications over the years failed to boost participation, and alternative procurement pathways (e.g., [Renewables Portfolio Standard](https://www.cpuc.ca.gov/rps/?ref=calregulatory.com), [Renewable Market Adjusting Tariff](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/renewable-market-adjusting-tariff?ref=calregulatory.com), the [Bioenergy Renewable Auction Mechanism](https://www.cpuc.ca.gov/industries-and-topics/electrical-energy/electric-power-procurement/rps/rps-procurement-programs/rps-bioram?ref=calregulatory.com), bilateral contracts) provide more viable options. The PD rejects arguments of the Bioenergy Association of California regarding statutory procurement mandates and wildfire mitigation benefits, finding that the program’s costs outweigh its benefits to ratepayers. **Instant Analysis**: This PD signals yet more intention by the CPUC to focus on program performance and affordability. --- ## **PG&E Condemnation of Assets** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K294/581294235.PDF?ref=calregulatory.com) pauses a long-running dispute between PG&E and the [South San Joaquin Irrigation District](https://www.ssjid.gov/?ref=calregulatory.com) over who should control local power lines in that area. The PD dismisses without prejudice an [application](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M539/K203/539203607.PDF?ref=calregulatory.com) filed by PG&E, which sought a determination on whether the South San Joaquin District’s proposed condemnation of PG&E’s electric distribution assets would serve the public interest. The PD concludes that ongoing eminent domain action in San Joaquin Superior Court, which began in 2016 and focuses on the evaluation of the assets in question, should proceed prior to the CPUC’s review. While the CPUC could, in theory, conduct an evidentiary hearing based on valuation scenarios, the PD finds that doing so now would be inefficient and potentially duplicative given the active court case. Once the valuation trial concludes, PG&E must refile an application with the CPUC, at which point a public-interest analysis, pursuant to the terms of the Public Utilities Code, can occur. **Instant Analysis**: The PD is saying that the courts need to finish deciding what PG&E’s assets are worth before further action can be taken, while insinuating that eminent domain fights hinge on price, and no policy questions can be addressed until that matter is settled. --- ## **P**e**tition of CCSF for Property Valuation of PG&E** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M581/K301/581301739.PDF?ref=calregulatory.com) establishes standards and methodologies that the CPUC will use to determine just compensation if the City and County of San Francisco proceeds to condemn portions of PG&E’s electric system that serve San Francisco. - The PD adopts three guiding principles: (i) PG&E shareholders and remaining customers must be made whole; (ii) the taking (i.e., the legal act of condemnation) is a partial condemnation; and (iii) PG&E may be entitled to business and physical severance damages. "Partial" here means CCSF is not seizing PG&E’s entire system, but simply a portion of it. - The PD adopts the “before and after rule” as the valuation framework. This entails measuring the difference between the value of PG&E's system before and after the taking, while allowing parties to define the scope of the “before” property and serve testimony accordingly. - The PD does not prescribe a single valuation method; instead, parties must apply and justify the sales comparison, income, and cost approaches. The PD also emphasizes protecting ratepayers from cost-shifting and requires testimony on how compensation will be allocated between shareholders and ratepayers. - The PD directs the City and County of San Francisco to produce a single, detailed separation plan, and outlines comprehensive testimony guidelines for both CCSF and PG&E, including asset inventories, engineering details, valuation models, and rate-impact analyses. - Last, the PD establishes that severance damages must be separately stated and cannot offset asset value. **Instant Analysis**: This PD sets the ground rules for how to value PG&E’s San Francisco electric assets if CCSF moves forward with eminent domain. The PD treats the effort as a partial condemnation. The adopted framework seeks to ensure that PG&E shareholders and remaining customers are made financially whole, and that costs are not shifted to other ratepayers. --- ## **SDG&E Natural Gas Leak Abatement** [Draft Resolution G-3606](https://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M583/K848/583848056.PDF?ref=calregulatory.com) denies SDG&E’s request to recover approximately **$24.9 million** in ratemaking forecasts for its 2024 Natural Gas Leak Abatement Compliance Plan. This rejection includes all Best Practice measures and RD&D projects, on the grounds that none of them were cost-effective, while authorizing only **$222,000** in recovery for previously under-collected capital costs and allowing **$428,000** in program administration costs, which will be tracked for future recovery. The draft resolution reflects [Senate Bill 1371](https://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill%5Fid=201320140SB1371&ref=calregulatory.com)’s affordability priorities, emphasizes the cost-effectiveness analysis of the [Safety Policy Division](https://www.cpuc.ca.gov/about-cpuc/divisions/safety-policy-division?ref=calregulatory.com) at the CPUC (with all measures far above a $26.88/MCF break-even threshold, and directs SDG&E to incorporate Natural Gas Leak Abatement costs into its Test-Year 2028 General Rate Case rather than continuing to seek standalone ratemaking authorizations. **Instant Analysis**: The draft resolution is indicative of increasing regulatory pressure to balance climate goals with affordability. --- ## **SDG&E Ratemaking Mechanism** This [proposed decision](https://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M579/K066/579066702.PDF?ref=calregulatory.com) authorizes SDG&E to establish a new “Electric Energization Memorandum Account” (EEMA) to track incremental capital costs related to new customer energization projects under Senate Bill 410 (the “Powering Up Californians Act”). The PD authorizes SDG&E to record up to **$51.2 million** between 2024-2026 (which is an 83% reduction from the company’s original request), which is broken down into $10.6 million (2024); $20.8 million (2025); and $19.8 million (2026). SDG&E may annually transfer eligible recorded costs to the Electric Distribution Fixed Cost Account for customer recovery but must demonstrate cost-reasonableness in its General Rate Case. The PD concentrates cost caps in capacity/expansion, new business, and transformers, but provides no authorization for IT enhancements and contingency. The PD narrows eligible cost categories, rejects poorly supported forecasts (e.g., substation land acquisition) and imposes tighter escalation assumptions on new business spending. SDG&E must retain a third-party auditor and follow clear evidentiary standards for future adjustments. ### Pop-Up Announcement: California Regulatory Intelligence URL: https://www.calregulatory.com/pop-up-announcement-california-regulatory-intelligence/ Last updated: 2025-12-01T17:37:13.000Z A single [CPUC](https://en.wikipedia.org/wiki/California%5FPublic%5FUtilities%5FCommission?ref=calregulatory.com) decision can move billions of dollars. But spotting relevant and actionable language in CPUC materials requires procedural fluency and the patience to sift through thousands of filings each year. For 17 years, I've helped clients navigate this flood from inside high-stakes proceedings. Now I'm launching California Regulatory Intelligence (CRI) as an independent intelligence service to decode CPUC proceedings in near-real time. CRI brings the art of discernment and interpretative context to regulatory analysis, something AI still lacks. And long before LLMs were mainstream, we were speed-reading dockets and exhuming rate schedules from opaque documents. - **Our conviction:** Regulatory fluency will become increasingly valuable as California's energy transition creates unprecedented complexity. Grid modernization, storage integration, transportation electrification, and evolving demand will generate thousands of filings with billions in economic impact over the next decade. - **The pilot:** For the next several weeks, CRI is free — we will be monitoring regulatory activity at the CPUC and its sister agencies (CEC, CARB, etc), with a focus on voting meetings, electricity/natural gas rate impacts, and policy developments affecting generation planning and grid reliability. Subscribe to join our test pool. Please share with anyone who might find this information valuable. 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