MONDAY AGGREGATE: Proposed Decisions on Flex Alerts, GCIM Year 31, and SDG&E ERRA Compliance
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 in R.25-09-004 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, and others opposing continuation altogether on affordability or equity grounds. (See CRI's previous Flex Alert coverage here.)
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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) 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 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 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 in a 17-year-old proceeding granting SCE a certificate of public convenience and necessity to construct the Alberhill System Project 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: The 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 granting LS Power Grid California a certificate to construct the Power Santa Clara Valley Project, 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 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 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 letter 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.
- 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) 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 that, if adopted, would deny ENGIE North America’s petition to modify a 2021 decision in the Self-Generation Incentive Program rulemaking (D.21-06-005).
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.