WEDNESDAY AGGREGATE: Final CPUC Voting Meeting of 2025; Palomar Decarbonization Project; TIMPBA Briefs

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.) Key items under consideration include:

• COST of CAPITAL: A proposed decision 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/After-Tax Weighted Average Cost of Capital 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 in the Long-Term Gas Planning docket implements Senate Bill 1221 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 approves a major settlement 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 seeking CPUC approval and cost recovery for its Palomar Decarbonization Demonstration Project, an integrated renewable hydrogen system installed at the Palomar Energy Center, 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 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 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 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. (More CRI coverage of this proceeding is available here.)

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.

GAS SYSTEM PLANNING

PG&E filed an advice letter 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 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), 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 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.)

NATURAL GAS STORAGE

Wild Goose Storage/Lodi Gas Storage filed a joint application 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.)

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 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.)
• 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.)
• OVERLAP with NON-CAPACITY WORK: PG&E, SCE, and SDG&E jointly filed an advice letter 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.)