December 18, 2025 CPUC Voting Meeting Preview

On December 18, the CPUC will convene for its final business meeting of the year. The agenda 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 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.
• 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 citing Alfred Kahn's seminal book The Economics of Regulation in a 2024 dais conversation. That exchange preceded a decision where the CPUC reduced the IOUs' routine Cost-of-Capital Mechanism adjustment from 50% to 20%, effective January 1, 2025.

LONG-TERM NATURAL GAS PLANNING

• SUMMARY: 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.
• 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 and detailed appendix 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 approves a settlement 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 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 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 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.
• 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, the Energy Producers and Users Coalition, and the Small Business Utility Advocates.

SDG&E's WILDFIRE MITIGATION COSTS

• SUMMARY: A proposed decision 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 & C);
  • The revised authorized revenue requirement and undercollection balance (Appendix A); and
  • The bill-impact consequences of 3- vs. 6-year amortization scenarios (Appendix D).

UTILITY FINANCES

• SUMMARY: A proposed decision 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 and SCE 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 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 (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 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 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 (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 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, with associated grid-needs reporting in the Grid Needs Assessment.
• 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.

AFFORDABILITY

• SUMMARY: A proposed decision 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 approves with modifications SCE’s Tariff On-Bill financing pilot, while rejecting proposals from SDG&E, SoCalGas, and Silicon Valley Clean Energy (SVCE).
  • Tariffed on-bill financing 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 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 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 denies a petition for modification filed by the Bioenergy Association of California to modify a 2020 CPUC decision (D.20-08-043), which had extended the Bioenergy Market Adjusting Tariff (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, Qualifying Facility standard offers, Integrated Resource Planning procurement, and BioRAM.
  • Citing both its authority to retire ineffective programs and the Governor’s 2024 affordability directive, 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 adopts, with select modifications, the 2025 Renewables Portfolio Standard Procurement Plans 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 denies a request 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.