December 18 CPUC Voting Meeting Results: Cost of Capital; Long-Term Gas Planning; Woolsey Fire

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 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 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 program through December 31, 2025.
• Union Island Pipeline: This proposed decision denies a request 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 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.

• 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, she framed the Commission’s task as steering between Scylla and Charybdis – 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 designates California’s initial set of priority neighborhood decarbonization zones pursuant to Senate Bill 1221, 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 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.

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 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.

WOOLSEY FIRE

This decision 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 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 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 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 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.

DISTRIBUTION PLANNING

Resolutions E-5413 and E-5414 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 (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 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 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 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 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.