December 4, 2025 CPUC Voting Meeting Preview

Agenda topics 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;
• Consolidate Transportation Electrification reporting;
• Set the 2026 Wildfire Fund non-bypassable charge;
• Approve Edison's tariffed on-bill financing pilot;
• Terminate the BioMAT program; and
• Deny CRPC’s request to classify the Union Island Pipeline as a public-utility asset.

IVANPAH LIVES (FOR NOW)

Draft Resolution E-5429 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). 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 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 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 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 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 updates the CPUC’s Senate Bill 884 undergrounding program by expanding and tightening the review, cost-justification, and audit requirements established under Resolution SPD-15 and aligned with Energy Safety’s 2025 guidelines for 10-year Electric Undergrounding Plans. 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 that the added bureaucracy risks delaying shovel-ready work and reducing near-term fire protection.

ENDING the SELF-GENERATION INCENTIVE PROGRAM

This proposed decision sets the closeout process for the ratepayer-funded Self-Generation Incentive Program (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 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 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) 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 has said.)

The PD continues the "Technical Assistance Program" (which was established in 2022) 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 program, SCE's Charge Ready Transport program, and SDG&E's Power Your Drive for Fleets Program.

INSTANT ANALYSIS: The PD doubles down on the CPUC’s post-D.22-11-040 retrenchment strategy. It consolidates reporting, simplifies oversight, and keeps only the most defensible Transportation Electrification elements alive while the major rebate programs remain paused.

WILDFIRE NON-BYPASSABLE CHARGE

This proposed decision 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 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.

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 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 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 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.

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, Qualifying Facility standard offers, Integrated Resource Planning procurement, and Bioenergy Renewable Auction Mechanism) 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, 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 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 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.