CPUC Voting Meeting Preview: 10/30/25
Welcome to California Regulatory Intelligence's inaugural briefing. The report below provides a summary of items the CPUC is scheduled to consider at its October 30, 2025 voting meeting. On Friday, we'll provide a full rundown of the meeting results, which will include:
- Any final language changes to items under consideration (11th hour redline edits);
- Notable commissioner comments from the dais; and
- Whether the Commission delayed action on any items until a future meeting.
More detail is provided in the summaries below.
STACK Infrastructure Transmission Service Request
Draft Resolution E-5420 approves (with modifications) PG&E’s request to build and energize new transmission infrastructure (including a 115-kilovolt Ringwood substation) to serve STACK Infrastructure’s 90-megawatt data center in San Jose, at an estimated cost of $85.9 million. STACK Infrastructure is a major data-center developer and operator that runs large-scale, high-capacity facilities to support cloud computing, AI, and enterprise data storage.
To protect ratepayers from stranded cost risk, the draft resolution modifies PG&E’s proposed refund process, capping refunds to STACK at 75% of annual net transmission-related revenues, rather than allowing immediate full refunds under the standard "Base Annual Revenue Calculation" methodology used under Electric Rules 15 and 16. The idea is that this approach slows, but does not reduce, the total refund amount, which is expected to be fully repaid in approximately six years.
The draft resolution also approves some other terms as reasonable, e.g., requiring actual cost payments and removing a 50% discount option. While a group of Community Choice Aggregators raised concerns about transparency in the lead-up to the PD, the Commission finds that those issues are better addressed in the Rule 30 proceeding.
Instant Analysis: This item is another indicator of how data centers are reshaping grid planning. By slowing down refund timelines for STACK’s $50 million interconnection, the CPUC is indicating that large transmission customers must share more risk with the broader system.
Undergrounding Distribution Equipment of Large Electrical Corporations
Draft Resolution SPD-37 refines and updates the CPUC’s Senate Bill 884 undergrounding program, a framework designed to expedite the burial of distribution infrastructure in high fire-thread districts to reduce wildfire risk and improve reliability.
The draft resolution aligns previously adopted Commission guidelines (via Resolution SPD-15, from last year) with the Office of Energy Infrastructure Safety’s 10-Year Undergrounding Plan Guidelines, clarifies cost-recovery procedures, and strengthens oversight.
New changes include:
- New Phase 2 requirements to ensure utilities provide sufficient project-level data;
- Additional conditions for cost recovery (including benefit-cost ratio thresholds and limits on unit-cost variance); and
- Explicit audit procedures for one-way balancing accounts to verify compliance before costs are recovered from ratepayers.
Draft Resolution SPD-37 also establishes a memorandum account cost cap to limit financial exposure.
Instant Analysis: The authorized refinements address the gap between preliminary cost estimates filed early in the project scoping process and actual costs incurred during construction, with goals to ensure ratepayer protections, transparency, and cost discipline while simultaneously advancing state wildfire goals.
Energy Efficiency Market Transformation
This proposed decision, from Commissioner Matt Baker, authorizes ratepayer funding for the California Market Transformation Administrator’s (CalMTA) Room Heat Pump Market Transformation Initiative (MTI) but declines funding for an Induction Cooktop MTI.
Background
- CalMTA is an independent, statewide entity that designs and implements “market transformation” programs that are meant to shift entire markets toward cleaner, more efficient technologies.
- The Room Heat Pump MTI is one of the first programs developed by CalMTA, which accelerates adoption of plug-in, 120-volt room heat pumps across the state.
- The Induction Cooktop MTI was a strategic plan to transform California’s cooking appliance market, shifting from gas to efficient induction technology via upstream market actions rather than just rebates. It still remains a potential future initiative even though it its funding is declined in Commissioner Baker’s PD.
The Baker PD (an alternative PD, or “APD”) sets a $54.87 million budget cap for 2026-2031, which is considerably lower than the $102.4 million set in ALJ Julie Fitch’s competing PD.
The Baker APD also requires CalMTA to submit sensitivity analyses in future MTI applications to better understand market adoption drivers, and – starting with applications after 2028 – to demonstrate efforts to secure non-ratepayer funding.
By December 31, 2028 CalMTA must file a Tier 2 advice letter with a nonprofit transition plan, an amended contract granting the CPUC a perpetual, no-cost license to CalMTA’s cost-effectiveness tool, and the results of an annual audit. The APD establishes annual reporting and audit requirements to ensure accountability, and any discontinuation of MTIs will require Tier 2 advice letters (Tier 2 filings are reserved for substantive but routine matters, e.g., program updates, implementation plans, or compliance filings).
In rejecting the Induction Cooktop MTI and other proposed budget categories, the APD cites ratepayer affordability concerns, federal funding uncertainty, and a need to better align funding levels with performance and policy goals. This narrower authorization still fulfills the statutory obligation to support market transformation under the Public Utilities Code, while encouraging CalMTA to diversify funding sources over time and focus deployment on proven, high-value initiatives.
Instant Analysis: Commissioner Baker’s APD declines to fund the Induction Cooktop MTI, citing affordability concerns and the need for stronger justification before expanding to new programs. The APD prioritizes the more cost-ready Room Heat Pump MTI. Costs will be borne by ratepayers of PG&E, SCE, and SDG&E.
PG&E Natural Gas Curtailment Procedures
This proposed decision authorizes PG&E’s application to revise its natural gas curtailment procedures, which brings them into alignment with procedures used by other major gas utilities.
Previously, PG&E relied solely on localized curtailments to mange pressure on its system of more than 5,600 miles of transmission pipeline. This PD adds systemwide curtailment protocols, which were developed through extensive stakeholder workshops and negotiations with parties including TURN, Cal Advocates, and the Indicated Shippers.
The new framework sequences curtailments in six prioritized customer groups:
- Non-dispatched electric generation;
- Partially dispatched generation;
- Noncore industrial and refinery customer;
- Additional noncore load;
- Non-residential core customers; and
- Residential and small commercial customers (but only in extreme emergencies).
"In its prepared testimony," the PD states, "PG&E makes two important points – curtailing any core customers is highly unlikely and PG&E will exhaust all possible options to avoid curtailing any core customers before doing so."
PG&E's design adheres to the principles of safety, effectiveness, simplicity, and alignment with SoCalGas and SDG&E. The PD authorizes changes to Gas Tariff Rules 1 ("Definitions") and 14 ("Capacity Allocation and Constraint of Gas Services"), requires PG&E to notify noncore customers and update its systems; and directs continued coordination with the CAISO to minimize the need for curtailments.
Instant Analysis: This PD modernizes PG&E’s natural gas curtailment framework by adding clear, systemwide procedures similar to those of SoCalGas and SDG&E. The PD prioritizes curtailments in a manner that protects core customers and grid reliability.
SCE: Diablo Canyon Replacement Bridge Swap Contracts
Draft Resolution E-5419 approves SCE’s request to execute two Diablo Canyon Replacement bridge swap contracts involving bundled Portfolio Content Category 1 (PCC-1) renewable energy credits (and energy). These are short-term energy transactions SCE uses to meet state procurement mandates that were established to replace output from the Diablo Canyon Power Plant when the facility was expected to retire.
For energy to qualify as PCC-1, it must come from a Renewables Portfolio Standard-eligible resource (e.g., solar or wind farm) and be directly delivered into a California balancing authority (e.g., the CAISO). Additionally, the RECs must stay with the power (they cannot be sold separately).
The approved purchase contract delivers approximately 1.7 million megawatt hours of bundled solar energy and RECs from June 2025 – May 2026 to help Edison meet its near-term Diablo Canyon Replacement procurement obligations, as established in 2021’s Mid-Term Procurement Decision (D.21-06-035) and related orders.
The companion sell contract involves roughly 1.86 million MWh of solar and disadvantaged communities RECs over multiple years.
Costs and benefits will be allocated to customers via the Portfolio Allocation Balancing Account, a cost-recovery mechanism the CPUC created to ensure that all customers who benefit from certain utility energy contracts pay their fair share of the costs, even if they have left the utility for another provider. And although a decision last month (D.25-09-007) eliminated future use of bridge contracts, the agreements here remain eligible because they were executed before that.
SCE may pursue cost recovery in full. Contract price details are confidential for market reasons.
Instant Analysis: These short-term contracts are intended to be a stopgap strategy that meets state clean-energy goals without disrupting reliability. Their costs will be allocated to both bundled and departing load customers responsible for this procurement, not just current SCE customers.
Modifications to the Self-Generation Incentive Program
This proposed decision, issued by Commissioner Karen Douglas, initiates the endgame for California’s long-running Self-Generation Incentive Program, which has provided ratepayer-funded financial incentives for installing behind-the-meter clean-energy technologies e.g., battery storage and distributed generation. The CPUC’s SGIP statutory obligations are at their end, and the Commission considers the program to have served its purpose of jumpstarting customer-sited clean tech.
Specifically, the PD establishes the framework for closing out the SGIP, launches the “Greenhouse Gas Reduction Fund” and makes various program changes. The Greenhouse Gas Reduction Fund will use cap-and-trade auction proceeds to support programs that reduce GHG emissions, particularly in disadvantaged communities.
The PD sets December 30, 2025 as the final application and waitlist deadline for the ratepayer-funded SGIP, defines fund allocation for Reservation Request Form submission (i.e., the moment when a project officially reserves or locks in its incentive funds from the program budget) and directs the annual repayment of unused funds to customers via existing mechanisms, with final repayment by 2033.
The PD shortens the SGIP’s Performance-Based Incentive period to two years for new projects and directs that non-residential equity projects may receive up to four additional extensions, under strict conditions.
The PD establishes that low-income Residential Solar and Storage Equity participants are exempt from mandatory Demand Response participation. (Recall that this dedicated SGIP budget category provides incentives for low-income customers to install behind-the-meter solar and battery storage systems.)
The PD also allows program modifications via the advice-letter process (in lieu of petitions for modification) and adopts a final SGIP Measurement and Evaluation plan.
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). In their petition, the Bioenergy Association of California sought to extend (or remove) the December 31, 2025 end date of the Commission’s Bioenergy Market Adjusting Tariff (BioMAT) program.
What is the Bioenergy Market Adjusting Tariff? The BioMAT is a feed-in tariff program that allows small bioenergy projects (up to 5 megawatts) to sell renewable power to the investor-owned utilities at fixed contract prices.
The PD finds that maintaining the program’s sunset date aligns with the state’s Affordability Executive Order (N-5-24) and overarching clean-energy priorities. The PD also finds that the BioMAT program has been chronically underutilized (only about 21% of the program’s 250 megawatt targets has been subscribed to since 2016) and that high per-MWh costs ($127 - $199) far exceed those of other renewable procurement mechanisms.
According to the Commission, multiple BioMAT program modifications over the years failed to boost participation, and alternative procurement pathways (e.g., Renewables Portfolio Standard, Renewable Market Adjusting Tariff, the Bioenergy Renewable Auction Mechanism, bilateral contracts) provide more viable options.
The PD rejects arguments of the Bioenergy Association of California regarding statutory procurement mandates and wildfire mitigation benefits, finding that the program’s costs outweigh its benefits to ratepayers.
Instant Analysis: This PD signals yet more intention by the CPUC to focus on program performance and affordability.
PG&E Condemnation of Assets
This proposed decision pauses a long-running dispute between PG&E and the South San Joaquin Irrigation District over who should control local power lines in that area. The PD dismisses without prejudice an application filed by PG&E, which sought a determination on whether the South San Joaquin District’s proposed condemnation of PG&E’s electric distribution assets would serve the public interest.
The PD concludes that ongoing eminent domain action in San Joaquin Superior Court, which began in 2016 and focuses on the evaluation of the assets in question, should proceed prior to the CPUC’s review. While the CPUC could, in theory, conduct an evidentiary hearing based on valuation scenarios, the PD finds that doing so now would be inefficient and potentially duplicative given the active court case.
Once the valuation trial concludes, PG&E must refile an application with the CPUC, at which point a public-interest analysis, pursuant to the terms of the Public Utilities Code, can occur.
Instant Analysis: The PD is saying that the courts need to finish deciding what PG&E’s assets are worth before further action can be taken, while insinuating that eminent domain fights hinge on price, and no policy questions can be addressed until that matter is settled.
Petition of CCSF for Property Valuation of PG&E
This proposed decision establishes standards and methodologies that the CPUC will use to determine just compensation if the City and County of San Francisco proceeds to condemn portions of PG&E’s electric system that serve San Francisco.
- The PD adopts three guiding principles: (i) PG&E shareholders and remaining customers must be made whole; (ii) the taking (i.e., the legal act of condemnation) is a partial condemnation; and (iii) PG&E may be entitled to business and physical severance damages. "Partial" here means CCSF is not seizing PG&E’s entire system, but simply a portion of it.
- The PD adopts the “before and after rule” as the valuation framework. This entails measuring the difference between the value of PG&E's system before and after the taking, while allowing parties to define the scope of the “before” property and serve testimony accordingly.
- The PD does not prescribe a single valuation method; instead, parties must apply and justify the sales comparison, income, and cost approaches. The PD also emphasizes protecting ratepayers from cost-shifting and requires testimony on how compensation will be allocated between shareholders and ratepayers.
- The PD directs the City and County of San Francisco to produce a single, detailed separation plan, and outlines comprehensive testimony guidelines for both CCSF and PG&E, including asset inventories, engineering details, valuation models, and rate-impact analyses.
- Last, the PD establishes that severance damages must be separately stated and cannot offset asset value.
Instant Analysis: This PD sets the ground rules for how to value PG&E’s San Francisco electric assets if CCSF moves forward with eminent domain. The PD treats the effort as a partial condemnation. The adopted framework seeks to ensure that PG&E shareholders and remaining customers are made financially whole, and that costs are not shifted to other ratepayers.
SDG&E Natural Gas Leak Abatement
Draft Resolution G-3606 denies SDG&E’s request to recover approximately $24.9 million in ratemaking forecasts for its 2024 Natural Gas Leak Abatement Compliance Plan. This rejection includes all Best Practice measures and RD&D projects, on the grounds that none of them were cost-effective, while authorizing only $222,000 in recovery for previously under-collected capital costs and allowing $428,000 in program administration costs, which will be tracked for future recovery.
The draft resolution reflects Senate Bill 1371’s affordability priorities, emphasizes the cost-effectiveness analysis of the Safety Policy Division at the CPUC (with all measures far above a $26.88/MCF break-even threshold, and directs SDG&E to incorporate Natural Gas Leak Abatement costs into its Test-Year 2028 General Rate Case rather than continuing to seek standalone ratemaking authorizations.
Instant Analysis: The draft resolution is indicative of increasing regulatory pressure to balance climate goals with affordability.
SDG&E Ratemaking Mechanism
This proposed decision authorizes SDG&E to establish a new “Electric Energization Memorandum Account” (EEMA) to track incremental capital costs related to new customer energization projects under Senate Bill 410 (the “Powering Up Californians Act”).
The PD authorizes SDG&E to record up to $51.2 million between 2024-2026 (which is an 83% reduction from the company’s original request), which is broken down into $10.6 million (2024); $20.8 million (2025); and $19.8 million (2026). SDG&E may annually transfer eligible recorded costs to the Electric Distribution Fixed Cost Account for customer recovery but must demonstrate cost-reasonableness in its General Rate Case.
The PD concentrates cost caps in capacity/expansion, new business, and transformers, but provides no authorization for IT enhancements and contingency. The PD narrows eligible cost categories, rejects poorly supported forecasts (e.g., substation land acquisition) and imposes tighter escalation assumptions on new business spending. SDG&E must retain a third-party auditor and follow clear evidentiary standards for future adjustments.
Instant Analysis: This PD reflects the Commission’s intent to support faster energization for customers while keeping spending controlled and transparent