Results of October 30, 2025 CPUC Voting Meeting

Below is a review of the CPUC's Thursday, October 30 business meeting. Note that the decisions and resolutions summarized here reflect final, redlined language changes that the Commission distributed earlier this week. Wherever applicable, we incorporated those changes into our final summaries. (See our meeting preview here to compare.)

STACK Infrastructure Transmission Service Request

Resolution E-5420 approves (with modifications) PG&E’s request to construct and energize new transmission facilities (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 supporting cloud computing, AI, and enterprise data storage.

To protect ratepayers from stranded-cost risk, the resolution modifies PG&E’s refund process, capping annual refunds to 75% of actual net revenues from the customer (defined as the transmission component of the bill and per-meter charge) and adjusting for the Income Tax Component of Contribution. The refund eligibility period is extended from 10 to 15 years. This approach slows (but does not reduce) the total refund, which is expected to be fully repaid in approximately six years.

The resolution also finds reasonable the use of actual cost payments, the removal of a 50% discount option, and other contract terms. Cal Advocates (a.k.a. the Public Advocates Office at the Commission) supported the modifications as necessary ratepayer protections, while a group of Community Choice Aggregators raised broader transparency issues that the Commission deferred to the Rule 30 proceeding.

INSTANT ANALYSIS: This resolution illustrates how California’s accelerating data-center buildout is reshaping grid-planning norms. By lengthening refund timelines and tightening revenue-assurance requirements, the CPUC is saying that large-load customers must now share greater long-term risk before ratepayers assume costs.

PG&E Natural Gas Curtailment Procedures

The Commission adopted a decision authorizing PG&E’s application to revise its natural gas curtailment procedures, which brings the company into alignment with procedures used by other major gas utilities.

Previously, PG&E relied solely on localized curtailments to manage pressure on its system of more than 5,600 miles of transmission pipeline. This decision adds systemwide curtailment protocols, which were developed through extensive stakeholder workshops and negotiations with parties including The Utility Reform Network, Cal Advocates, and the Indicated Shippers.

The new framework sequences curtailments in six prioritized customer groups:

1. Non-dispatched electric generation;
2. Partially dispatched generation;
3. Noncore industrial and refinery customer;
4. Additional noncore load;
5. Non-residential core customers; and
6. Residential and small commercial customers (but only in extreme emergencies).

"In its prepared testimony," the decision 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. Thursday's decision:

• 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.

(A redlined version of Gas Tariff Rule 1 is available here, and a redlined version of Gas Tariff Rule 14 is available here.)

INSTANT ANALYSIS: This modernization aligns PG&E’s procedures with SoCalGas and SDG&E, creating a uniform statewide curtailment hierarchy that safeguards core customers while clarifying coordination duties with the CAISO.

SCE Diablo Canyon Replacement Bridge Swap Contracts

Resolution E-5419 approves two offsetting bridge swap contracts between Southern California Edison and the Clean Power Alliance involving bundled Portfolio Content Category 1 (PCC-1) renewable energy credits and associated energy.

The purchase contract counts toward SCE’s Mid-Term Reliability procurement obligations under Decisions 21-06-035 and 24-09-006, which were established to replace output from the Diablo Canyon Power Plant, when that facility's future was in question and decommissioning was in play.

Under the approved buy contract, SCE will receive approximately 1.7 million megawatt hours of bundled solar energy and RECs from June 2025 through May 2026. The companion sell contract covers approximately 1.86 million MWh of solar and disadvantaged-community RECs over multiple years. (For energy to qualify as PCC-1, it must be RPS-eligible and delivered into a California balancing authority with RECs retained by the buyer.)

Payments under the contracts are recoverable in full through SCE’s Portfolio Allocation Balancing Account, subject to prudent administration, ensuring that both bundled and departing-load customers share costs and benefits.

Although D.25-09-007 has since eliminated future bridge contracts, the specific agreements addressed here remain eligible because they were executed before that decision. Contract price details are confidential.

INSTANT ANALYSIS: These short-term bridge contracts were intended to maintain compliance and reliability during the Diablo Canyon transition window. Cost allocation across bundled and departing-load customers reflects the CPUC’s emphasis on consistent treatment across all service classes.

Condemnation of PG&E Assets

The Commission adopted a decision that pauses a long-running dispute between PG&E and the South San Joaquin Irrigation District (SSJID) over who should control local power lines in that area.

The decision dismisses, without prejudice, PG&E’s application for a Section 851 determination on whether SSJID’s proposed condemnation of PG&E’s electric distribution assets would serve the public interest.

The decision concludes that the San Joaquin Superior Court must complete its eminent-domain valuation trial (which began in 2016) before the CPUC undertakes any public-interest analysis. While the Commission could, in theory, hold its own evidentiary hearing using valuation scenarios, Thursday's decision finds that doing so now would be inefficient, duplicative, and premature given the ongoing court case.

Once the valuation trial concludes, PG&E must refile an application with the CPUC, at which point a public-interest review under the Public Utilities Code can proceed.

INSTANT ANALYSIS: By deferring to the San Joaquin Superior Court, the CPUC is reinforcing that valuation (not public interest) is the gating issue in eminent-domain disputes.

Property Valuation of PG&E

The CPUC adopted a decision that establishes the standards, appraisal methods, and filing requirements it will use to determine just compensation under California's eminent-domain process if the City and County of San Francisco (CCSF) condemns portions of PG&E’s electric system that serve San Francisco.

The decision adopts three guiding principles:

• PG&E shareholders and remaining customers must be made whole and left financially neutral to the acquisition;
• The taking (i.e., the legal act of condemnation) constitutes a partial condemnation; and
• PG&E may be entitled to both business and physical severance damages. “Partial” means CCSF would acquire only part of PG&E’s electric system, not the whole utility.

The decision adopts the “before-and-after rule” as the valuation framework (i.e., measuring the difference between the value of PG&E’s property before and after the taking) while allowing parties to define the scope of the “before” property and justify it in testimony.

The decision does not select a single valuation method; instead, parties must apply and reconcile the sales comparison, income, and cost approaches, demonstrating how each conforms to California law and avoids double-counting. The decision also requires testimony on how compensation will be allocated between shareholders and ratepayers to ensure rate neutrality, consistent with the CPUC’s duty to prevent cost-shifting.

The decision requires CCSF to produce a single, detailed separation plan and directs both parties to provide testimony on asset inventories, valuation models, and rate impacts. Severance damages must be stated separately and may not offset the value of the part taken.

Energization: SDG&E Ratemaking Mechanism

By a vote of 4-1 (Commissioner Darcie Houck dissented) the Commission adopted a decision authorizing SDG&E to establish a new Electric Energization Memorandum Account (EEMA) to track incremental capital costs for customer energization projects under Senate Bill 410 (the Powering Up Californians Act).

• The decision authorizes SDG&E to record up to $51.188 million between 2024 and 2026 (an 83% reduction from the company’s original $310.127 million request) broken down as $10.561 million (2024), $20.793 million (2025), and $19.834 million (2026). SDG&E may annually transfer eligible recorded costs to the Electric Distribution Fixed Cost Account for customer recovery but must demonstrate that those costs were just and reasonable in its next General Rate Case.
• The decision concentrates authorized spending in capacity/expansion, new business, and transformer materials, but rejects funding for information technology enhancements and contingency.
• The decision narrows eligible cost categories, excludes poorly supported forecasts e.g., substation land acquisition, and applies tighter escalation assumptions to new business spending. SDG&E must retain a Commission-selected third-party auditor and follow clear evidentiary standards for any future adjustments.

"The record in this proceeding," said Commissioner Matt Baker, "showed that SDG&E is effectively managing its customer energization requests and making progress to reduce the backlog that it does have."

He continued:

If this changes in the near future, SDG&E will be able to make its case for future energization investment needs beyond what is authorized in the cap today. Specifically, the utility can file a petition to modify this decision...as it can with any other commission decision. And the utility's next rate case application is set to be filed in the next year where energization costs can be viewed more holistically across the utility's complete budget and energization demands.

In dissent, Commissioner Houck noted her agreement with many parts of the decision and lauded SDG&E on its energization efforts overall. But she said that the decision improperly authorizes backward-looking cost recovery for 2024 expenses that have already been incurred, which is a violation of SB 410's requirement for "upfront" cost caps based on forecasted data.

Houck contends that this maneuver inappropriately shifts financial risk from the utility to ratepayers, especially since SDG&E may not have actually exceeded its total GRC-authorized energization budget when viewed at the category level rather than sub-category level. Additionally, Houck is concerned that changes to how incremental costs are calculated could allow SDG&E to count more spending as "incremental" than they actually overspent, creating perverse incentives.

INSTANT ANALYSIS: This outcome walks a tightrope of urgency and oversight: i.e., enabling faster energization while imposing fiscal guardrails. Commissioner Houck’s dissent highlights a growing Commission debate over statutory intent versus operational pragmatism.

SDG&E Natural Gas Leak Abatement

Resolution G-3606 approves in part and denies in part SDG&E’s 2024 Natural Gas Leak Abatement Compliance Plan. The resolution authorizes approximately $2.9 million in total recovery across 2025–2026, including $2.57 million for selected Best Practice measures (limited to costs incurred through July 28, 2025), $112,668 for RD&D, and $222,000 for previously under-recovered capital costs, while denying funding for cost-ineffective proposals such as Aerial Methane Monitoring.

This resolution reflects Senate Bill 1371’s affordability priorities and the Safety Policy Division’s cost-effectiveness analysis, which found all measures above a $26.88/MCF break-even threshold. The resolution directs SDG&E to incorporate future Natural Gas Leak Abatement costs into its Test-Year 2028 General Rate Case instead of continuing to seek stand-alone ratemaking authorization.

INSTANT ANALYSIS: This resolution is an indicator that leak-abatement funding is tightening: only cost-effective, mandatory measures will survive CPUC scrutiny, and all future recovery must be folded into GRC cycles rather than standalone filings.

Delayed Until November

Notably, the CPUC delayed action on the following items. (The entire hold list available here.)

• ENERGY EFFICENCY: Commissioner Matt Baker held competing proposed decisions that address energy efficiency market transformation initiatives. Baker's own 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 (note that an 11th-hour, redlined change increased the $102.4 million in ALJ Fitch's PD to $114.6 million).  These items are now tentatively scheduled for consideration by the CPUC on November 20.
• UNDERGROUNDING GUIDELINES: At the request of President Alice Reynolds, the Commission held Draft Resolution SPD-37, which refines and updates the CPUC’s Senate Bill 884 undergrounding program, a framework designed to expedite the burial of distribution infrastructure in high fire-threat districts to reduce wildfire risk and improve reliability. This item is now tentatively scheduled for consideration by the CPUC on November 20.
• SELF-GENERATION: Commissioner Karen Douglas held a proposed decision that, if adopted, would initiate 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. This item is now tentatively scheduled for consideration by the CPUC on November 20.
• BIOENERGY: At the request of staff, the Commission delayed action on a proposed decision that 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. This item is also tentatively scheduled for consideration on November 20 (the most recent version of the PD is available here).