WEDNESDAY AGGREGATE: Interconnection Reform; Gas AMI; SoCalGas Rates

Today's briefing blends macro-policy (Rule 21) with infrastructure accountability (gas AMI, the Sempra Utilities' Cost Allocation Proceeding), and notable housekeeping (transmission, Union Island, Diablo Canyon).

Collectively these items provide a snapshot of alternating currents at the CPUC: electrification reform on one side and the unwinding of the legacy gas-system on the other.

Rule 21 Distribution-Level Interconnection

Parties recently filed reply comments in response to the Commission rulemaking whose aim is to modernize Rule 21, which governs how Distributed Energy Resources and electric vehicles connect to the distribution grid.

Across reply comments, parties converge on the need for near-term reform to clear procedural bottlenecks that delay clean-energy projects and threaten eligibility for federal tax credits.

Most stakeholders (including the Solar Energy Industries Association, Vote Solar, the Interstate Renewable Energy Council, NRDC, PearlX, and the Vehicle-Grid Integration Council) urge the Commission to prioritize two fixes:

• Reforming "Screen Q," which pushes many projects into the CAISO’s lengthy transmission-level queue; and
• Enforcing utility accountability for missed interconnection timelines.

Clean-energy advocates support measurable penalties and a first-phase decision by mid-2026, while utilities favor a collaborative approach focused on automation, portals, and clearer processes.

Instant Analysis: This rulemaking is the state’s central arena for interconnection reform, linking distributed generation, storage, and EV integration under one modernization push. The CPUC faces strong pressure to fix Screen Q, enforce utility accountability, and clarify how vehicle-to-grid systems are treated under Rule 21. Interconnection reform is no longer niche policy housekeeping but a true test of California’s ability to translate clean-energy ambition into procedural competence before 2026 tax-credit windows close.

PG&E Advanced Metering Infrastructure

PG&E, Cal Advocates, TURN, and the Small Business Utility Advocates filed a supplemental statement supporting settlement of PG&E’s Comprehensive Gas Advanced Metering Infrastructure (GAMI) Replacement Program case.

The settlement addresses three scoping issues:

• PG&E’s responsibility for early module failures;
• Cost allocation between shareholders and ratepayers; and
• Treatment of undepreciated investments in retired modules.

PG&E maintained that premature failures were due to battery life, not mismanagement, while the advocacy groups argued for shared responsibility and cost disallowances.

Under the agreement, the parties cut PG&E’s 2023–2026 capital spending by about $65 million, reduced expenses by $7.1 million, and removed $1.049 million in return on equity tied to $9.83 million in undepreciated failed equipment.

The compromise (about $17 million below PG&E’s original request) balances risk between customers and shareholders and resolves the disputed issues without litigation. The joint filing asserts the settlement is reasonable, consistent with prior CPUC decisions, and in the public interest because it ensures accountability while enabling progress toward PG&E’s next-generation Gas AMI 2.0 system.

Instant Analysis: This settlement reflects a course correction in PG&E’s handling of its failed gas metering technology. After years of contention over who should pay for prematurely failing AMI modules, consumer advocates secured modest but meaningful concessions (roughly $73 million in combined reductions and the removal of shareholder returns on undepreciated assets). This shows a growing regulatory insistence on shared accountability for asset underperformance: utilities must demonstrate prudence, not merely technical inevitability, when infrastructure fails early. Future technology-replacement cases (e.g., grid sensors, communications upgrades) could face similar scrutiny, emphasizing lifecycle transparency, warranty recovery, and cost-sharing discipline over blanket ratepayer coverage.

Sempra Utilities' Cost Allocation Proceeding

In our November 10 Monday Aggregate, we summarized parties' protests and responses to the September Cost Allocation Proceeding filing of SoCalGas/SDG&E (the Sempra Utilities).

Recall that, with the new CAP application, the Sempra Utilities seek to revise natural gas rates, modify storage allocations, and adjust rate-design elements effective January 1, 2027. Parties raise concerns about rate impacts, storage reductions, embedded cost methodologies, allocation fairness, and insufficient justification for key proposals. Below are micro-summaries of their remarks.

The Southern California Generation Coalition (SCGC)'s protest has since surfaced on the CPUC's website. Below is a short summary of their position.

• SCGC contends that SoCalGas misleadingly compares its proposed 2027–2029 rates to “normalized” (rather than actual) September 2025 rates, giving a false impression of decreases when, by SCGC’s analysis, certain rates (e.g., electric-generation transmission-level service) would actually increase roughly 23%. The coalition also challenges SoCalGas’s plan to replace the storage and balancing regime adopted in the 2024 CAP settlement, noting reductions in total storage inventory, injection, and withdrawal capacities without sufficient justification.
• Further, SCGC opposes SoCalGas’s reallocation of $116 million in backbone transmission costs (plus safety-program expenses) to local transmission (an idea rejected in two prior CAPs) and its proposal to cut available backbone transmission service capacity in triennial open seasons from the current 3,775 MMcfd to 110% of forecasted design standards.
• SCGC also objects to SoCalGas’s plan to use over-collections from the Noncore Storage Balancing Account to offset a $4 million undercollection in the Firm Access Storage Rights account, calling it an improper ratepayer subsidy for a failed off-system delivery program.

Instant Analysis: This proceeding is shaping up to be one the most contentious rate cases in years. Across the board, parties are challenging the transparency, internal logic, and evidentiary support of the Sempra Utilities' application. SCGC adds particular force to these objections by accusing SoCalGas of misleading rate comparisons (using “normalized” rather than actual 2025 data) to imply rate decreases that may, in fact, be increases for electric generators. SCGC also targets SoCalGas's plan to abandon the 2024 storage and balancing framework, which had been painstakingly negotiated, and criticizes proposed reductions in storage inventory and backbone transmission capacity as inadequately justified and potentially harmful to reliability.

In short, representatives of every major customer group see Sempra’s embedded-cost reallocations as opaque, self-serving, or both. Even Shell Energy North America's partial praise for scheduling reforms underscores how narrow the utilities’ defensible ground may be.

This case now functions as an early stress test of post-electrification gas economics, where shrinking load, aging infrastructure, and legacy cost recovery are colliding.

SDG&E 2026 ERRA Forecast

Administrative Law Judge Lirag issued a proposed decision approving SDG&E's Forecast 2026 Energy Resource Recovery Account submission. The PD authorizes a total of $824.1 million, a large increase from $122.3 million in 2025.

The increase stems largely from higher Portfolio Allocation Balancing Account (PABA) costs and lower market price benchmarks. The PD finds SDG&E’s forecasts reasonable, covering procurement, local generation, competition transition, and GHG allowance returns, with 10% increases expected for bundled customers and 30% to 40% increases for unbundled customers.

The PD also adopts SDG&E’s 2026 Electric Sales Forecast of 17,432 GWh, derived from California Energy Commission demand modeling, and authorizes 2026 Power Charge Indifference Adjustment rates. The PD resolves disputes over pre-2019 banked Renewable Energy Credits (RECs) by requiring SDG&E to use only post-2018 RECs unless separately approved. The PD directs SDG&E to implement the new rates effective January 1, 2026 via advice letter.

Comments are due December 1. The earliest the CPUC will consider this item is December 4.

Instant Analysis: This PD showcases the CPUC’s continued tolerance for steep procurement cost increases when justified by market benchmarks and balancing account true-ups, even amid affordability pressures. The 10% to 14% bundled rate hike reflects structural shifts (especially in PABA accounting and Resource Adequacy/REC valuation) rather than discrete utility mismanagement. Still, it underscores how volatile market benchmarks can translate directly into double-digit retail swings. The PD's guardrails on pre-2019 RECs show the Commission’s sensitivity to transparency and fairness in cost allocation, even as it largely affirms SDG&E’s modeling.

SDG&E Mid-Term Reliability Contracts

SDG&E filed Advice Letter 4755-E (available here) to obtain approval of two battery energy storage contracts with Golden Fields Solar VI, LLC: a 44 megawatt, 4-hour system and a 48 MW 8-hour system. Both are 15-year power purchase tolling agreements expected online by June 1, 2027.

The projects were selected through SDG&E’s Tranche 3 Integrated Resource Planning RFO, evaluated using a least-cost/best-fit methodology and verified by PA Consulting as Independent Evaluator.

SDG&E requests cost recovery via the Power Charge Indifference Adjustment (2023 vintage for the 4-hour system and 2021 vintage for the 8-hour system).

Instant Analysis: These contracts mark SDG&E’s continued move toward storage-centric reliability solutions, illustrating how utilities are using multi-duration battery portfolios to satisfy long-lead and zero-emission mandates.

Transmission Costs

On November 4, 2025 PG&E met with advisors to Commissioner Matt Baker to discuss its application (A.24-09-015) for recovery of recorded expenditures through the Transmission Revenue Requirement Reclassification Memorandum Account (TRRRMA).

PG&E explained that the TRRRMA proceeding is intended to prevent double recovery of costs while allowing the company to reconcile jurisdictional mismatches between CPUC and FERC rates. PG&E emphasized that the company has already refunded over $1.36 billion under FERC’s TO18-20 settlement (which resolved disputes over Common, General, and Intangible plant allocations) and that PG&E is now seeking CPUC authorization to recover up to $472.8 million in costs previously reviewed in other rate cases.

PG&E asserted that these costs were incurred, audited, and approved for recovery in both CPUC and FERC contexts, providing extensive supporting documentation, including invoices and ledger data. The company argued its showing meets the burden of proof and that recovery through the TRRRMA is reasonable, consistent with Commission precedent (including a similar SCE case), and ensures no double counting.

Instant Analysis: PG&E is using the TRRRMA as a jurisdictional bridge: a mechanism to true-up costs between CPUC and FERC without appearing to double-dip. By highlighting the $1.36 billion in FERC refunds as evidence of good faith while seeking CPUC recovery of previously vetted costs, PG&E frames its filing as procedural housekeeping rather than new spending.

Union Island Pipeline

On November 5, 2025 California Resources Production Corporation (CRPC) met with Commissioner Karen Douglas's Chief of Staff, Kourtney Vaccaro. At issue is a proposed decision that denies a request of 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. (More details on the PD are available in our November 30 CPUC Voting Meeting Preview).

CRPC urged the Commission to withdraw the PD, arguing that it contains significant legal, procedural, and factual deficiencies. CRPC asserted that the PD departed from established CPUC precedent, applied an incorrect legal standard, and resolved issues not designated as threshold matters, thereby denying parties an opportunity to address them.

CRPC also cited factual inaccuracies arising from what it viewed as an incomplete evidentiary record. In addition, CRPC emphasized the potential environmental and economic impacts if the Union Island Pipeline were forced to cease operations, including the loss of local jobs, loss of royalty income for roughly 200 San Joaquin County landowners, and increased reliance on imported natural gas that could raise greenhouse-gas emissions.

Instant Analysis: CRPC's outreach underscores how consequential the Union Island denial could be for the company’s in-state gas operations and for local producers tied to its network. By stressing job losses, royalty impacts, and higher greenhouse emissions from out-of-state imports, CRPC is reframing the issue as one of economic and environmental harm rather than legal qualification. But the CPUC’s PD rests squarely on jurisdictional and evidentiary grounds (whether CRPC meets the statutory definition of a “gas corporation” with valid franchises and active operations).

Diablo Canyon Cost Recovery

Administrative Law Judge Michelle Cooke issued a ruling that denies a motion by Californians for Green Nuclear Power (CGNP) seeking to disqualify ALJ Jack Chang from PG&E's 2026 Diablo Canyon cost-recovery proceeding (see our update here for additional details.)

The ruling concludes that no bias or financial conflict exists and leaves ALJ Chang assigned to the Diablo Canyon proceeding. (CGNP has a Substack post here that responds.)

Instant Analysis: The CPUC maintains that any rulings issued against CGNP in this proceeding were for procedural reasons (and not motivated by bias).