MONDAY AGGREGATE: New Friction for Aliso Canyon; New Transmission Questions for PG&E

Today's briefing covers:

• The latest in Aliso Canyon procedural arcana;
• A successor docket for the CPUC's Risk-Based Decision-Making Framework;
• The proper accounting of PG&E transmission assets; and
• Amendments to large-resource Mid-Term Reliability contracts, with RA implications.

ALISO CANYON RULINGS

ALJ Jamie Ormond issued back-to-back rulings April 16-17 in SoCalGas's D.24-12-076 compliance application, expanding the evidentiary record and overriding the utility's resistance to discovery.

The April 16 email ruling (initially reported by CRI here) memorializes directions from the prior day's workshop. SoCalGas must produce information on significant outages outside its service territory by May 1 and inside its territory by May 15. Parties may comment on both outage filings by June 1. Comments on the workshop presentation slides are due April 28, with replies due May 5.

The April 17 ruling grants Sierra Club's motion to compel responses to certain data requests, served February 27. SoCalGas had resisted on relevance grounds, arguing Sierra Club sought to relitigate the past. The ALJ rejects that framing directly, saying:

Parties to a proceeding have broad discovery rights, Applicant should not assume as to know what a Party seeks to do with information sought in a discovery request. And the Commission, rather than SoCalGas, determines both the admissibility of information and evidence and the weight granted to it.

SoCalGas must produce complete, unredacted responses within 10 days. The ruling also establishes prospective NDA timelines for future confidentiality claims: five days to provide an executable NDA, 48 hours to return redlines, 10 days to produce after execution.

INSTANT ANALYSIS: The ALJ is saying that SoCalGas does not control the scope of this proceeding (on outage history, on discovery, or on what counts as relevant). The compel order is notably blunt: the utility cannot prejudge what a party intends to do with requested information. For stakeholders tracking the underlying storage inventory question, the practical consequence is a wider evidentiary record than SoCalGas sought to build. Intervenors now have room to test the utility's reliability narrative against historical outage data and compelled discovery. That shifts the credibility dynamic before any briefing on merits begins.

RISK-BASED DECISION-MAKING

The CPUC is expected to launch a new rulemaking on April 30 to refine the Risk-Based Decision-Making Framework used by electric and gas utilities when proposing safety spending in General Rate Cases.

The new proceeding has four objectives:

• Incorporate a formal risk tolerance standard into the Risk-Based Decision-Making Framework;
• Modify the Risk Assessment & Mitigation Phase filing schedule to give the CPUC's Safety Policy Division more review time;
• Update the Benefit-Cost Ratio methodology; and
• Assess whether small gas utilities Alpine Natural Gas and West Coast Gas should be required to file annual Risk Spending Accountability Reports.

A risk-tolerance track picks up where a 2025 decision (D.25-08-032) left off. That decision defined risk tolerance as the maximum acceptable residual risk after mitigation weighed against the cost of further reduction, but declined to adopt a formal standard, delegating that work here. The CPUC will seek party proposals on both a formal tolerance standard and a benchmark tied to common everyday risks Californians already accept.

An anticipated RAMP schedule track responds to a documented pattern: Safety Policy Division has received deadline extensions on every RAMP filed since 2020 (the Sempra IOUs in 2021, SCE in 2022, PG&E in 2024, Sempra again in 2025), running about two months each time. The new rulemaking proposes modifying Rate Case Plans to formalize additional review time, starting with PG&E's 2028 RAMP application. The proceeding will also address whether informal party comments on RAMP filings should continue.

The Benefit-Cost Ratio methodology track addresses two gaps.

• First, utilities have each applied their own approach to O&M expenses in Benefit-Cost Ratio calculations; the new rulemaking proposes standardizing that treatment.
• Second, the current RAMP Data Template includes a Present Value Revenue Requirement field as optional; the new proceeding will consider making it mandatory to better reflect life-cycle costs in Benefit-Cost Ratio calculations.

A parallel joint application by PG&E, SCE, and SDG&E (A.26-02-005) addresses Benefit-Cost Ratio methodology for the Senate Bill 884 undergrounding program specifically; the new rulemaking cites that process as potentially informative.

INSTANT ANALYSIS: This rulemaking is about the rules that govern how every major safety spending request gets evaluated (in this GRC cycle and the ones that follow). Framework proceedings like this move slowly and attract less attention than contested rate cases, but their outputs are load-bearing.

• The risk tolerance track is where the hardest policy question will surface. California has spent a decade building tools for quantifying utility risk but has never specified how much unmitigated risk is acceptable once those tools run. This proceeding is designed to close that gap.
• The RAMP reform looks administrative but isn't. Safety Policy Division has taken extensions on every RAMP since 2020. More formalized review time means more SPD influence over what enters the GRC record. Parties who engage early gain more than parties who wait.
• The Benefit-Cost Ratio track is where methodology becomes money. Inconsistent O&M treatment and no required Present Value Revenue Requirement metric mean two utilities can propose functionally similar programs and score them differently based on accounting choices. Some programs that currently look favorable will not survive standardization.

TRANSMISSION

PG&E filed Advice Letter 7894-E to confirm that 620 work orders for transmission plant were miscoded to distribution asset classes from 2006 through 2022, and identified and corrected in 2023. The earliest in-service date was 2006, but the miscoded assets did not enter CPUC rates until the 2011 General Rate Case (base-year mechanics meant the 2003 and 2007 GRCs carried zero balance for these assets).

• Total revenue requirement collected through bundled retail rates over 2011–2022 was $73.5 million. Of that, PG&E estimates $7.9 million would have been recovered from wholesale transmission customers had the assets been correctly classified. (This amount is approximately 10%, using a methodology Cal Advocates proposed in the underlying Transmission Revenue Requirement Reclassification Memorandum Account proceeding.)
• The remaining $65.6 million would still have flowed through bundled retail transmission rates. PG&E's position: the previously approved $(42.6) million refund covering 2023–2026 resolves the current-cycle impact, the assets are excluded from CPUC rates starting January 1, 2027 via the 2027 GRC, and no further refund is warranted for 2011–2022. If the Commission orders additional refunds, PG&E recommends the TRRRMA as the vehicle.

The FERC-side argument is mechanical. From January 2006 through April 2019, PG&E operated under stated transmission rates with no true-up mechanism. From May 2019 through December 2022, the TO20 Formula Rate applied (but TO20 was superseded by TO21 on January 1, 2024, closing the error-correction window). PG&E argues retroactive charges to wholesale customers would be contested and likely fail. Internal controls, data validation, and capital accounting training have been updated; PG&E concedes misclassifications may still occur against a $100 billion + plant base.

Protests are due May 7.

INSTANT ANALYSIS: The $7.9 million headline understates the interesting number. The real figure is $65.6 million: what bundled retail customers paid over 2011–2022 for assets that should have been allocated through transmission treatment, and what they will not be refunded under PG&E's recommended outcome. PG&E's logic: the FERC mechanism to recover that $65.6 million from wholesale customers has lapsed, so neither party pays it back. Bundled retail customers absorb the full historical differential.

That is the precedent worth noting. When jurisdictional misclassification is discovered after the relevant FERC rate vehicle has been superseded, the historical cost-allocation error becomes uncollectable from the side that should have borne it. The clean period (2023 onward) is symmetric: FERC picks up the costs, CPUC-jurisdictional customers get refunded. The legacy period is asymmetric: bundled retail customers overpaid, wholesale customers underpaid, and PG&E's recommendation leaves both sides where they are.

The key questions for any protest: whether 2011 is the correct start date, whether the 10% wholesale share is defensible across all four GRC cycles (it ranged from 9.2% to 12.1%), and whether TRRRMA is the right vehicle if additional refunds are ordered. The main takeaway: plant classification sits at the CPUC/FERC seam, and when errors span multiple rate-case vintages, the window to recover from the correct customer class may close before the error is discovered. That is a feature of the regulatory construct, not a PG&E-specific failure.

MID-TERM RELIABILITY

PG&E filed Advice Letter 7895-E, seeking CPUC approval of amendments to two Mid-Term Reliability RFO Phase 3 Power Purchase Agreements with Atlas Solar XII and XIII (Atlas North 1 and 2).

The projects (co-located 375 MW solar PV + 225 MW four-hour lithium-ion battery storage each, located in La Paz County, Arizona) were originally approved in Resolution E-5370. For compliance counting, each project delivers 150 MW solar + 225 MW storage toward MTR and D.26-02-057 obligations.

The amendments change the delivery term start from December 1, 2027 to September 1, 2028, a nine-month delay; the 15-year term is unchanged. Projected commercial operation remains June 15, 2028. The projects are expected to contribute approximately 2,200 GWh annually to PG&E's GHG-free energy goals and about 0.6 MMt CO2 in emissions reductions.

Two facts the advice letter underplays.

• First, ownership: the Merrimack Energy Independent Evaluator report shows Atlas Solar XII and XIII were Hanwha/174 Power Global subsidiaries at original execution in February 2024, with Lydian Energy now the operating parent. 174 Power Global and Lydian both participated in amendment negotiations.
• Second, the market benchmark: Merrimack compared the amended terms against shortlisted solar-plus-storage offers from PG&E's 2025 GHG-Free RFO (offers received July 18, 2025), and recommended approval, finding negotiations "conducted fairly and reasonably."

The filing suggests that development fundamentals are in reasonable shape. The main power transformers and high-voltage breakers (the long-lead items that typically drive delays) are already procured, with Engineering, Procurement, and Construction execution targeted for Q2 2026.

The Large Generator Interconnection Agreement under CAISO queue position Q1402 is fully executed with CAISO and DCR Transmission, LLC. The projects qualify for a 30% Investment Tax Credit plus 10% Domestic Content and 10% Energy Community adders, though the seller carries the risk if any of those credits fail to materialize.

Cost recovery mirrors the original agreements: net costs flow through the Portfolio Allocation Balancing Account, with above-market costs PCIA-eligible under the terms of a 2023 decision (D.23-02-040). Protests are due May 7.

INSTANT ANALYSIS: The ownership story is of particular interest. 174 Power Global executed the original PPAs in February 2024; Lydian Energy is now the operating parent, and both entities sat at the negotiation table. Schedule delays concurrent with a control transition is a recognizable pattern in solar-plus-storage development. The question isn't whether these specific amendments clear (they will) but whether other Hanwha-originated projects in the California interconnection queue are running the same playbook.

On the approval itself, PG&E's unstated argument is straightforward: re-soliciting against 2025 GHG-Free RFO pricing would cost ratepayers more than tolerating a nine-month delay, and a decision last fall (D.25-09-007) made the alternative compliance math worse by killing bridge contracts.