FRIDAY AGGREGATE: IRP Cycle 2024-2026 Changes; Woolsey Fire Financing Order; Aliso Canyon Filing
Today's CPUC briefing includes:
- An ALJ ruling setting the requirements and schedule for the next round of individual Integrated Resource Plans;
- An SCE application seeking CPUC approval of a financing order to securitize costs associated with the 2018 Woolsey Fire, via the issuance of recovery bonds;
- A SoCalGas application telling the CPUC that Aliso Canyon remains necessary for reliability, and that reducing inventory now would be a mistake;
- Parallel CalCCA applications for rehearing of CPUC decisions that approved the 2026 ERRA Forecasts for PG&E and SCE;
- A draft resolution that increases funding for the California Distributed Generation Statistics platform;
- A joint IOU advice letter updating the terms and conditions of the Emergency Load Reduction Program;
- A scoping memo establishing the procedural framework for LS Power’s "Power the South Bay" transmission project CPCN application;
- A PG&E advice letter seeking approval of an exceptional-case agreement to serve Genentech’s South San Francisco campus expansion, with up to 30 MW of transmission-level service by 2034; and
- SoCalGas's notice of a planned curtailment that will affect a limited set of noncore customers in the Riverside area.
INTEGRATED RESOURCE PLANNING
Administrative Law Judge Fitch issued a ruling in R.25-06-019 setting the requirements and schedule for the next round of individual Integrated Resource Plans for the model years 2026, 2028, 2030, 2035, 2040, and 2045.
The ruling moves the IRP filing deadline from May 5 to June 1, 2026, aligning it with regularly required procurement compliance filings, and provides detailed direction on the modeling inputs, assumptions, and templates that load-serving entities must use.
LSEs are required to base their plans on:
- Updated Commission modeling inputs (including 2024 Integrated Energy Policy Report load forecasts);
- Revised RESOLVE assumptions (with enhanced geothermal systems and generic long-duration energy storage added as default candidate resources);
- Updated resource costs and potentials; and
- Finalized greenhouse gas benchmarks allocated proportionally by load to meet sector targets of 25 MMT by 2035 and 8 MMT by 2045.
These load forecasts were adjusted after CCAs submitted forecasts that in aggregate fell below the 2024 IEPR reference case, prompting the California Energy Commission to escalate individual forecasts at sector growth rates and apply pro rata adjustments to reach 100% of service area totals. PG&E, SCE, and SDG&E had objected that CCA submissions failed to account for projected data center load growth.
Commission staff also provided a representative statewide least-cost portfolio as planning guidance, though LSEs retain flexibility to submit both a required conforming portfolio that meets assigned GHG targets and an optional preferred portfolio that goes beyond those requirements.
The ruling mandates use of the Narrative Template, Clean System Power Calculator, and Resource Data Template, clarifies treatment of long lead-time resources, and sets July 15 as the deadline for comments on filed IRPs.
INSTANT ANALYSIS: This ruling fixes the analytical frame for the 2024–26 IRP cycle by standardizing load forecasts, emissions benchmarks, and modeling assumptions ahead of individual filings. Compliance risk now sits primarily with portfolio composition and procurement follow-through, rather than forecast discretion. The staff RESOLVE portfolio functions as a reference case, centered on solar, storage, geothermal, and wind, with gas capacity retained for reliability through 2045 and continued reliance on Path 26 and Path 15 transmission expansions. Aligning IRP and procurement filings places greater emphasis on internal consistency between planning assumptions and executable procurement paths.
WOOLSEY FIRE
SCE filed an application seeking CPUC approval of a financing order under the Public Utilities Code to securitize costs associated with the 2018 Woolsey Fire through the issuance of recovery bonds.
The request follows the CPUC’s December 2025 settlement decision authorizing recovery of approximately $1.97 billion in just and reasonable Woolsey Fire–related costs recorded in SCE’s Wildfire Expense Memorandum Account, with those costs to be financed rather than recovered through traditional ratemaking. (See our summary of that decision here.)
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SCE proposes issuing $1.95 billion in recovery bonds through a bankruptcy-remote special purpose entity, supported by a non-bypassable fixed recovery charge on customer bills and a Commission-approved true-up mechanism to ensure timely bond repayment.
SCE argues that securitization will materially reduce customer costs on a net present value basis compared to conventional utility financing, with estimated savings exceeding $800 million, while preserving credit quality through structural protections, annual true-ups, and Commission oversight.
INSTANT ANALYSIS: This application implements the Woolsey Fire settlement by securitizing $1.95 billion of approved wildfire costs through recovery bonds backed by a non-bypassable fixed recovery charge. The goal is lower-cost financing and rate smoothing versus traditional utility debt. The proposal tracks prior wildfire securitizations, especially the Thomas Fire, and is largely executional rather than substantive. Key review points will be the expedited schedule, finance team oversight of final bond terms, and confirmation that charge allocation and exemptions align with existing Commission practice
ALISO CANYON
SoCalGas filed a compliance application to request CPUC review of Energy Division’s 2025 Aliso Canyon Biennial Assessment, which recommends reducing the facility’s maximum inventory level by 10 Bcf from the current 68.6 Bcf authorized in a 2024 decision (D.24-12-076).
- SoCalGas argues that the Biennial Assessment understates continued reliance on Aliso Canyon due to overly optimistic assumptions about pipeline availability, receipt-point utilization, and storage performance, and that reducing inventory would increase gas and electric reliability risks, price volatility, and costs to ratepayers.
- Notably, SoCalGas emphasizes that Staff themselves hedged the reduction recommendation, stating that "a smaller incremental or no reduction may be appropriate" given forward price risks and near-term factors including increased US LNG exports and the startup of the Energía Costa Azul LNG facility in Baja California.
- The application contends that Aliso Canyon remains critical to meeting peak demand, particularly during 1-in-10 winter conditions, and that corrected modeling inputs show higher withdrawal needs than assumed by Commission Staff.
- SoCalGas further asserts that the economic analysis is limited, cannot reliably predict price impacts, and fails to account for reductions to the Unbundled Storage program, which would compound adverse ratepayer effects.
- The application also argues that applying Staff's own threshold methodology consistently would show winter 2026-2027 forward prices exceed the threshold, creating an internal inconsistency in the analysis.
Accordingly, SoCalGas asks the Commission to decline to authorize any reduction in Aliso Canyon’s maximum inventory at this time and to authorize an increase in the inventory level if necessary to maintain system reliability and just and reasonable rates.
INSTANT ANALYSIS: SoCalGas is directly challenging Energy Division’s first Aliso Canyon biennial recommendation, arguing that any inventory reduction is premature and increases reliability risk due to optimistic assumptions around pipeline availability, receipt-point utilization, and storage performance. The application frames the dispute as a modeling credibility issue while leveraging Staff's own hedging language against the recommendation, and highlights added ratepayer exposure from higher price volatility and reductions to the Unbundled Storage program.
ERRA FORECASTS
CalCCA filed parallel applications for rehearing that challenge the CPUC’s approval of 2026 ERRA Forecast decisions for PG&E and SCE (D.25-12-027 and D.25-12-028, respectively – see our summaries here).
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- CalCCA argues that both decisions unlawfully set Power Charge Indifference Adjustment rates in ways that harm departing load and violate long-standing indifference principles.
- CalCCA also contends the CPUC improperly allowed the utilities to retroactively apply a new Resource Adequacy Market Price Benchmark methodology adopted in a 2025 decision (D.25-06-049) to value 2025 RA portfolios, even though PCIA rates for that year were already being collected under the prior, settled methodology.
- According to CalCCA, this midstream methodological change eliminated the required true-up and instead resulted in prohibited retroactive ratemaking, exceeding the Commission’s authority, lacking adequate findings, and reflecting an abuse of discretion.
Last, CalCCA challenges the Commission’s approval of proposals by both SCE and PG&E to assign zero value to pre-2019 banked Renewable Energy Credits used for bundled customer Renewables Portfolio Standard compliance in 2025 and 2026. CalCCA argues that this treatment unlawfully deprives departed customers of benefits they helped fund and violates statutory indifference requirements and Commission precedent requiring such RECs to be valued at the RPS MPB.
INSTANT ANALYSIS: These parallel applications present a coordinated challenge to how the Commission handled PCIA true-ups in the 2026 ERRA cycle, with CalCCA arguing that retroactive application of the revised RA Market Price Benchmark crossed from lawful balancing-account practice into prohibited retroactive ratemaking. The filings also dispute the interim acceptance of zero-value treatment for pre-2019 banked RECs, framing it as a violation of statutory indifference requirements and settled PCIA precedent. If credited on rehearing or appeal, the arguments could affect not only 2026 PCIA outcomes for PG&E and SCE but also the viability of applying D.25-06-049 across other ERRA proceedings.
DISTRIBUTED GENERATION
The CPUC issued Draft Resolution E-5436, which increases funding for the California Distributed Generation Statistics platform to $2.6 million per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion.
The draft resolution directs PG&E, SCE, and SDG&E to improve data quality by revising their online interconnection application interfaces, including standardized equipment drop-downs, stronger cost validation, corrected system size calculations, and retroactive fixes to existing data.
The item also orders a rebranding of DGStats to reflect the inclusion of non-distributed-generation programs and authorizes publication of anonymized Contractors State License Board disclosure document data. Finally, the IOUs must host a public workshop and improve tracking and reporting of system decommissioning to address growing accuracy gaps as legacy systems retire.
The earliest the Commission will consider this item is February 26.
INSTANT ANALYSIS: This draft resolution upgrades DGStats into durable regulatory infrastructure by nearly tripling funding, allowing inflation adjustments, and positioning the platform as a long-term backbone for forecasting, planning, and enforcement. The draft resolution targets data quality failures directly, mandating automated sizing, validated equipment lists, retroactive corrections, standardized cost inputs, and structured decommissioning tracking (changes that will alter historical and forward-looking Distributed Energy Resource analyses). Publishing anonymized CSLB disclosure data and rebranding the platform expands DGStats from a reporting site into a transparency and compliance tool with real market discipline effects.
EMERGENCY LOAD REDUCTION PROGRAM
PG&E, SCE, and SDG&E jointly filed an advice letter to update the Emergency Load Reduction Program terms and conditions pursuant to a 2023 decision (D.23-12-005). The filing does not change the underlying ELRP program design, but instead makes statewide, largely administrative clarifications related to enrollment, disenrollment, settlement, baseline calculations, and incentive eligibility.
The filing also formally sunsets the residential Power Saver Rewards program (ELRP Sub-Group A.6) following its authorized expiration at the end of 2025. The utilities also propose utility-specific clean-ups, including clearer rules around missing meter data, forfeiture of incentives when service accounts close, distinctions between aggregators and service providers, updated baseline and day-of adjustment mechanics, and streamlined customer authorization and data-sharing language.
Protests are due February 4.
INSTANT ANALYSIS: This filing is administrative, but it clarifies and enforces payment eligibility under ELRP. The formal sunset of Power Saver Rewards closes the residential chapter and narrows ELRP’s scope back to non-residential customers and aggregations. New language around missing meter data, baseline construction, and service-account status places greater responsibility on participants and aggregators to maintain clean data and continuous enrollment. The practical takeaway is that ELRP remains available, but settlement mistakes now carry explicit financial consequences.
TRANSMISSION WORK
Commissioner Karen Douglas issued a scoping memo in A.24-05-014, setting the scope, schedule, and procedural framework for LS Power’s Power the South Bay transmission project CPCN application. The project, selected by the CAISO as a reliability-driven upgrade, was modified from a mixed AC/DC design to an exclusively 230 kV AC line, with an estimated $677.7 million capital cost recovered through CAISO transmission rates. The CAISO requires the project to be in service by June 1, 2028, and LS Power has agreed to cost-containment controls enforceable by the CAISO.
INSTANT ANALYSIS: This scoping memo places the Power the South Bay CPCN on a fast, low-friction track. The primary substantive risk is not need or cost recovery (which are largely anchored by CAISO selection and FERC-jurisdictional transmission rates) but CEQA, specifically the acknowledged temporary (but significant) air-quality impacts at the Santa Clara terminus. The Commission is already framing an overriding considerations finding, indicating that system reliability and regional benefits will be weighed against localized construction impacts. With a briefing-only schedule and a Q1 2026 decision target, the proceeding is positioned for approval based on the existing record.
Separately, PG&E filed an advice letter seeking approval of an exceptional-case agreement to serve Genentech’s South San Francisco campus expansion with up to 30 MW of transmission-level service by 2034.
The project relies on bespoke Rules 2, 15, and 16 agreements, with Genentech paying actual costs for transmission upgrades and special facilities, largely insulating existing ratepayers. Refunds are contingent on realized load and revenues, using standard Rule 15 Base Annual Revenue Calculation mechanics, while certain design and special facility costs remain non-refundable.
INSTANT ANALYSIS: This is a procedurally conservative, low-risk transmission service filing that cleanly walls off cost exposure from existing ratepayers through actual-cost treatment, limited refunds, and non-refundable special facilities. Its real significance is precedential: it shows how PG&E is still using Rules 2, 15, and 16 exceptional cases to onboard large transmission-level loads while Rule 30 remains interim, preserving flexibility for bespoke negotiations.
NATURAL GAS CURTAILMENT
SoCalGas issued a planned maintenance notice advising that certain noncore customers in (and around) Riverside will be subject to a temporary natural gas service reduction pursuant to Rule 23.
The curtailment is scheduled from 6:00 a.m. February 2, through 6:00 p.m. February 6, although the duration may vary depending on work completion. Affected customers will receive individual maximum-usage limits in advance of the event and are advised to coordinate directly with their SoCalGas account representatives and monitor Envoy for updates. The notice reflects a localized, planned maintenance action rather than a systemwide constraint.
INSTANT ANALYSIS: This is a routine, localized maintenance curtailment affecting a limited set of noncore customers in the Riverside area. It does not indicate broader system constraints, policy change, or near-term reliability risk for the Southern California gas system. The item is most relevant as an operational heads-up for affected industrial customers and does not warrant broader market or regulatory concern absent clustering or escalation of similar notices.