May 14 CPUC Voting Meeting Preview: PG&E NG Peak-Day Reset, $1.95B Woolsey Securitization, Diablo Cost Threshold Shift

The CPUC's May 14 voting meeting agenda features a potential reset of PG&E’s natural gas peak-day supply outlook, $1.951 billion in SCE's Woolsey Fire securitization, and a stricter Diablo Canyon cost threshold.

GAS SYSTEM RELIABILITY

A proposed decision approves a full settlement between PG&E and TURN resolving PG&E's updated Peak Day Supply Standard for winters 2024-2025 through 2026-2027.

The case stems from a 2023 decision (D.23-11-069), which directed PG&E to refresh its peak-day demand and supply modeling. TURN challenged three inputs (core demand, electric generation demand, and Redwood Path supply availability) then settled rather than litigate. The PD finds the resulting standard reasonable, within the evidentiary range, and consistent with its directive to improve methodology.

The settlement reworks three inputs across three winters, generating 24 changed cells in PG&E's reliability table.

• Core demand and electric generation both drop;
• Combined northern-southern supply rises 92 MMcfd; and
• Every settled value falls between the parties' litigated positions.

Those changes reduce the pre-investment 2024-2025 shortfall from -380 MMcfd to -135 MMcfd and move winters 2025-2026 and 2026-2027 into surplus before any new wells come online (a year earlier than PG&E's filed analysis projected). TURN won the argument that PG&E's peak-day numbers were inflated.

INSTANT ANALYSIS: PG&E filed an analysis showing a -380 MMcfd shortfall heading into 2024-2025 and a system that would not reach surplus until 2026-2027 even after new wells came online. The settled numbers say something quite different. The 2024-2025 deficit shrank to -135 MMcfd, and the system crossed into surplus in 2025-2026 before any new wells were built. TURN's testimony forced PG&E to accept lower demand forecasts and higher supply availability than it had filed, and the arithmetic followed.

The battle now moves to A.25-05-009, where PG&E will re-file demand trajectories, electric generation burn, and supply assumptions for winter 2027-2028 forward. The PD expressly preserves both parties' freedom to relitigate every input. The settlement closes a three-winter window without forcing a Commission ruling on whether PG&E's underlying methodology produces inflated capacity needs (a question TURN will almost certainly bring back in the General Rate Case).

WOOLSEY FIRE

A proposed decision authorizes SCE to securitize approximately $1.951 billion in Woolsey Fire Wildfire Expense Memorandum Account (WEMA) costs through Recovery Bonds, with projected ratepayer savings of $811 million on a Net Present Value basis versus traditional utility financing.

The underlying just-and-reasonable determination was made in a 2025 decision (D.25-12-023), which approved approximately $1.972 billion in WEMA cost recovery (35% of SCE's gross request, net of $1 billion in insurance and third-party recoveries) and disallowed the remaining 65% (approximately $3.663 billion). The $1.951 billion reflects that approved recovery, adjusted for upfront costs and a revised pre-securitization accrual window.

The PD's just-and-reasonable finding on the bond issuance traces to a joint stipulation between SCE and Cal Advocates. Woolsey is SCE's fifth Assembly Bill 1054 securitization, after three capex financing orders (D.20-11-007, D.21-10-025, D.23-02-023) and the $1.629 billion Thomas/Montecito financing order (D.25-08-033). Cumulative AB 1054 issuances for Edison will reach approximately $5.2 billion once Woolsey closes.

SCE transfers recovery property (principally the right to collect a non-bypassable Fixed Recovery Charge) to a bankruptcy-remote Special Purpose Entity that issues the bonds and repays investors from Fixed Recovery Charge revenues.

The cash-flow model runs in three steps each payment period.

• First, the bond payment obligation (principal, interest, ongoing costs) is converted to a billing requirement adjusted for uncollectibles and days-sales-outstanding.
• Second, that requirement is allocated by the General Rate Case Allocation Factor from the Marginal Cost and Revenue Allocation Settlement Agreement (D.22-08-001). The CARE/FERA portion is reallocated to non-exempt classes via the existing CARE discount allocation, placing the full revenue requirement on non-exempt customer classes.
• Third, per-kWh clearing rates are calculated against forecast sales. The model runs over two payment periods, adopts the higher clearing rate, and nets prior Trustee-held collections and projected revenues under current rates against the next requirement. Over- and under-collections roll into the subsequent true-up.

INSTANT ANALYSIS: The Woolsey Fire revenue requirement was decided last year and is not relitigated here. Moving $1.951 billion off rate base produces approximately $811 million in Net Present Value savings versus traditional financing. The trade is a long-lived, non-bypassable surcharge engineered for payment certainty, with true-ups that adjust as needed to keep collections aligned with debt service regardless of load volatility.

Cumulative SCE AB 1054 issuances reach approximately $5.2 billion across five securitizations, though concurrent Fixed Recovery Charge exposure on customer bills at any given moment depends on the amortization schedules of the earlier CapEx orders. Each financing order produces its own Fixed Recovery Charge running on its own schedule.

The GRC Allocation Factor carries through to each Fixed Recovery Charge, the CARE/FERA portion is reallocated through the existing CARE discount allocation, and the full revenue burden falls on non-exempt customer classes. For large C&I, each new financing order layers on top of whatever earlier-vintage Fixed Recovery Charges remain outstanding.

DIABLO CANYON COST RECOVERY

A proposed decision grants in part the Alliance for Nuclear Responsibility (A4NR)'s petition to modify the December 2024 Diablo Canyon cost-recovery decision (D.24-12-033, as modified by D.25-07-041).

Going forward, when the CPUC evaluates whether PG&E's actual costs come in below 115% of forecast under Section 712.8(h)(1), it will now use the final Resource Adequacy Market Price Benchmark rather than the forecast value to calculate RA substitution capacity costs.

This change follows a 2025 decision (D.25-06-049) in the ERRA/PCIA Reform docket, which overhauled the benchmark methodology and brought the 2025 final value down to $11.21/kW-month against a $42.54 forecast, with a parallel correction on the 2024 side from $28.65 to $26.26. Inside a $722.6 million revenue requirement that includes a $210 million RA substitution line item, the distance between forecast and final determines whether the threshold imposes meaningful review or absorbs almost anything.

The PD accepts A4NR's argument that an inflated forecast benchmark widens the 115% buffer and shields operating costs from the review the statute contemplates, and agrees that the final benchmark better tracks how the statute measures cost performance. The PD declines to restate the approved revenue requirement or rewrite prior findings, reasoning that ERRA-style true-ups already in place have moved the corrected benchmarks into rates without anyone needing to reopen the decision.

The modification runs through 2030 rather than applying only to 2025, a scope PG&E supported and the PD adopts because the same reasoning recurs every year.

INSTANT ANALYSIS: The PD closes an opening in the Diablo Canyon cost-recovery framework that would have let a meaningful slice of operating costs pass the 115% threshold without scrutiny. A bigger problem sits in the benchmark framework itself. The CPUC already concluded in D.25-06-049 that the prior methodology was vulnerable to manipulation and inconsistent with the statutory indifference requirement, and this PD keeps that diagnosis from carrying through into a separate statutory test where the consequences are heavier because the cutoff on reasonableness review is absolute.

SHARED RENEWABLES

A proposed decision implements California's Shared Renewables Portfolio without the funding that was intended to support it. Federal Solar for All money is gone, terminated by the Environmental Protection Agency in August 2025. A $33 million state appropriation reverted to the General Fund in June 2025. The program will proceed anyway.

The PD ties the new Community Renewable Energy tariff to the Renewable Market Adjusting Tariff program. Proposals for capacity adders, expanded project sizes, time-of-delivery adjustments, and above-avoided-cost compensation were all rejected as inconsistent with the Public Utilities Code. Nonparticipating customers will not pay above avoided costs.

INSTANT ANALYSIS: The basic concept of this program survives. The economics that would have driven participation do not.

CRUDE OIL TRANSPORTATION

A proposed decision approves Crimson California Pipeline’s request to increase crude oil transportation rates on its Southern California system by 10%, effective August 1, 2025. The PD rejects a late attempt by Crimson to push the increase higher. The 10% increase is supported by Crimson’s revenue requirement and a projected 10.82% return on equity.

Crimson’s additional 3.16% request is denied on procedural grounds. The PD authorizes retroactive recovery of the approved 10% back to August 1, 2025, with interest at the 90-day commercial paper rate. Costs will fall on large commercial shippers.

INSTANT ANALYSIS: No shipper protested the application, no safety disputes were raised, and no ESJ friction materialized. The approved rates land within an acceptable commercial band for refinery-linked counterparties. Crimson has been billing at pre-August 2025 rates for about nine months; retroactive recovery with interest creates a meaningful cash collection against an approximate $30 million test-period revenue base.