May 14 CPUC Meeting Results: PG&E Reliability Assumptions Shift, Wildfire Costs Repriced, and Diablo Oversight Changes Through 2030
At today's CPUC voting meeting, the Commission adopted the following items.
- A decision authorizing a deal between PG&E and TURN over how much natural gas PG&E needs available during extremely cold winter days through 2027.
- A decision authorizing SCE's transformation of significant Woolsey Fire costs into a long-term bond payment plan.
- A decision finding that future Diablo Canyon Power Plant cost reviews should use final market values instead of earlier forecast estimates when determining whether costs stayed within the law’s 115% review threshold.
Full summaries of the CPUC's final, redlined versions of these items are provided below the following housekeeping items.
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GAS SYSTEM RELIABILITY
A 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. Thursday's decision 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. Today's decision 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 decision in A.26-01-007 authorizes SCE to issue approximately $1.951 billion in Recovery Bonds to refinance costs arising from the 2018 Woolsey Fire. The total consists of three components:
- $1.639 billion in Wildfire Expense Memorandum Account costs approved for recovery in the December 2025 Woolsey Fire settlement decision (D.25-12-023), representing about 35% of SCE's total WEMA balance through May 2025, net of approximately $1 billion in insurance recoveries;
- $299.2 million in estimated pre-securitization debt financing costs accrued while the bonds are being arranged; and
- $12.7 million in estimated upfront bond issuance costs.
The remaining 65% of SCE's recorded WEMA costs (approximately $3.663 billion) was permanently disallowed in the prior settlement.
Under the financing structure, SCE transfers Recovery Property (its right to collect the Fixed Recovery Charge) to a legally separate, bankruptcy-remote Special Purpose Entity. The Special Purpose Entity issues the bonds, and proceeds flow back to SCE. Bond repayment occurs through the Fixed Recovery Charge, a non-bypassable surcharge on all existing and future electricity consumers in SCE's service territory, regardless of provider. CARE and FERA customers are exempt by statute. The charge is subject to true-up adjustments at least annually, and more frequently if a shortfall is anticipated, with excess collections credited back through SCE's Base Revenue Requirement Balancing Account. Once the financing order is issued, it becomes irrevocable.
SCE estimates that securitization will produce approximately $811 million in net present value savings relative to traditional rate-base treatment, measured against the utility's CPUC-authorized 7.59% return on rate base. The CPUC accepts the savings case while noting that the actual figure will depend on final bond terms, tranche structure, and market interest rates at issuance.
The proceeding moved fast. On March 13, 2026, SCE and Cal Advocates filed a joint stipulation resolving all issues in the scoping memo, including financing structure, customer allocation, and the just-and-reasonable findings, eliminating the need for evidentiary hearings. SCE is targeting Q3 2026 for bond issuance. If adopted, this would mark SCE's fifth Recovery Bond authorization under the Assembly Bill 1054 framework, following three wildfire mitigation CapEx securitizations and the Thomas Fire/Montecito debris flow financing order (D.25-08-033).
INSTANT ANALYSIS: The CPUC is running the AB 1054 securitization playbook. A settlement in the underlying cost-recovery case arrived in December, a stipulation resolving the financing application followed in March, and a final decision came on May 14. The underlying costs have been vetted, and Cal Advocates had little reason to challenge a financing structure built around a straightforward Net Present Value savings case.
The practical result is that $1.951 billion in wildfire liability (already negotiated down substantially from SCE's original $5.635 billion request) converts into bondholder-grade debt backed by statutory repayment certainty, non-bypassable collection authority, and tranche maturities capped at 33 years.
For large customers and load-serving entities, the Fixed Recovery Charge ends up on the bill regardless of provider, sits outside traditional rate base, and remains in place through future rate cases. Importantly, the $811 million savings figure compares securitization to rate-base treatment, not to further cost disallowance.
The more relevant question for sophisticated customers is cumulative exposure: how this new Woolsey layer accumulates against existing AB 1054 wildfire mitigation and Thomas Fire securitization charges that are already embedded in bills. Today's decision does not consolidate that picture.
DIABLO CANYON
A decision grants in part the Alliance for Nuclear Responsibility petition to modify a 2024 decision (D.24-12-033) approving $722.6 million in cost recovery for extended operations at Diablo Canyon.
The sole modification: for purposes of the 115% statutory threshold under the Public Utilities Code, the CPUC will use the final Resource Adequacy Market Price Benchmark rather than the forecast benchmark when evaluating whether Diablo Canyon costs remain insulated from further reasonableness review. The change applies to all Diablo Canyon forecast proceedings through 2030.
The threshold matters because costs below 115% of forecast are shielded from additional review under Senate Bill 846's expedited framework. The forecast 2025 RA Market Price Benchmark was $42.54/kW-month. The final benchmark, recalculated after methodology reforms adopted in a 2025 decision (D.25-06-049), fell to $11.21/kW-month. The Alliance for Nuclear Responsibility argued that embedding the higher forecast value into the statutory baseline artificially widened the cushion beneath the threshold, shielding operating costs from scrutiny the statute did not intend to foreclose. PG&E supported the modification but argued it should apply uniformly across all Diablo Canyon forecast years rather than 2025 alone. The decision adopts PG&E's position.
The decision denies everything else. No revenue requirement is revised. No prior findings are reopened. Forecast-to-final benchmark differences have already flowed into rates through the ERRA-style true-up process.
INSTANT ANALYSIS: By requiring the final RA Market Price Benchmark rather than the forecast benchmark for the 115% statutory threshold test, the decision reduces the forecast-driven cushion between actual costs and the point at which additional scrutiny could return. In 2025, the difference is substantial: $11.21/kW-month final versus $42.54 forecast. Applied to every Diablo Canyon extended-operations forecast proceeding through 2030, this is a standing rule, not a one-year accounting correction.
CRUDE OIL TRANSPORTATION
A decision in A.25-06-026 authorizes a 10% rate increase for Crimson California Pipeline L.P.'s Southern California crude oil system, effective August 1, 2025, while rejecting the company's later attempt to reach a 13.16% increase.
Crimson operates about 300 miles of crude oil pipelines connecting Southern California oil fields to Los Angeles Basin refineries. The decision finds the 10% request justified, concluding the higher rates support reasonable, reliable, and safe operations while bringing Crimson's test-year return on equity to 10.82%.
The decision also authorizes retroactive recovery to August 1, 2025, allowing Crimson to collect the difference between billed and approved rates plus interest at the 90-day commercial paper rate. The decision denies Crimson's January 2026 miscellaneous filing seeking an additional 3.16%.
INSTANT ANALYSIS: For California refiners and crude shippers, the key takeaway is this: the CPUC will approve a full 10% mid-cycle pipeline rate increase on a basic financial showing when no opposition emerges (no protests were filed in this proceeding). Retroactive recovery to August 2025 preserved Crimson's economics despite the delayed approval, reinforcing Section 455.3 as a workable ratemaking pathway for operators facing rising costs.
DELAYED ITEMS
At the behest of President John Reynolds, the CPUC delayed action on a proposed decision that implements California's Shared Renewables Portfolio. CRI's full summary of this item is available here. The item is now tentatively scheduled for consideration on June 11.