FRIDAY AGGREGATE: Woolsey Fire Update; IOUs' Energization Costs; SCE's IT/Enterprise Resource Funding

Today's report includes the following items.

• WOOLSEY FIRE: A prehearing conference convened in the proceeding where SCE seeks a financing order under the Public Utilities Code to securitize $1.951 billion in Woolsey Fire-related costs recorded in its Wildfire Expense Memorandum Account. Relatedly, a Commissioner Matt Baker scoping memo sets an intervenor testimony deadline of March 4.
• ENERGIZATION: PG&E, SCE, and SDG&E jointly filed a motion in R.24-01-018 seeking authorization to establish memorandum accounts to track costs associated with funding an Energy Division contract to analyze energization data.
• ENTERPRISE RESOURCE PLANNING: In February 20 reply briefs, parties offered conflicting views on SCE's request to recover costs for its NextGen Enterprise Resource Planning program. SCE argues the program is necessary because its existing ERP system faces imminent obsolescence, posing operational and cybersecurity risks.
• NATURAL GAS RESEARCH: PG&E filed an application for rehearing of CPUC Resolution G-3618, arguing that the CPUC unlawfully denied recovery of approximately $7.2 million in Gas Research, Development, and Demonstration program costs incurred in 2023-2024.
• NATURAL GAS STORAGE: A SoCalGas advice letter lowers the storage injection fuel retention, which slightly improves the economics of injecting gas into storage ahead of the new storage year.

WOOLSEY FIRE

A February 19 prehearing conference convened in the proceeding where SCE seeks CPUC approval for a financing order under the Public Utilities Code to securitize $1.951 billion in Woolsey Fire-related costs recorded in its Wildfire Expense Memorandum Account (WEMA), which were found just and reasonable in the December 2025 settlement decision (D.25-12-023).

SCE's position is that securitization through recovery bonds will lower financing costs passed to ratepayers compared to the alternative established in the settlement: a five-year amortization financed with long-term debt.

At the prehearing conference, Cal Advocates highlighted two areas of particular focus:

• The appropriate duration and tenor of the recovery bonds (noting that in the Thomas Fire case, SCE initially proposed 35-year bonds before the parties agreed to a weighted average of up to 20 years); and
• The cumulative ratepayer impact of these bonds layered on top of Edison's three prior Assembly Bill 1054 financing orders and the Thomas Fire bonds.

SCE and Cal Advocates agreed these issues are fairly subsumed within the broader Thomas Fire scoping framework. Cal Advocates does not currently anticipate factual disputes but indicated it is preparing data requests and will focus its testimony on bond duration and bill impacts, including analysis of tenors ranging from 15 to 30 years.

A notable exchange occurred around the interpretation of the Woolsey settlement decision. Edison maintained the settlement offered only two paths: securitization or five-year amortization, and suggested this binary framing influenced its decision to settle.

ALJ DeAngelis pushed back, suggesting the CPUC is not necessarily limited in this proceeding to evaluating only those two options, particularly regarding alternative amortization periods. Cal Advocates aligned with the ALJ's broader reading. The issue was left unresolved but noted for the record.

Commissioner Matt Baker's prepared remarks struck a balanced tone, acknowledging securitization as a valuable tool to ease rate shock while cautioning that the details (particularly bond duration and ultimate ratepayer impact) require careful scrutiny.

Commissioner Baker's subsequent scoping memo formally adopted nine scoped issues centered on:

• Whether the proposed bonds are just, reasonable, and consistent with the public interest;
• Whether they reduce rates relative to traditional financing;
• The appropriate customer allocation for fixed recovery charges; and
• Reporting requirements.

Intervenor direct testimony is due March 4, rebuttal testimony March 6, with a status conference that same day to determine whether evidentiary hearings (set for March 9) are actually needed or whether parties will stipulate testimony into the record.

Opening briefs are due March 16, reply briefs March 23, and all parties agreed to a shortened Section 311 comment period.

INSTANT ANALYSIS: The battle here isn't whether SCE securitizes $1.951 billion in Woolsey costs (D.25-12-023 already blessed recovery), it's how long ratepayers carry the bonds.

• Cal Advocates is modeling tenors from 15 to 30 years and cited cumulative stacking with Edison's three existing AB 1054 orders plus the Thomas Fire bonds, which is new analytical territory that could set precedent for every future Section 850 filing across all three IOUs.
• Meanwhile, ALJ DeAngelis pushed back hard on Edison's claim that the Woolsey settlement locked the Commission into a binary choice of securitization or five-year amortization, suggesting the CPUC retains authority to evaluate alternative amortization periods. Edison's counsel warned that such a reading could retroactively undermine the settlement framework itself.

The March 4 Cal Advocates testimony will define the entire range of dispute, and the present-value comparison between securitization savings and shorter-tenor alternatives becomes the decisive exhibit.

ENERGIZATION

PG&E, SCE, and SDG&E jointly filed a motion in R.24-01-018 seeking authorization to establish memorandum accounts to track their costs associated with funding a CPUC Energy Division contract to analyze energization data.

The motion implements language in a 2024 decision (D.24-09-020), which requires the large electric utilities to collectively fund $1 million per year for five years to improve the CPUC’s ability to collect, analyze, track, and publicly report energization data and progress toward adopted energization and upstream capacity upgrade targets.

Each utility’s share would be allocated based on its percentage of California-jurisdictional electric revenues as of the decision’s issuance, with PG&E and SCE each responsible for about 47% and SDG&E about 6%.

The utilities explain that the CPUC directed them to establish these accounts so the Energy Division’s contracting costs can be recorded but not recovered from ratepayers unless later approved in a ratesetting proceeding. They also note uncertainty regarding whether the $5 million contract funding is distinct from or part of a separate “Commission-managed evaluation budget” to be sought through the state budget process, requesting clarification on that point.

If approved, each utility would file advice letters to formally create the memorandum accounts, enabling the CPUC to bill them for the contract costs once the Executive Director executes the agreement.

INSTANT ANALYSIS: This filing is a procedural compliance step. The IOUs are seeking to track (not yet recover) their shares of a $5 million CPUC-directed contract to strengthen Energy Division oversight of energization timelines, with any ratepayer recovery deferred to a later proceeding. The overarching story, though, is that the Commission is building a permanent data-monitoring function around interconnection performance. That points to tougher scrutiny of utility timelines going forward and potential downstream pressure if targets are missed.

ENTERPRISE RESOURCE PLANNING

In February 20 reply briefs, parties offered conflicting views on SCE's request to recover costs for its NextGen Enterprise Resource Planning (ERP) program.

• SCE argues the program is necessary because its existing ERP system faces imminent obsolescence, posing operational and cybersecurity risks, and contends that its cost forecasts, implementation plan, risk management approach, and projected long-term benefits are reasonable and supported by extensive evidence. SCE seeks approval of approximately $1.08 billion in capital expenditures, $238 million in O&M costs, and a two-way balancing account to manage cost uncertainty while returning savings to customers.
• SCE argues that parties' failure to respond to its rebuttal testimony in their reply briefs should be treated as a concession on those issues, and contends that delaying the business transformation scope would increase costs by 30% and reduce customer savings by 20%.
• Cal Advocates maintains that SCE has not met its burden of proof for many disputed costs, recommends approving substantially reduced funding, and opposes the requested two-way balancing account on legal and policy grounds, arguing it would shift risk to ratepayers during an affordability crisis.
• Cal Advocates also argues that $212.754 million already authorized in SCE's 2025 General Rate Case should be applied to fund NextGen ERP implementation and that SCE has not demonstrated why costs from completed or obsolete IT projects cannot be reallocated, and raises procedural concerns about SCE's late-filed 2024 recorded data compromising Cal Advocates' ability to conduct a thorough review.
• Small Business Utility Advocates (SBUA) likewise urges denial or major modification of the application, emphasizing the high risk of cost overruns, delays, overstated benefits, and near-term rate impacts, and proposing that only limited "obsolescence" work proceed (if at all) under stricter cost controls tied to demonstrated benefits.
• SBUA proposes that SCE's rate of return on capital be contingent on achieving a positive benefit-cost ratio, a mechanism SCE characterizes as unprecedented and akin to retroactive ratemaking, citing multiple court decisions and CPUC precedents rejecting similar benefit-contingent penalties. SBUA also aligns with TURN's stance in this proceeding that excess cost recovery should require a separate application and that any cost overrun review must consider whether SCE delivered forecasted benefits.

INSTANT ANALYSIS: This proceeding is about who bears digital transformation risk. SCE is framing the ERP replacement as unavoidable infrastructure due to system obsolescence, while intervenors argue the broader transformation is discretionary and should not be financed by ratepayers.

• The first question that needs answering is whether the Commission will approve the approximately $482 million transformation scope at all (both SBUA and TURN argue it should be denied outright, with SBUA proposing SCE defer to its next GRC).
• If the Commission denies the transformation scope, the balancing account debate becomes moot for nearly half the requested funding. If some or all of the program advances, the conflict shifts to the requested two-way balancing account. Approval would shift cost-overrun risk to customers and set a precedent that large utility IT modernization qualifies as recoverable infrastructure. Denial would keep that risk with shareholders.

In short, this case is a testing ground for whether enterprise software inevitably becomes rate-base infrastructure in California.

NATURAL GAS RESEARCH

PG&E filed an application for rehearing of CPUC Resolution G-3618, arguing that the Commission unlawfully denied recovery of approximately $7.2 million in Gas Research, Development, and Demonstration program costs incurred in 2023 ($3.53 million) and 2024 ($3.67 million).

SDG&E Wildfire Costs + Provider of Last Resort Framework

An SDG&E General Rate Case decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures

CALIFORNIA REGULATORY INTELLIGENCEMC

• PG&E contends the Commission misinterpreted the 2023 General Rate Case decision (D.23-11-069) by applying a new requirement for pre-approval of RD&D spending retroactively, even though the decision directed PG&E to submit its first pre-approval plan by June 1, 2024 (implying applicability beginning with 2025 spending). PG&E pointed out this timing concern in its October 2023 comments on the proposed decision.
• PG&E argues it was impossible to comply with pre-approval requirements for expenditures already incurred or underway, making denial of cost recovery arbitrary, inconsistent with treatment of similar requirements imposed on SoCalGas, and an abuse of discretion.
• PG&E also raises an equal protection claim under both the California and U.S. Constitutions as an independent ground for reversal, arguing the Commission treated functionally indistinguishable utilities differently without justification.

PG&E requests that the CPUC grant rehearing, allow recovery of the disputed costs in a balancing account, or alternatively modify the underlying decision to clarify that the pre-approval framework applies prospectively starting in 2025 rather than retroactively to 2023–2024 spending.

Notably, PG&E invites the Commission to construe the rehearing application as a petition for modification of D.23-11-069, offering the Commission a procedural off-ramp to correct course without conceding legal error.

INSTANT ANALYSIS: This rehearing request tests whether the CPUC can enforce new pre-approval rules on spending that occurred before those rules could realistically be followed. If the CPUC holds the line, utilities face higher risk that late GRC directives can retroactively jeopardize recovery for RD&D and pilot programs. If the Commission relents, it preserves the norm that new oversight mechanisms apply prospectively, not mid-stream.

The petition-for-modification alternative makes the second outcome more likely by giving the Commission a face-saving path to resolution.

The context is: small dollars, real precedent. The outcome will indicate how aggressively the CPUC plans to control utility discretion over gas-system innovation spending during the transition period.

NATURAL GAS STORAGE

SoCalGas filed Advice Letter 6607-G (available here) to revise its gas storage tariffs by reducing the In-Kind Energy Charge applied to customer gas injections from 8.93% to 6.88%, effective April 1.

The filing updates Schedule Nos. G-BSS (Basic Storage Service), G-LTS (Long-Term Storage Service), and G-TBS (Transaction-Based Storage Service) in accordance with:

• A 2009 decision (D.09-11-006), which established that the injection fuel rate be recalculated annually using a three-year rolling average of actual fuel use; and
• A 2016 decision (D.16-06-039), which authorized SoCalGas to sell equivalent gas compressor fuel volumes to cover electricity costs for electric compressors at its storage fields.

The proposed decrease reflects updated operational data and cost adjustments, including electricity costs associated with electric compressors installed under the Aliso Canyon Turbine Replacement project, with projections based on 2023–2025 performance data and forward market prices.

INSTANT ANALYSIS: This filing lowers the storage injection fuel retention to 6.88%, slightly improving the economics of injecting gas into SoCalGas storage ahead of the new storage year. The change reflects updated fuel-use data and projected electricity costs for electric compressors, not a policy shift. Notably, the electric-equivalent fuel component now represents roughly 88% of the forward-looking fuel requirement in the calculation, meaning power prices are already playing a larger role in shaping gas storage charges than the underlying gas compression itself.