MONDAY AGGREGATE: Stipulation Charts a Course for $1.951 Billion Woolsey Fire Securitization
Today's top item is a joint stipulation between SCE and Cal Advocates in A.26-01-007, where Edison seeks authority to issue $1.951 billion in recovery bonds to finance costs related to the 2018 Woolsey Fire. The stipulation resolves all contested issues in the proceeding.
On the Sempra front, SDG&E filed an application for authority to issue up to $2.583 billion in new long-term debt and $1.348 billion in additional roll-over debt authority for 2027–2029.
Additional items of note include:
- A ruling in the SGIP docket establishing new cost-verification requirements for SGIP Residential Solar and Storage Equity projects;
- A California Resources Production Corporation application for rehearing of a CPUC decision last month (D.26-02-003); and
- A SoCalGas request for expedited approval of two interstate natural gas capacity contract renewals with El Paso Natural Gas Company.
WOOLSEY FIRE
SCE and Cal Advocates filed a joint stipulation resolving all contested issues in A.26-01-007, which seeks authority for SCE to issue $1.951 billion in recovery bonds to finance costs related to the 2018 Woolsey Fire. (See CRI's coverage here.)
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- The parties agree that the wildfire costs recorded in SCE's Wildfire Expense Memorandum Account were previously found just and reasonable in a 2025 decision (D.25-12-023), allowing them to be financed through securitization. Structure and tenor were the only issues in material dispute. The stipulation caps the transaction at a 22-year weighted average life and 33-year maximum maturity, and concludes that issuing the bonds is just, reasonable, and consistent with the public interest.
- The bonds would be issued through a bankruptcy-remote special purpose entity and repaid through a nonbypassable "Fixed Recovery Charge" on SCE electric customers, with CARE and FERA customers exempt. Because CARE and FERA customers are exempt from the Fixed Recovery Charge, securitization eliminates their bill impact entirely; they would otherwise face a $2.78 monthly increase under a five-year amortization.
- The parties argue that securitization produces an estimated $827 million in present-value savings compared with traditional utility financing at SCE's authorized 7.59% rate of return, and approximately $304 million compared with five-year amortization using long-term debt. The stipulated structure would produce an estimated $1.19 monthly increase for non-CARE residential customers compared with $4.27 under five-year amortization.
The parties request that the Commission expedite issuance of a financing order.
INSTANT ANALYSIS: The joint stipulation clears the path for approval of SCE's $1.951 billion Woolsey Fire securitization. With SCE and Cal Advocates aligned, no contested issues remain, and the CPUC can move directly to a financing order.
Structure and tenor were the only points in material dispute (Cal Advocates protested the application on these grounds) and the parties agreed to cap the bonds at a 22-year weighted average life and 33-year maximum maturity. This compromise spreads wildfire cost recovery over decades while limiting the longest tail of ratepayer charges.
The moral of the story is that securitization is now a default recovery tool, converting liabilities into long-term recovery bonds backed by nonbypassable charges.
WILDFIRE MITIGATION
SDG&E filed a response opposing Protect Our Communities Foundation’s application for rehearing of D.26-01-021 in the utilities’ 2024 General Rate Case proceeding. (See CRI's coverage of that application here.)
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- SDG&E argues that Protect Our Communities Foundation failed to identify any legal error in the Commission’s decision approving recovery of certain Wildfire Mitigation Plan Memorandum Account costs associated with 2019–2022 spending.
- According to SDG&E, Protect Our Communities Foundation’s rehearing request largely repeats arguments the CPUC already considered and rejected, including claims that the decision improperly allowed recovery of post-2022 costs, considered securitization, or authorized a future proceeding for 2024–2025 costs. SDG&E contends these arguments reflect misunderstandings of how capital expenditures are recovered over time and of the statutory framework governing wildfire mitigation cost recovery.
- SDG&E's response also defends the CPUC’s use of the “prudent manager” standard for evaluating whether previously incurred utility costs are just and reasonable. SDG&E maintains that this standard reflects long-standing ratemaking practice and statutory review requirements, and that Protect Our Communities Foundation’s challenge merely attempts to relitigate policy disagreements rather than demonstrate legal error.
Last, SDG&E argues that the CPUC acted within its discretion in allowing additional evidentiary development for certain Drone Inspection and Repair program costs rather than immediately disallowing them, and that Protect Our Communities Foundation mischaracterizes both the decision and the governing statutes.
INSTANT ANALYSIS: SDG&E frames the dispute as a misunderstanding of ratemaking mechanics, particularly the approval of 2019–2022 wildfire mitigation spending versus the later recovery of associated capital costs through depreciation and return. One notable procedural wrinkle is SDG&E’s suggestion that one ordering paragraph in D.26-01-021 may conflict with the Public Utilities Code regarding recovery pathways for 2024–2025 wildfire mitigation costs.
UTILITY FINANCES
SDG&E filed an application seeking CPUC authority to issue up to $2.583 billion in new long-term debt and $1.348 billion in additional roll-over debt authority for 2027–2029. The roll-over amount covers $1.35 billion in planned re-financings of Series QQQ, DDD, and AAA maturities in 2026 and 2028, plus $500 million in pre-positioned authority to act on opportunistic re-financing that could reduce embedded debt costs.
The application reflects capital spending driven by wildfire mitigation, grid hardening, electric-vehicle infrastructure, energy storage, gas system integrity, and risk mitigation strategies from SDG&E's 2025 RAMP filing (A.25-05-013). SDG&E has already consumed $2.331 billion of the $4.1 billion authorized under a 2022 decision (D.22-12-011) and expects to exhaust remaining authority by year-end 2026.
SDG&E seeks flexibility across a full menu of debt instruments:
- First-mortgage bonds;
- Fall-away bonds;
- Debentures;
- Foreign-market securities;
- Direct long-term loans;
- Variable-rate debt;
- Tax-exempt financings; and
- Accounts-receivable-backed obligations, along with hedging and derivative tools including interest-rate swaps, caps, collars, and currency swaps.
INSTANT ANALYSIS: The combined $3.93 billion request represents roughly 19% of SDG&E's $21 billion total regulatory capitalization and confirms the utility's capital cycle remains heavily debt-dependent through decade's end. The financing tracks spending approved in the Test-Year 2024 General Rate Case (D.24-12-074) and the 2025 RAMP proceeding, a financial echo of the CPUC's own capital approvals. SDG&E's current structure (47.2% long-term debt vs. a 45.25% authorized target) is already running above the CPUC's blueprint. Each successive debt application of this scale makes it harder to stay within those bounds without Sempra putting more equity in to keep pace.
SELF-GENERATION INCENTIVE PROGRAM
Commissioner Karen Douglas issued a ruling establishing new cost-verification requirements for SGIP Residential Solar and Storage Equity projects whose reported Total Eligible Project Cost exceeds specified thresholds relative to the maximum incentive for the system size.
The Residential Solar and Storage Equity program launched in June 2025 with $252 million in incentives for low-income solar and storage installations. It is 99% reserved with over 3,200 projects waitlisted. However, an analysis by Energy Division found reported costs significantly above industry averages and historic SGIP benchmarks, prompting stronger verification before incentive payments are issued.
- All Residential Solar and Storage Equity projects with Total Eligible Project Cost above 90% of the maximum incentive must now submit equipment and labor documentation at the Incentive Claim Form stage. Projects above 100% must additionally provide invoices supporting each cost category and a supplemental verification form signed by the developer or system owner and delivered to the host customer.
- Developers with multiple projects may establish a baseline Total Eligible Project Cost using program-wide documentation, but must provide project-specific justification for any project exceeding that baseline. Any Total Eligible Project Cost that cannot be verified must be reduced, and the Program Administrator must warn the developer to reduce Total Eligible Project Cost across all other SGIP applications.
Program Administrators will review projects in three prioritized groups.
- Group A: Projects below 100% of the maximum incentive, plus projects above 100% that applied for interconnection before February 20, 2026.
- Group B: Projects above 100% with customer out-of-pocket costs under $3,000 and multifamily projects not in Group A.
- Group C: All remaining projects, subject to random audit sampling. Program Administrators may withhold 30% or more of the incentive for any project pegged for an audit. Handbook updates are due within five days.
Comments are due March 18 as part of responses to the assigned commissioner's ruling.
INSTANT ANALYSIS: The CPUC is intensifying cost oversight in the Residential Solar and Storage Equity program after finding project pricing well above market benchmarks. Commissioner Douglas's ruling creates payment friction for higher-cost developers by requiring documentation before incentives are released, and gives Program Administrators authority to withhold at least 30% of incentives and force portfolio-wide Total Eligible Project Cost reductions when costs can't be verified. The CPUC's concern is that inflated pricing consumes limited equity-program funds meant to maximize low-income installations. Similar scrutiny could emerge in other equity or storage programs if pricing anomalies surface.
NATURAL GAS INFRASTRUCTURE/PIPELINE REGULATION
California Resources Production Corporation filed an application for rehearing of a decision last month (D.26-02-003), which dismissed its application for designation as a public-utility gas corporation and for a Certificate of Public Convenience and Necessity to operate the Union Island natural-gas pipeline.
(See CRI's coverage here.)
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The Commission dismissed the application without prejudice, finding the matter unripe because parallel litigation and local proceedings concerning franchise rights and pipeline ownership remain unresolved. D.26-02-003 replaced an earlier proposed decision that had denied the application on the merits.
In its request for rehearing, CRPC argues the decision:
- Misinterprets the Public Utilities Code by requiring present ownership of the entire pipeline before granting public-utility status, an interpretation the Commission expressly rejected in a 2011 decision (D.11-12-056), where it called that reading an "absurd result";
- Departs from longstanding CPUC precedent allowing CPCNs based on prospective operation of utility infrastructure, and misrepresents the record in the WesPac and Wickland decisions it cites to distinguish (including incorrectly characterizing WesPac's pipeline as "unopposed" when the City of Gardena actively litigated against it);
- Ignores that a CPCN would confer eminent domain authority enabling CRPC to perfect ownership of the pipeline segments at issue, making the ripeness rationale circular, a path the CPUC has endorsed in prior CPCN grants to Independent Storage Providers (Wild Goose, Gill Ranch, Lodi) and that California courts upheld in Shell v. City of Compton and Unocal v. Conway; and
- Improperly introduced a ripeness theory outside the scoped issues of the proceeding.
CRPC also contends the CPUC violated its own scoping memo, procedural rules, and due-process requirements by resolving the application on grounds expressly reserved for a later evidentiary phase and adopting a revised decision shortly before the vote without giving parties an opportunity to address the new rationale.
INSTANT ANALYSIS: The rehearing request challenges the CPUC’s shift from denying CRPC’s CPCN application on the merits to dismissing it as “unripe.” CRPC argues the Commission misapplied the law and departed from precedent allowing public-utility status based on prospective operation of infrastructure.
The eminent domain argument is the strategic core: CRPC contends a CPCN would give it the condemnation authority needed to resolve the very ownership uncertainties the Commission cited as grounds for dismissal, and that the Commission has granted public-utility status for exactly this purpose in prior proceedings.
The case tests whether the CPUC can determine pipeline utility status before ownership and franchise disputes are resolved. If the ripeness approach stands, developers may need clearer asset control before seeking CPCN authority. The dispute also reflects conflict between statewide infrastructure oversight and local franchise control, with potential implications for future pipeline and energy-facility proceedings.
NATURAL GAS CAPACITY
SoCalGas filed Advice Letter 6612-G (available here) requesting expedited approval of two interstate natural gas capacity contract renewals with El Paso Natural Gas Company.
The filing is made under the interstate capacity acquisition framework authorized in a 2004 CPUC decision (D.04-09-022), which allows expedited review when stakeholders such as Cal Advocates support the transaction. Cal Advocates participated in the relevant Capacity Consulting Group discussions in February 2025 and indicated support for the renewals, while TURN did not participate.
The specific commercial terms of the contracts are confidential and included in a protected attachment because they contain market-sensitive information related to SoCalGas’s gas procurement and capacity management strategies. SoCalGas states that the contracts will not modify tariffs, withdraw service, or impose new service conditions.
Protests are due March 23.
INSTANT ANALYSIS: SoCalGas continues to maintain contracted interstate transport capacity into the Southern California gas system rather than relying purely on spot transportation or market flexibility. That reinforces the utility’s long-standing reliability strategy: secure firm upstream capacity to manage winter demand, storage injections, and operational volatility across the constrained SoCal basin. The key implication is continuity, with no immediate effect on gas procurement costs, scheduling, or balancing arrangements for core or noncore customers.