FRIDAY AGGREGATE: Update on $190 Million THUMS Oil Islands Cable Replacement; Slow SCE Movement in Microgrid Incentive Program

Today's roundup touches on SCE's role in the Microgrid Incentive Program, an agreement serving the THUMS artificial oil islands, the Low Carbon Fuel Standard, and PG&E's Risk Assessment and Mitigation Phase ("RAMP") submission.

MICROGRIDS

SCE filed Advice Letter 5737-E (available here), which contains its Q4 2025 quarterly status report for the Microgrid Incentive Program, as required by a 2023 decision (D.23-04-034).

The report shows that program activity remains limited and largely administrative. No new outreach occurred in Q4 due to the closure of initial consultation windows and uncertainty around future funding rounds.

During Round 2, SCE completed four technical consultations and received five applications before the December 31, 2025 deadline, bringing the cumulative total to six applications across Rounds 1 and 2.

• Only one project has been awarded to date (from Round 1), and it has not yet entered interconnection or special facilities studies; execution of its performance agreement is expected in early 2026.
• No microgrids are operational, and no incentive, interconnection, or special facilities payments have been made beyond a single $25,000 application development grant.
• Financially, the program remains mostly unspent: of the $91.3 million authorized budget, about $559,000 (0.6%) has been paid, almost entirely for administration, while $17.8 million (about 20% of the total budget) is committed but not yet disbursed.

SCE reports no unintended outcomes, no active operating agreements, and no accruals beyond administrative costs, with meaningful expenditures deferred until projects advance out of early contracting and study phases.

INSTANT ANALYSIS: SCE’s filing demonstrates how slowly the program is translating authorization into steel in the ground. Nearly three years after implementation rules were adopted, only one project has been awarded, no interconnection or special facilities studies have begun, and no microgrids are operating. Spending remains overwhelmingly administrative, with less than 1% of the $91.3 million authorized budget actually paid out, even as roughly one-fifth of total funds are now nominally committed.

The bottleneck is no longer policy design but execution: applications have closed, Round 2 applications will undergo eligibility checks and evaluation starting in Q1 2026, and all material costs are pushed into future years. For stakeholders tracking resiliency delivery rather than paper progress, the report highlights a widening gap between program intent and on-the-ground outcomes, with meaningful deployment unlikely until contracting and study work finally clears in 2026

ARTIFICIAL OIL ISLANDS/ADDED FACILITIES

In a joint mediation statement SCE, THUMS Long Beach Company, and the City of Long Beach report continued progress toward a negotiated sale of the THUMS “Added Facilities” to THUMS in A.24-12-001.

Background

• In 2024, SCE filed an application (A.24-12-001) to obtain CPUC confirmation that aging submarine cables and associated “Added Facilities” serving the THUMS artificial oil islands must be replaced under a new, customer-financed Added Facilities Agreement, with THUMS or any successor customer providing all upfront capital and assuming all removal-cost risk.
• SCE argued that Rule 2 and the 1965 Added Facilities Agreement require the customer (not general ratepayers) to fund these special, oil-field-specific facilities. Rule 2 only added customer-financed Added Facilities Agreements as an option in 1983, and replacement coverage only became available for SCE-financed Added Facilities Agreements in 1996 (not retroactively). The 1965 THUMS Added Facilities Agreements predates both provisions and contains no replacement coverage.
• With replacement estimated at $190 million + and likely to take a decade amid declining oil production, Senate Bill 1137 buffer-zone restrictions, and State/City plans to retire offshore drilling, SCE warned that utility financing could strand nine-figure assets and violate longstanding policy that added-facility costs cannot shift to the broader rate base.
• SCE proposed that any new agreement follow Commission-approved Form 16-309, the standard template for customer-financed Added Facilities Agreements that includes removal cost provisions.
• Last fall – in response to an ALJ request – the City of Long Beach and THUMS submitted a joint filing clarifying that the Long Beach Unit (the eastern Wilmington Oil Field, including the four THUMS islands, is owned by the State, held in trust by the City, and operated with THUMS as the field-contractor’s agent). They reported that the State Lands Commission provides oversight but has declined to participate directly in this proceeding, instead deferring to the City in its trustee role.

Mediation Statement

The new statement from SCE, THUMS Long Beach Company, and the City of Long Beach describes a full-day mediation in July 2025 followed by ongoing confidential negotiations, including site visits to the Pico Substation, exchanges of draft sale terms, and continued discussions through mid-January 2026, with plans to update the Commission again in late February.

• The mediating parties state they were prepared to discuss the confidential negotiations at a status conference (held yesterday), though they did not anticipate being able to provide additional detail beyond what appears in the filing.
• Cal Advocates is not joining this portion of the statement and instead submits a separate position arguing that, as a matter of law, SCE's request to recover replacement facility costs from ratepayers must be dismissed with prejudice.
• Cal Advocates requested coordination on January 14, proposing a schedule for joint drafting, but the mediating parties did not provide a draft statement until January 21 and never contacted Cal Advocates to discuss the mediation itself.
• Cal Advocates cites D.70659, which approved the original facilities arrangement only on the condition that ratepayers bear none of the costs, and contends that SCE’s own application acknowledges this prohibition.
• Cal Advocates further argues that allowing mediation to proceed without resolving the ratepayer issue risks obscuring future cost exposure, undermines intervenor rights, and delays efficient resolution. Consequently, Cal Advocates urges the CPUC to dispose of the ratepayer recovery request now rather than await the outcome of private settlement talks.

THUMS and the City of Long Beach have also filed their own motion to dismiss SCE's application on separate grounds (ripeness and jurisdictional deficiencies), distinct from Cal Advocates' ratepayer protection argument.

INSTANT ANALYSIS: This mediation update shows the case moving on two tracks:

• Progress toward a negotiated sale of the THUMS facilities; and
• An unresolved dispute over whether ratepayers can ever be exposed to replacement costs.

The latter remains the controlling issue. Cal Advocates’ position narrows the CPUC’s options. Decision 70659 approved these oil-specific added facilities only on the condition that ratepayers bear none of the costs, a premise SCE itself acknowledges. A settlement cannot bypass that constraint if it relies on utility financing or abandonment protection.

The case has implications for how the CPUC will treat aging, single-customer oil infrastructure in a phase-down environment. How the CPUC resolves the ratepayer question here may carry ripple effects for other legacy Added Facilities Agreements facing end-of-life replacement decisions.

LOW CARBON FUEL STANDARD

SDG&E filed coordinated advice letters (available here) in which it seeks approval of updated Low Carbon Fuel Standard (LCFS) holdback revenue implementation plans and corresponding exemptions from Public Utilities Code Section 851, as required by a 2020 CPUC decision (D.20-12-027).

The filings outline how SDG&E proposes to deploy its share of LCFS residential “holdback” credits (after the required 25% contribution to the statewide California Clean Fuel Reward) across a set of transportation electrification programs aimed at lowering adoption barriers.

Advice Letter 4794-E

• This filing focuses on the residential side of the portfolio. SDG&E proposes a new Residential Charging Rebate Program that would provide one-time rebates for the purchase and installation of Level 2 electric-vehicle chargers, with additional support for panel upgrades or panel-upgrade avoidance technologies. The filing also seeks approval to extend SDG&E’s existing Pre-Owned Electric Vehicle rebate program, which launched in 2024, through 2027.
• SDG&E frames these programs as addressing persistent cost and infrastructure barriers to EV adoption, particularly for income-qualified and underserved customers, and emphasizes that LCFS proceeds allow these benefits to be delivered without relying on ratepayer funding.
• SDG&E proposes to track revenues and expenditures through its existing LCFS balancing account and requests an effective date of March 1.

Advice Letter 4795-E

• This filing addresses a complementary but distinct use of LCFS holdback revenues: the Electric Vehicle High Power (EV-HP) Rate Incentive Program. Under this proposal, SDG&E would offer annual on-bill credits to customers taking service on the EV-HP rate to encourage off-peak and super-off-peak charging behavior. Customers would receive quarterly notifications showing their progress toward maximizing the annual credit.
• Incentives would be tiered by customer load size, subject to quarterly caps, and include enhanced benefits for customers in disadvantaged communities. SDG&E positions the program as both bill relief and a load-management tool that aligns EV charging with grid conditions, thereby advancing electrification while mitigating peak impacts.

INSTANT ANALYSIS: These paired advice letters show SDG&E drawing a clearer connection between LCFS revenues and grid outcomes. Instead of using LCFS holdback as a generic EV subsidy, SDG&E splits it between upfront help for residential charging constraints and ongoing bill credits that reward off-peak charging behavior. One lowers the entry cost; the other shapes how new load behaves once it arrives. If the filings are approved, the Commission would be reinforcing the idea that LCFS revenues are meant to influence load behavior and system outcomes, not just increase EV adoption totals.

RISK ASSESSMENT & MITIGATION PHASE

The CPUC issued a proposed decision closing PG&E's 2024 Risk Assessment and Mitigation Phase (RAMP) proceeding, which serves as the front-end risk analysis for PG&E’s 2027 Test Year General Rate Case.

The PD finds that PG&E’s RAMP filing, which uses a new cost-benefit framework to monetize safety and reliability risks, complies with Commission requirements despite multiple identified deficiencies.

While the CPUC's Safety Policy Division identified multiple methodological concerns (particularly around risk monetization, reliability valuation, alternative mitigation comparisons, and transparency) the PD determines none rose to a level warranting rejection.

An April 2025 ruling required PG&E to address four specific deficiencies, including providing parallel risk-neutral analyses and disaggregated reliability cost calculations, which PG&E subsequently did using the newly-released ICE 2.0 calculator rather than the ICE 1.0 version used in its original RAMP filing, with remaining disputes explicitly folded into the GRC record. The PD declines to resolve broader framework disputes here, deferring them to the ongoing GRC or future rulemakings.

Comments are due February 19. The earliest the Commission will consider this item is March 19.

INSTANT ANALYSIS: This PD closes PG&E’s 2024 RAMP on a narrow finding of procedural sufficiency, while leaving substantive disputes to be examined in the 2027 GRC. The PD accepts that PG&E satisfied prior RAMP directives, including follow-on responses ordered in April 2025, but makes clear that unresolved questions about risk modeling, reliability valuation, mitigation alternatives, and rate impacts remain live issues. By channeling those disputes into the GRC, the PD ensures they will be tested in the context where capital spending, cost allocation, and customer rates are actually determined.

The outcome should not be read as validation of PG&E’s preferred risk framework or mitigation portfolio. Expect scrutiny in the GRC to center on cost-benefit credibility, treatment of legacy controls with low cost-benefit ratios, justification of proposed mitigations versus realistic alternatives, and whether PG&E's mitigation strategy can be justified under escalating affordability concerns.