FRIDAY AGGREGATE: SONGS Cost Fight, IRP Flex Push, Mega-Load Interconnection Changes

Today's roundup covers ongoing disputes over the 2024 Nuclear Decommissioning Cost Triennial Proceeding for San Onofre, ex parte influences on a proposed decision in the IRP docket, and PG&E's handling of large load interconnections.

Also, on February 13 parties served intervenor testimony in PG&E's 2027 General Rate Case Phase 1. The volume is substantial and will shape the trajectory of the proceeding. CRI is available to produce a comprehensive synthesis for clients who require rapid situational awareness in this proceeding. (Contact if needed.)

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NUCLEAR DECOMMISSIONING

In the 2024 Nuclear Decommissioning Cost Triennial Proceeding for San Onofre (SONGS), the major parties’ reply briefs highlight ongoing disputes over cost assumptions, contingency levels, spent fuel timelines, and the handling of Department of Energy litigation proceeds.

• The Joint Utilities (SCE and SDG&E) defend their decommissioning cost estimates and core assumptions against intervenor critiques. They argue that assuming federal removal of spent nuclear fuel beginning around 2034 is reasonable given longstanding Commission practice and pervasive uncertainty about federal action.
  • The utilities oppose modeling multiple long-duration storage scenarios as speculative and instead support using DOE litigation recoveries as a funding buffer if removal is delayed. They also reject calls to include an alternative “Settlement Scenario” for dismantlement timing in future estimates, contending that only the Operational Scenario reflects the actual strategy being implemented.
  • On cost issues, the utilities defend contingency levels for contractor work and other forecast assumptions as grounded in risk analysis and expert studies.
  • Notably, the utilities' defense of contingency is specific: they argue the Decommissioning General Contractor contingency increase above the previously approved 10% level is justified by the costs of settling COVID-19 pandemic claims, not a blanket defense of all contingency assumptions.
• TURN’s reply brief presses the opposite direction, arguing the utilities’ forecasts overstate costs and contingencies. TURN urges the CPUC to:
  • Keep the contractor contingency at the previously approved level rather than increasing it;
  • Trim multiple SONGS Unit 1 cost forecasts to align with recent actual spending; and
  • Remove or reduce contingencies tied to staffing, leases, incentives, security overtime, inspection fees, and contracted services where historical data does not support higher projections.
• On funding policy, TURN contends trust balances appear sufficient for decades of storage costs and therefore DOE litigation proceeds should flow back to ratepayers rather than being retained in decommissioning trusts.
• Cal Advocates focuses on specific cost components it views as unsupported or premature. It:
  • Argues the utilities failed to justify certain cleanup costs tied to returning land parcels to the Navy;
  • Challenges proposed increases in IT-related decommissioning expenses;
  • Questions a higher contingency assumption for Palo Verde decommissioning estimates; and
  • Recommends splitting DOE litigation proceeds between customer refunds and trust funding rather than diverting all proceeds to the trusts.
• The Alliance for Nuclear Responsibility emphasizes long-term uncertainty and intergenerational equity risks. It argues the utilities rely on overly optimistic assumptions about the timing of federal removal of spent nuclear fuel and should analyze longer onsite storage scenarios and stress-test funding adequacy accordingly.
• The Alliance also supports continued evaluation of an alternative dismantlement scenario in case coastal or regulatory decisions require earlier structural removal, and it cautions against additional contributions to decommissioning trusts absent clearer need.
• On trust funding, the Alliance's position is the inverse of what it might appear to be: the Alliance is not advocating for additional contributions to the decommissioning trusts, but rather cautioning against diverting DOE litigation proceeds into those trusts without first conducting proper quantitative analysis of whether the funding is actually needed.

INSTANT ANALYSIS: The main conflict here is who carries long-term risk if spent fuel stays onsite longer than assumed. Utilities want to preserve DOE litigation proceeds inside decommissioning trusts as a hedge; consumer groups want refunds to ratepayers now. That decision will determine whether future funding pressure lands on utility balance sheets or customers. The battle over fuel-removal timelines is equally significant. Longer storage assumptions would inflate projected costs and could reopen collection debates; maintaining current assumptions keeps liabilities contained for now.

A second, underappreciated axis of conflict is the California Coastal Commission's potential authority over the timing of subsurface structure removal at the SONGS site. The Alliance for Nuclear Responsibility argues the utilities are making an unsupported assumption that the CCC will indefinitely defer requiring structural removal until all spent fuel has left the site. If the CCC takes a different view when SCE files its required permit amendment by June 2028, it could force earlier and more costly dismantlement activity (independent of the spent fuel timeline entirely). The utilities and the Alliance genuinely disagree about this risk, and it represents a regulatory wildcard that current cost estimates may not adequately capture.

This proceeding is a precedent-setting test of how the CPUC will ultimately allocate multi-decade infrastructure risk, with implications beyond nuclear.

INTEGRATED RESOURCE PLANNING

Ex parte meetings continue to mount in the CPUC's Integrated Resource Planning docket, as parties address the pending IRP proposed decision, which is scheduled for consideration on February 26.

February 26, 2026 CPUC Voting Meeting Preview

IRP 6,000 MW Order; Closure on Winter Gas Price Investigation

CALIFORNIA REGULATORY INTELLIGENCEMC

In meetings with CPUC personnel, parties advanced competing visions of how the 2029–2032 procurement framework should be structured (see CRI's discussion of CalCCA and Cal Advocates' recent ex parte meetings here.)

• California Resources Corporation (CRC) urged commissioners’ offices to modify the PD to explicitly allow natural-gas generation paired with carbon capture and storage (including retrofits of existing plants and CCS-enabled fuel-cell configurations) to qualify as eligible interim resources and planning assumptions.
• CRC also separately asked the Commission to include NGCCS as a resource type in the 2026–2027 Transmission Planning Process Base Case modeling, a distinct request from the 2029–2032 interim procurement window.
• CRC argued that a “least-regrets” approach would recognize NGCCS as a clean, firm, dispatchable option that could deliver emissions reductions, reliability, and cost control sooner than a renewables-plus-storage pathway alone. CRC cited CARB’s Scoping Plan, ongoing federal permitting, and the prospect of near-term CO₂ injection projects in California as evidence that the technology is ready for deployment.
• In a separate ex parte meeting, the three large electric utilities (PG&E, SCE, and SDG&E) jointly urged revisions that would moderate the PD's procurement mandate rather than expand eligible resource types. The utilities asked the Commission to:
  • Retain flexible compliance mechanisms;
  • Consider reducing or delaying the 2032 procurement requirement based on updated load forecasts from the California Energy Commission’s 2025 Integrated Energy Policy Report;
  • Clarify effective load carrying capability assumptions;
  • Allow any Diablo Canyon extension to count toward requirements; and
  • Ensure that a proposed storage cap would not restrict hybrid resources.
• The utilities' message focused on feasibility, cost containment, and implementation risk, warning that rigid targets or penalty exposure amid uncertain forecasts and project delays could drive unnecessary customer costs.

INSTANT ANALYSIS: Stakeholders across the IRP docket are converging on one message: the proposed 2029–2032 procurement order is too rigid given load uncertainty, project risk, and resource constraints.

The Joint IOUs, CalCCA, and Cal Advocates have all pressed for greater flexibility (reassessing the 2032 target with updated forecasts, easing the storage cap’s application, and preserving compliance mechanisms for delayed projects) while resource developers simultaneously push to expand eligible technologies such as gas with carbon capture.

The alignment across utilities, CCAs, and consumer advocates increases the odds of late revisions before the February 26 vote. Any changes to procurement volumes, storage limits, or compliance rules would ripple into RA strategy, contract timing, and gas-fleet planning, extending uncertainty for load-serving entities that expected the trajectory to stabilize.

LARGE LOAD INTERCONNECTIONS

PG&E submitted Advice Letter 5180-G/7843-E, requesting CPUC approval to add new exhibits to its existing Agreement to Perform Tariff Schedule Related Work that would govern preliminary services for large electric interconnection projects.

• The proposed exhibits establish detailed terms under which PG&E can perform customer-funded design and engineering work, and in some cases procure long-lead equipment, before a formal interconnection agreement is executed. PG&E states the changes respond to a surge in requests from large-load customers whose projects require complex planning and may necessitate ordering equipment such as transformers years in advance to meet proposed operation dates.
• Under the proposal, customers requesting these preliminary services must pay PG&E's actual costs through deposits that cover engineering, design, and procurement activities, with remaining funds either credited toward construction if the project proceeds or returned without interest if it does not.
• The exhibits also set contractual conditions addressing cost responsibility, scheduling contingencies, liability limits, and procurement risks, including provisions that deposits used to secure long-lead materials may be non-refundable if a project is cancelled.

PG&E argues the framework provides commercial clarity for developers while protecting existing ratepayers by ensuring that large projects—not the general customer base—bear the financial risks of early engineering work and equipment purchases undertaken prior to finalized interconnection agreements.

INSTANT ANALYSIS: PG&E is creating a pathway to start design, engineering, and long-lead equipment procurement for large-load interconnections before a final agreement is signed, with customers funding the work through deposits. The move aims to accelerate timelines for mega-projects while shifting cancellation and cost risk away from ratepayers.

The filing refers to these customers generically as "Large Load Customers" without specifying the underlying demand drivers, though the framework is consistent with pressures emerging from data centers and other high-demand facilities (an inference based on market context rather than anything PG&E states in the filing itself).

ELECTRIC VEHICLE INFRASTRUCTURE

SDG&E submitted Advice Letter 4805-E (available here) requesting CPUC approval to modify the performance metrics used to judge “per se reasonableness” for its Power Your Drive for Fleets medium- and heavy-duty electric vehicle infrastructure program.

• SDG&E argues that real-world conditions have slowed deployment and made the original targets unrealistic. These conditions include limited availability of heavy-duty EVs, high construction costs, customer unfamiliarity with electrification, supply-chain delays, and policy constraints including a statewide moratorium on new transportation electrification applications after 2026.
• As of the end of 2025, the program had built 42 operational sites supporting about 1,760 vehicles and spent $43.1 million of its $154.8 million authorized budget, while encountering cost variability driven by grid upgrades, trenching, site design, and inflation. Notably, only 622 vehicles are fully invoiced across 28 completed sites.
• To reflect these constraints, SDG&E seeks to reduce the required deployment benchmarks from 300 make-ready installations to 75 completed sites and from 3,000 electrified vehicles to 1,900 vehicles, while maintaining other requirements such as spending in disadvantaged communities.

SDG&E says these revisions would align performance evaluation with actual market conditions and the shortened program timeline, noting that without adjustments it cannot meet the original targets before the mandated sunset date. The filing also emphasizes ongoing cost-control practices, screening of projects for cost effectiveness, and the expectation that unspent funds will be returned to ratepayers.

INSTANT ANALYSIS: SDG&E is resetting expectations for utility-led fleet electrification. By reducing deployment targets, it acknowledges that MDHD EV adoption is constrained by vehicle supply, customer readiness, construction costs, and the CPUC’s 2026 program sunset, not utility funding alone. For stakeholders, the message is that authorized budgets will not translate into full buildout under current conditions.

The filing follows a path already walked by SCE and PG&E, who received similar metric relief via Resolution E-5247 in 2023, and is likely to further reinforce the precedent for utilities seeking relief as the CPUC shapes its next phase of transportation electrification policy.

UTILITY FINANCES

PG&E filed notice of an ex parte communication in its application for a limited capital structure adjustment.

On February 13, PG&E met with CPUC President Alice Reynolds’ energy advisor and a utility costs and compliance supervisor. In the meeting, PG&E presented its request as a narrow, temporary measure intended to preserve access to capital and support future financing without increasing customer rates or altering its authorized revenue requirement.

PG&E argued that denying the request could raise financing costs by at least $60 million annually, potentially affecting customers. Conversely, approval would address timing issues between current accounting charges and expected future cost recoveries or external funding, including wildfire claims and a Department of Water Resources forgivable loan.

PG&E emphasized that similar relief has been granted previously and framed the adjustment as critical to funding incremental capital projects while maintaining financial stability.

INSTANT ANALYSIS: PG&E is prioritizing balance-sheet flexibility ahead of looming capital demands tied to wildfire liabilities and infrastructure spending. By framing its request as rate-neutral and temporary, PG&E is attempting to lower the political temperature while securing financing headroom the Commission has historically allowed in constrained circumstances. The real stakes are forward-looking: approval would ease near-term capital access during a period of heavy investment requirements, while denial would raise financing costs that could surface in later rate cases.

Ultimately this proceeding is a significant test of how much financial accommodation the CPUC is willing to extend to investor-owned utilities facing overlapping wildfire, grid hardening, and affordability pressures.

PURPA

SDG&E filed Advice Letter 4806-E (available here), which proposes revisions to its PURPA tariff to comply with CPUC Resolution E-5425, which clarified how utilities must compensate certain customer-generators who lose access to Net Energy Metering or Net Billing tariffs due to contractor violations of prevailing-wage requirements. (See CRI's coverage of Resolution E-5425 here.)

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

The filing responds to an earlier rejection by Energy Division, which found SDG&E's prior proposal inconsistent with CPUC directives because the 20 MW cap SDG&E had proposed contradicted a 2023 decision (D.23-11-068), which required the tariff apply to all facilities eligible under pertinent provisions of the Public Utilities Code without a size limit. Resolution E-5425 subsequently authorized the 20 MW cap, resolving the conflict and enabling this compliance filing.

Under the revised tariff, affected renewable generators would be compensated at avoided-cost rates based on CAISO day-ahead prices, and eligibility would be limited to facilities up to 20 MW, consistent with the resolution's findings.

The tariff:

• Applies automatically to customers whose projects are disqualified from NEM/NBT programs due to willful wage violations;
• Provides either 30-day notice (for single generating accounts without aggregated accounts) or 60-day notice (for accounts with benefitting or aggregated accounts) before transition; and
• Allows customers to return to their prior tariff if the violation finding is overturned.

INSTANT ANALYSIS: This is a narrow but consequential compliance filing with real project-finance implications. SDG&E is implementing Resolution E-5425 by establishing a fallback PURPA pathway for projects disqualified from NEM/NBT due to prevailing-wage violations, capping eligibility at 20 MW and tying export compensation to avoided-cost pricing. The result converts labor-compliance risk into tariff risk: projects that fail wage rules lose retail-rate economics and fall to wholesale-style compensation.