MONDAY AGGREGATE: Resource Adequacy; Provider of Last Resort; Wildfire Cost Recovery

Today's roundup covers:

• The compression of Resource Adequacy reform into a seven-month Track 1 window;
• The formalization of high barriers to Provider of Last Resort competition; and
• The placement of $1.9 billion in PG&E wildfire cost recovery into full evidentiary review.

Other items include the Commission's modification of data-center interconnection economics to protect ratepayers, the rejection of PG&E's request for expedited short-term debt authority, and a denial of two years of PG&E gas Research, Development, and Demonstration spending.

RESOURCE ADEQUACY

President Alice Reynolds issued a scoping memo that establishes the framework for the CPUC’s next phase of Resource Adequacy reform, focusing on forward procurement obligations (beginning with the 2027 compliance year) and continued refinement of the Slice-of-Day RA program.

The ruling divides the proceeding into two tracks.

• Track 1, running through early July 2026, addresses time-sensitive issues for the 2027 RA year, including adoption of 2027–2029 Local Capacity Requirements and 2027 Flexible Capacity Requirements based on CAISO studies, along with such program refinements as accreditation methodologies for long-duration storage, solar and wind resources, development of a final Unforced Capacity framework, transactability issues under Slice of Day, residual unit commitment requirements, and proposals related to energy-only resources.
• Track 2 will address system, flexible, and local capacity requirements for later years (2028–2030), potential adjustments to the planning reserve margin informed by Loss of Load Expectation studies, and broader RA refinements, with coordination alongside Integrated Resource Planning where appropriate.

Track 1 party proposals are due January 23.

INSTANT ANALYSIS: This ruling formally launches the CPUC’s next major Resource Adequacy rulemaking for the 2027–2029 timeframe and sets an aggressive Track 1 schedule aimed at resolving time-sensitive capacity requirements by early July 2026. The Commission is clearly prioritizing near-term reliability mechanics (local capacity, flexible capacity, Slice-of-Day refinements, and accreditation methodologies) over broader reforms, which suggest there is a limited appetite for reopening foundational RA design questions this cycle.

For load-serving entities, developers, and traders, the key takeaway is compression risk: multiple consequential RA determinations are being funneled into Track 1, with little margin for delay. Issues that miss this window may slip into later tracks, potentially creating misalignment between procurement obligations and evolving market realities.

PROVIDER of LAST RESORT

Commissioner Darcie Houck issued a proposed decision establishing a a procedural framework for how non-investor-owned entities may seek designation as a Provider of Last Resort under Senate Bill 520, without pre-judging eligibility criteria in the absence of a concrete applicant. (Providers of Last Resort are the load-serving entity designated to supply electricity to customers when their chosen provider fails or exits the market).

The PD concludes that, because no non-IOU entity has expressed intent to assume full POLR responsibility for all customer classes in a geographic area, it would be inefficient and speculative for the Commission to resolve detailed substantive issues in advance.

Instead, the PD adopts a streamlined, application-driven approach under which any prospective non-IOU Provider of Last Resort must submit a comprehensive application demonstrating compliance with Senate Bill 520’s minimum statutory requirements, including financial security, insurance, procurement compliance, technical and operational capacity, and protections against cost-shifting.

The PD:

• Clarifies that Provider of Last Resort obligations may not be divided by customer class;
• Affirms that IOUs cannot veto a non-IOU Provider of Last Resort application but must participate in a joint filing process where feasible; and
• Leaves questions regarding the scope of Commission regulatory authority to be resolved on a case-specific basis.

Comments are due January 2, 2026. The earliest the Commission will consider this item is January 15.

INSTANT ANALYSIS: A Provider of Last resort is the grid's safety net: boring by design, expensive to run, and essential when markets break. This PD does not open the door to near-term non-IOU POLR competition. The PD instead formalizes a high bar and a case-by-case, application-driven process that effectively preserves IOUs as default Providers of Last Resort unless (and until) a well-capitalized, full-service alternative steps forward. The PD explicitly rejects customer-class-only Provider of Last Resort models, requires universal service capability, and signals that cost recovery, regulatory scope, and affiliate issues will be litigated individually (which raises transaction costs for any prospective applicant). The PD functions as a gating framework rather than an invitation to entry, reinforcing system stability while deferring substantive policy choices until a real applicant emerges.

WILDFIRES

Commissioner Matthew Baker issued a scoping memo that sets the procedural framework for PG&E’s application to recover wildfire-related costs from the 2019 Kincade Fire and 2021 Dixie Fire under Assembly Bill 1054 (see our summary of the application here,).

PG&E seeks a review of costs recorded in its Wildfire Expense Memorandum Account and Catastrophic Event Memorandum Account, including claims paid by the Wildfire Fund, unreimbursed claims and litigation costs, and restoration-related capital and O&M expenses.

The proceeding is governed by Public Utilities Code Section 451.1, which requires the CPUC to determine whether PG&E’s conduct related to each fire was reasonable and whether the associated costs are just and reasonable.

Intervenor testimony is due April 13, with rebuttal testimony due May 29.

INSTANT ANALYSIS: With nearly $1.9 billion at stake ($1.59 billion in wildfire claims, litigation, and financing costs plus $314 million in restoration expenses), this scoping memo establishes a full prudence and reasonableness review of PG&E’s Kincade and Dixie Fire cost recovery under AB 1054. All major cost categories (claims, litigation, and restoration) are subject to evidentiary scrutiny, absent settlement. The ruling declines to bifurcate the proceeding for now, keeping both fires on a single procedural track and preserving intervenor leverage while maintaining a November 2026 decision deadline. The case will turn on whether PG&E can defend its pre-ignition conduct and cost management under the Section 451.1 standard, including potential shareholder exposure if any Wildfire Fund-paid claims are found unjustified.

DATA CENTERS

The CPUC issued a draft resolution approving (with modifications) PG&E’s request to energize a new 90-megawatt Microsoft data center in San Jose through transmission-level upgrades, including new 115-kilovolt facilities and dedicated lines.

The Draft Resolution finds the agreements necessary but determines that applying the standard Electric Rule 15 refund framework without adjustment would pose undue risk to ratepayers due to the project’s size, transmission-level interconnection, and uncertainty around long-term revenue realization.

To address this risk, the draft resolution modifies the Base Annual Revenue Calculation refund process by limiting annual refunds to 75% of PG&E’s actual net transmission revenues from Microsoft, with an adjustment for the Income Tax Component of Contribution, and extends the refund period from ten to fifteen years.

Microsoft must pay actual construction costs and receives no refunds for special facilities it requested. The draft resolution emphasizes that this is an exceptional, non-precedential determination and directs PG&E to file conforming agreements.

This item is tentatively scheduled for Commission consideration on January 15.

INSTANT ANALYSIS: This draft resolution approves PG&E’s Microsoft data center energization as an exceptional case but changes the refund mechanics to protect ratepayers. By limiting annual refunds to 75% of actual net transmission revenues (plus Income Tax Component of Contribution) and extending the refund window to 15 years, the draft resolution avoids allowing large, transmission-level loads to recover upfront costs faster than revenues are actually realized.

The key takeaway is that large data centers and other hyperscale loads should expect customized refund treatment and slower cost recovery when transmission upgrades are involved. This preserves project viability while making clear that distribution-level refund assumptions will not be applied wholesale where ratepayer exposure could arise, particularly ahead of a final Rule 30 framework.

UTILITY FINANCES

Commissioner Darcie Houck issued a scoping memo addressing PG&E’s application to increase its authorized short-term borrowing by $2.0 billion, from $8.5 billion to $10.5 billion.

In response to a protest filed by Cal Advocates, PG&E is directed to file a supplemental showing by January 5, detailing its intended uses of the additional authority, liquidity and tail-risk needs, interest rates, and whether further increases may be sought.

The ruling denies PG&E’s request for expedited treatment, finding no near-term urgency, and adopts a standard schedule with a potential evidentiary hearing and a proposed decision expected in spring 2026.

INSTANT ANALYSIS: This ruling presses PG&E to more clearly justify why additional short-term debt authority is needed now. By ordering a supplemental filing and rejecting an expedited schedule, the ruling frames this as a transparency and capital-discipline test rather than a routine financing approval, giving intervenors room to probe liquidity assumptions, use of proceeds, and whether existing credit capacity already addresses near-term risk.

RENEWABLE NATURAL GAS

PG&E, SoCalGas/SDG&E, and Southwest Gas filed a joint advice letter to document their 2025 research on the impacts of mercury on natural gas pipeline integrity.

• The filing explains that, due to historically limited and largely inapplicable research on mercury impacts outside of cryogenic liquefied natural gas operations, the utilities have continued to rely on an existing mercury trigger level of 0.08 mg/m³ while conducting additional study.
• Operational data from renewable natural gas interconnections across dairy, wastewater, food waste, and landfill sources show no mercury exceedances to date, including new landfill RNG injections that began in late 2025.
• The utilities also describe ongoing laboratory research led by Southwest Research Institute under a Gas Technology Institute project, including multi-month exposure tests of pipeline and end-use materials at elevated mercury concentrations.

Phase 2 testing is nearing completion, with final results expected in 2026. The utilities state they will review those results to determine whether sufficient evidence exists to propose updated mercury trigger or action limits for California’s natural gas distribution systems.

Protests are due January 2.

INSTANT ANALYSIS: This filing keeps the status quo in place. The utilities again document the absence of mercury exceedances across RNG interconnections and confirm that no changes to mercury trigger or action limits are proposed at this time. The substantive work is occurring off-docket in laboratory testing, with any potential regulatory follow-on pushed into 2026 after Phase 2 results are finalized.

NATURAL GAS RESEARCH

The CPUC issued Draft Resolution G-3618, which denies PG&E’s proposed Gas RD&D Investment Plans for 2024 and 2025 and rejects its request to recover $7.2 million in RD&D costs from 2023–2024.

Although funding levels were authorized in PG&E’s 2023 General Rate Case, the Commission finds the plans fail to:

• Demonstrate ratepayer benefits;
• Avoid duplication with other gas and hydrogen programs;
• Properly allocate administrative costs; and
• Meet reporting and consultation requirements.

Consequently, PG&E may not record RD&D expenses for these years. PG&E is directed to resubmit revised 2024 and 2025 plans within 60 days addressing the identified deficiencies.

The draft resolution also establishes more prescriptive planning, coordination, and reporting requirements for future Gas RD&D plans beginning in 2026, and requires unspent funds to be returned to ratepayers at the end of the current GRC cycle.

The earliest the CPUC will consider this item is January 15.

INSTANT ANALYSIS: The draft resolution makes clear that prior GRC authorization is not a green light to spend. For gas utilities, this sets a higher bar for RD&D filings and narrows the path for hydrogen-related work until the Commission provides clearer guidance on ratepayer funding.