January 15, 2026 CPUC VOTING MEETING RESULTS: SDG&E Wildfire Costs; POLR Framework; Data Center Transmission Upgrades

At its January 15, 2026 voting meeting, the CPUC adopted:

• An SDG&E General Rate Case decision that disallows $206.1 million in O&M costs and $242.5 million in capital expenditures, while approving $77.9 million in O&M and $945.5 million in capital as reasonable and necessary wildfire mitigation investments;
• A procedural framework for how non–investor-owned utilities may seek designation as a Provider of Last Resort under Senate Bill 520;
• An SCE ERRA Compliance decision authorizing recovery of $51.442 million in undercollected balances across five accounts, mainly driven by Emergency Load Reduction Program costs;
• PG&E’s request to facilitate transmission upgrades needed to energize a new 90-MW Microsoft data center in San Jose;
• Two Mid-Term Reliability actions affecting PG&E’s energy storage portfolio;
• A resolution that rejects $16.4 million in requested funding and disallowing $7.2 million in cost recovery for PG&E natural gas RD&D expenses incurred in 2023–2024; and
• A resolution approving requests of PG&E and SDG&E to establish PURPA-compliant export tariffs for customer-generation facilities that lose access to Net Energy Metering or Net Billing Tariff due to prevailing wage violations under the Public Utilities Code.

Additionally, the CPUC withdrew a proposed decision that denied a petition for modification filed by the Bioenergy Association of California to modify a 2020 CPUC decision (D.20-08-043), which had extended the Bioenergy Market Adjusting Tariff program through December 31, 2025.

And the Commission delayed action once again on a proposed decision that denies a request of California Resources Production Corporation for a Certificate of Public Convenience and Necessity to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation. This item is now scheduled for consideration on February 5.

Full meeting results are provided below.

WILDFIRE MITIGATION/SDG&E RATES

This decision addresses SDG&E's General Rate Case Track 2 request to recover wildfire mitigation costs recorded in its Electric and Gas Wildfire Mitigation Plan Memorandum Accounts (WMPMAs) for the 2019–2022 period, above amounts authorized in its Test Year 2019 GRC.

SDG&E sought recovery of roughly $284 million in operations and maintenance costs and $1.188 billion in capital expenditures incurred to comply with expanded wildfire mitigation requirements enacted through Senate Bill 901 and Assembly Bill 1054.

The decision finds that while many of these investments were required and prudent, a substantial portion of the recorded costs were not reasonable for ratepayer recovery under the CPUC’s standards, particularly where SDG&E failed to sufficiently demonstrate incrementality, cost-effectiveness, or proper allocation between capital and O&M.

• The decision disallows $206.1 million in O&M costs and $242.5 million in capital expenditures, while approving $77.9 million in O&M and $945.5 million in capital as reasonable and necessary wildfire mitigation investments. Major disallowances include costs for drone inspections, aviation firefighting, PSPS communication practices, data governance tools, and certain inspection and community outreach activities that were either already funded in prior GRC authorizations, insufficiently justified, or misclassified.
• The decision defers final authorization of some drone-related costs to Track 3 of the proceeding. After accounting for approved costs and prior interim rate relief, the decision authorizes a net revenue requirement of $416.6 million for 2019–2027 and allows SDG&E to amortize the remaining undercollection over three years, resulting in an average residential bill impact of about $5.09 per month for non-CARE customers.
• Appendix A provides a detailed cost reduction summary, showing how individual wildfire mitigation initiatives were adjusted. Across capital accounts, approximately $242.5 million is removed, with large reductions tied to drone assessments, centralized data repositories, aviation firefighting, covered conductor programs, and Public Safety Power Shutoff communications, while certain inspection activities were reclassified from capital to O&M. On the O&M side, about $206.1 million is disallowed, including significant reductions to drone assessments, fuels management, PSPS communications, vegetation restoration initiatives, and indirect labor and overhead costs. The appendix also documents proportional reductions to indirect costs and consultant expenses, including Ernst & Young review costs, to align recoverable amounts with approved direct expenditures.
• Appendix B presents the authorized Results of Operations model for both electric and gas WMPMAs, translating the approved costs into annual revenue requirements, depreciation, return, taxes, and interest from 2019 through 2027. The model shows that electric wildfire mitigation costs dominate the overall revenue requirement, while gas-related costs are comparatively small and result in a net overcollection of approximately $735,000. Separately, the decision denies SDG&E's request for $16.9 million in ongoing capital-related gas costs, finding SDG&E failed to demonstrate their connection to wildfire mitigation or adequately explain its allocation methodology. The appendix also reflects prior interim rate relief of $289.9 million granted in 2024–2025 and shows how the remaining undercollection is carried forward and amortized to support rate stability.

"I want to be clear," said Assigned Commissioner Darcie Houck, "that the investor-owned utilities submitting applications have the burden of proof to show that the funds requested should be authorized.

"They control the information and should be presenting it in a way that's complete, understandable and clear. That said, we also recognize that safety is an absolute top priority, and given that the risk reductions that may be achieved through the use of advanced technologies have the potential to greatly improve safety, we want to encourage appropriate safety measures and fully consider whether the cost of inspections and repairs are just and reasonable."

Houck credited SDG&E's wildfire mitigation efforts, noting the utility has not experienced a major wildfire since the 2007 Witch Fire. But she emphasized the CPUC's duty to ensure ratepayer costs remain just and reasonable, citing a recent report finding California's investor-owned utilities spent a combined $9.2 billion on wildfire risk reduction in 2023." Ratepayers alone cannot continue to shoulder the burden," she said, calling on utilities, the Commission, and the legislature to find solutions outside the traditional ratesetting box to contain wildfire costs while maintaining safety standards.

Commissioner John Reynolds echoed the burden-of-proof point, noting that SDG&E failed to demonstrate the reasonableness of its drone program but that the decision appropriately gives the utility a second opportunity in Track 3 given the importance of wildfire safety spending. He encouraged SDG&E to bring key information forward earlier in future proceedings.

INSTANT ANALYSIS: This decision is a hard cost-discipline marker for wildfire mitigation recovery: it approves much of SDG&E's 2019–2022 wildfire spending but draws clear lines around proof, incrementality, and allocation. Large disallowances (especially for drones, aviation firefighting, PSPS communications, data tools, and overhead/support costs) reflect impatience with broad programmatic claims that lack initiative-level justification. For utilities, the takeaway is direct: future WMPMA recovery will turn on granular cost-benefit showings and clean capital/O&M classification, not portfolio-level narratives.

PROVIDER OF LAST RESORT

This decision establishes a procedural framework for how non–investor-owned utilities may seek designation as a Provider of Last Resort (POLR) under Senate Bill 520, while declining to resolve hypothetical policy questions in the absence of a concrete applicant.

The decision finds that no non-IOU entities currently intend to assume full POLR responsibilities for all customer classes within a geographic area, and that interest expressed by some parties is conditional and fact-specific. Consequently, the decision adopts a case-by-case application approach rather than a generalized rulemaking.

It requires any non-IOU applicant to submit a comprehensive application demonstrating financial, technical, and legal capability; compliance with procurement, reliability, and disconnection rules; and protections against cost shifting. The decision clarifies that POLR obligations may not be divided by customer class, affirms that applications must be jointly filed with the incumbent IOU (without granting the IOU veto power), and requires IOUs to be named as respondents.

"I do want to acknowledge," said Commissioner John Reynolds, "that every utility has not just the privilege but the obligation to serve customers in its territory."

He added:

POLR is a serious responsibility. At present, the electric investor-owned utilities act as Providers of Last Resort — the backstop in case an alternative provider fails financially. For example, when Western Community Energy went bankrupt, Southern California Edison had to take 100,000 customers back and provide them electricity service with only four weeks of notice. Southern California Edison, as the Provider of Last Resort, had to be ready for this type of event. So this is a serious responsibility with serious requirements.

This proceeding earlier established the financial requirements of a Provider of Last Resort and a cost-tracking mechanism if customers return en masse to the incumbent utility. Now this proceeding establishes the next steps for any load-serving entity that wishes to take on the privilege and obligation of serving as a provider of last resort.

Reynolds then made a connection between this proceeding and the Power Charge Indifference Adjustment mechanism.

"PCIA," he said, "is used by the Commission to fairly allocate costs between customers who receive their generation from an incumbent utility and those who receive it through direct access or through a Community Choice Aggregator. Sometimes PCIA has been maligned, sometimes misconstrued as a tax, but the PCIA is not a tax — it's a payment made to ensure fairness, so that all customers cover the costs for work that our utilities have done on behalf of all electric customers, not just their own customers – like being the Provider of Last Resort."

INSTANT ANALYSIS: This decision resets the POLR conversation by halting broad policy debates until a real applicant steps forward. Any non-IOU entity considering POLR status now faces a high evidentiary bar: all-customer-class service (though partial geographic territory is permitted); mandatory IOU coordination without IOU veto power; and a bespoke, application-driven review of cost recovery, regulatory authority, and operational readiness. In practice, the ruling leaves IOUs firmly in place as default POLRs while preserving only a narrow, slow, and fact-intensive pathway for future challengers.

SCE ERRA COMPLIANCE

This decision approves SCE’s 2022 ERRA compliance application and finds that SCE largely acted prudently and in compliance with Commission rules during the 2022 record year.

The decision authorizes recovery of $51.442 million in undercollected balances across five accounts, mainly driven by Emergency Load Reduction Program costs, producing an estimated $0.45 per month increase for the average residential customer.

Two cost items are disallowed: $56,500 in CAISO sanctions, which cannot be recovered from ratepayers as financial penalties, and $1.65 million in double-charged franchise fees to departed customers, which must be refunded through a one-time bill credit. The decision also requires SCE to return $14,547 in foregone Public Safety Power Shutoff revenues to customers.

INSTANT ANALYSIS: This decision shows the Commission's continued willingness to approve sizable ERRA undercollections when utilities demonstrate overall procurement compliance, even under 2022 fuel and reliability pressures. At the same time, the decision draws a firm boundary around penalties and administrative errors, confirming that CAISO sanctions and tariff-driven double charges remain shareholder risks, not recoverable from ratepayers. The Commission applied Public Utilities Code §748.1 sua sponte (neither party had raised it) to bar recovery of the CAISO penalties. For CRI readers, the takeaway is that ERRA is still a backward-looking reasonableness review, but one where even minor accounting failures can produce disallowances and refunds in an otherwise clean case.

PG&E + DATA CENTERS

Resolution E-5439 approves, with modifications, PG&E’s request to facilitate transmission upgrades needed to energize a new 90-MW Microsoft data center in San Jose. The resolution authorizes four agreements covering new 115-kV transmission facilities and substation work, but limits how PG&E can refund Microsoft’s upfront energization costs to protect ratepayers.

Rather than applying the standard Rule 15 refund method, the resolution caps annual refunds at 75% of PG&E’s actual net transmission revenues from Microsoft, plus an adjustment for the Income Tax Component of Contribution, and extends the refund window from 10 to 15 years.

The resolution finds this slower refund structure necessary given the project’s scale, transmission-level connection, and risk of stranded costs if projected load does not materialize, while still allowing Microsoft to recover its full eligible costs over time. PG&E opposed the 75% cap in comments but the resolution rejects all three of the utility's arguments.

INSTANT ANALYSIS: This resolution establishes a tougher ratepayer-protection template for large, transmission-level data center interconnections ahead of a finalized Rule 30 framework. By capping refunds at 75% of actual net transmission revenues and extending recovery to 15 years, the resolution makes clear that hyperscale loads will not receive fast, front-loaded refunds based only on projected demand. The resolution explicitly disclaims precedential effect, stating that it should not prejudice the ongoing Rule 30 proceeding (A.24-11-007). For CRI readers, the takeaway is this: future data center, AI, and high-load projects in PG&E territory should expect bespoke cost-recovery limits, slower refunds, and closer scrutiny of stranded-cost risk (though the Commission's final approach awaits Rule 30).

PG&E and MID-TERM RELIABILITY

The CPUC approved two related Mid-Term Reliability actions affecting PG&E’s storage portfolio.

In Resolution E-5432, the Commission authorizes PG&E to execute a third amendment to its existing 300-MW lithium-ion battery contract with Nighthawk Energy Storage, a subsidiary of Arevon Energy. The amendment pushes the project's initial delivery date from June 1, 2025 to June 1, 2026 and approves a revised contract price. Resolution E-5432 finds the delay and price adjustment reasonable given permitting and interconnection delays, inflation, higher interest rates, and supply-chain pressures. It concludes that approval avoids default risk and higher replacement costs while preserving Mid-Term Reliability compliance.

Resolution E-5432 also notes that Nighthawk has now obtained local permits from the City of Poway and San Diego County, secured project financing, and holds a Large Generator Interconnection Agreement with SDG&E, with an expected online date of March 1, 2026 (ahead of the June 1 contractual deadline).

With Resolution E-5437, the Commission separately approved PG&E's execution of a new Mid-Term Reliability contract with Balsam Project, LLC, a subsidiary of Aypa Power Development, for the 225-MW Dirac Battery Energy Storage System. The eight-hour lithium-ion project will be located in Chino and is expected to come online in May 2028 and deliver capacity under a 15-year agreement beginning August 2028. The resolution finds the contract reasonable, competitively procured, and consistent with prior Mid-Term Reliability decisions, approving cost recovery through PG&E's Portfolio Allocation Balancing Account with Power Charge Indifference Adjustment eligibility under the 2021 vintage, subject to prudent administration.

INSTANT ANALYSIS: Together, these approvals show the CPUC balancing schedule risk in near-term Mid-Term Reliability resources with continued build-out of long-lead-time, eight-hour storage. The Nighthawk third amendment reflects regulatory tolerance for delivery slippage when delays are largely outside developer control and replacement risk is higher. The Dirac approval reinforces that competitively procured, eight-hour lithium-ion projects qualify as long-duration storage under a 2025 decision (D.25-06-005) and can clear cost-reasonableness review with confidential pricing and PCIA eligibility. For CRI readers, the combined takeaway is precedent: amended mid-term contracts can survive repeated schedule and price resets, while new eight-hour storage remains a viable compliance pathway for the 2028–2031 window under the Mid-Term Reliability framework.

PG&E and NATURAL GAS RESEARCH

Resolution G-3618 denies PG&E’s proposed Gas RD&D investment plans for 2024 and 2025, rejecting $16.4 million in requested funding and disallowing $7.2 million in cost recovery for RD&D expenses incurred in 2023–2024.

The resolution finds PG&E failed to demonstrate clear ratepayer benefits, relied on insufficient impact analysis, proposed potentially duplicative activities, and did not comply with required administrative cost reporting formats (including failure to use the required template for breaking out the 10% admin budget by category) and planning rules under a 2023 decision (D.23-11-069) and Public Utilities Code §740.1.

PG&E must resubmit revised Tier 3 Advice Letters within 60 days and comply with revised consultation, reporting, and coordination requirements before any Gas RD&D funding can be approved.

INSTANT ANALYSIS: The Commission is drawing a firm line that gas RD&D funding must show a direct, defensible ratepayer benefit, rather than rely on broad decarbonization objectives or compliance-related work. The resolution raises the approval bar for gas RD&D statewide and puts hydrogen and methane research under closer review unless utilities clearly distinguish RD&D from mandated or overlapping programs. The resolution also signals that Energy Division may develop formal strategic goals for gas RD&D modeled on the Electric Program Investment Charge program, which would institutionalize this tighter framework across all gas administrators.

PURPA

Resolution E-5425 approves requests of PG&E and SDG&E to establish PURPA-compliant export tariffs for customer-generation facilities that lose access to Net Energy Metering or Net Billing Tariff due to prevailing wage violations under the Public Utilities Code.

The resolution clarifies that these facilities may continue exporting energy under a PURPA tariff priced pursuant to a 2020 decision (D.20-05-006). However, the resolution adopts an explicit capacity cap of 20 MW per generating facility. This cap aligns with federal PURPA must-take obligations as implemented by FERC and matches the D.20-05-006 pricing structure, which was designed for facilities of 20 MW or less.

While a 2023 decision (D.23-11-068) did not originally impose a size limit, Resolution E-5425 concludes that adding a 20 MW cap avoids confusion, reduces legal risk, and maintains consistency with the federal must-take obligation. PG&E and SDG&E are directed to refile their tariffs reflecting this limitation, and SCE is required to update its previously approved PURPA tariff to match, ensuring uniform treatment across all large electric IOUs.

INSTANT ANALYSIS: Resolution E-5425 reshapes the off-ramp for NEM and NBT customers that lose tariff eligibility due to prevailing wage violations by formally capping the fallback PURPA export tariff at 20 MW per facility. While framed as a clarification, the decision matters because it closes an ambiguity left open in D.23-11-068 and aligns California’s wage-enforcement framework with federal PURPA must-take limits and Rule 21 classifications. The practical effect is to limit how large customer-sited projects can remain economically viable after a wage violation, while also standardizing treatment across PG&E, SDG&E, and SCE. For developers and large behind-the-meter customers, the ruling reinforces that wage compliance failures now carry not just tariff consequences, but hard capacity ceilings that cannot be bypassed through interconnection or export pathways.

UTILITY SITE ACCESS

This decision allows SCE to outsource and monetize telecommunications site access on utility property under General Order 69-C without filing a formal Section 851 application. The decision finds the arrangement remains a limited, revocable use that does not interfere with utility operations, but conditions approval on Commission acceptance of a Tier 3 Advice Letter identifying the buyer and demonstrating its qualifications, conflicts, and market-power safeguards.

The decision also imposes five-year true-up requirements to ensure the lump-sum payment is properly allocated between active (tower) and passive (ground) revenue under the Gross Revenue Sharing Mechanism. The decision also requires shareholders to make ratepayers whole if Non-Tariffed Products & Services revenue falls below the $16.67 million threshold.

INSTANT ANALYSIS: The decision confirms that SCE may outsource and monetize secondary uses of utility property under General Order 69-C (including third-party assignment and lump-sum payments) without a formal Section 851 application. Approval is conditioned on vetting the buyer through a Tier 3 Advice Letter, along with revocability, compliance oversight, and ratepayer protections. The decision references a similar PG&E transaction and directs staff to evaluate whether General Order 69-C should be updated, which suggests this framework may have broader applicability.

OTHER ITEMS

• CRUDE OIL TRANSPORTATION: Resolution O-0100 authorizes San Pablo Bay Pipeline Company, LLC to recover $894,683 in retroactive charges for under-collected crude oil transportation rates from March 1, 2023 through February 28, 2024, consistent with a 2025 Decision (D.25-06-044). The resolution reduces the requested amount by $8,243 by adopting a revised interest calculation methodology proposed by shippers. The resolution leaves disputes over interim rates to pending rate proceedings A.24-01-016 and A.25-01-009.
• ENERGY EFFICIENCY: Resolution E-5442 certifies Peninsula Clean Energy Authority's request to renew and administer its Energy Efficiency FLEXmarket program for a new three-year term, from August 1, 2025 through July 31, 2028, under the "elect to administer" pathway. The resolution approves a total budget of $2.97 million, funded through PG&E non-bypassable EE charges, and requires Peninsula Clean Energy to meet cost-effectiveness thresholds (a pointed requirement given that the program's Total Resource Cost fell to 0.09 in 2024) and coordinate with PG&E and BayREN to avoid customer confusion.
• HYDRO SALE: The CPUC approved SCE's application to sell the Lytle Creek and Fontana hydroelectric plants (3.45 MW combined) to Fontana Union Water Company, finding the sale in the public interest and categorically exempt from CEQA. The decision authorizes recovery of an estimated $9.5 million pre-tax loss through existing balancing accounts and Power Charge Indifference Adjustment rates, and requires post-closing Tier 1 advice letters with final loss and tax calculations.
• SDG&E HOUSEKEEPING: Resolution E-5405 approves SDG&E’s request to recover non-officer compensation costs tied to the company's Vice President, People and Culture role, but reduces the request to $282,983 in O&M expenses for Test Year 2024 after cutting employee food service costs and disallowing professional membership expenses. The approved amounts result in a $265,000 revenue requirement for 2024 and $1.1 million for the 2024–2027 General Rate Case cycle, with minimal rate impacts.