February 26, 2026 CPUC Voting Meeting Results: President Alice Reynolds' Final Meeting

Today's CPUC voting meeting marked the final time Commissioner Alice Reynolds was present for her role as CPUC president. President Reynolds is moving on to work with the CAISO, and fellow commissioner John Reynolds (no relation) will succeed her as head of the public utilities agency.

Gavin Newsom Installs John Reynolds as New CPUC President

Alice Reynolds will step down later this month and join the California Independent System Operator’s Governing Board.

CALIFORNIA REGULATORY INTELLIGENCEMC

In her farewell remarks, President Reynolds commented that, under her stewardship, California has pursued a reliability-first decarbonization strategy. She cited the addition of more than 6,800 MW of new clean capacity in 2025 and the rapid build-out of battery storage to approximately 17,000 MW, presenting both as evidence that the state can maintain grid stability while accelerating the energy transition model, which other jurisdictions are beginning to replicate.

Reynolds also affirmed a universal-service doctrine in which utilities are not permitted to segment customers by profitability, underscoring that grid infrastructure and clean energy delivery must extend to all households and businesses regardless of income.

At the same time, she acknowledged that rising energy affordability pressures now frame virtually every CPUC decision, with cost containment and bill relief shaping approaches to General Rate Cases, program design, and financial-assistance mechanisms for customers struggling to pay utility bills.

The meeting's regular agenda had two major items of note.

• Integrated Resource Planning: A unanimous decision orders California load-serving entities to undertake a new tranche of electric resource procurement for reliability during 2029–2032 while also transmitting recommended resource portfolios to the CAISO for the 2026–2027 transmission planning cycle. An accompanying attachment allocates the procurement obligations across individual LSEs based on their share of forecasted 2026 load, specifying annual capacity targets for 2030–2032 and the portion that must be long-duration storage or clean firm resources.
• Natural Gas Price Spike OII: A decision in Investigation 23-03-008 concludes that the extraordinary spike in California natural gas prices during winter 2022–2023 resulted primarily from severe market conditions rather than misconduct by regulated utilities. This decision is a comprehensive exoneration of regulated gas utilities and storage providers for the price shock. The decision carried 4-0 (Commissioner Matt Baker was recused due to his past work with Cal Advocates).

Additionally, the following items carried on the consent agenda.

• EPIC: A decision adopts a comprehensive set of strategic objectives to guide the Electric Program Investment Charge Program’s 2026–2030 investment cycle, continuing the state’s ratepayer-funded energy innovation efforts while refining governance and accountability.
• V2X Microgrid Pilot: Resolution E-5434 approves, with modifications, PG&E’s request to adjust its Vehicle-to-Everything (V2X) Microgrid Pilot #3, which is designed to test how bidirectional electric vehicles can support community microgrids during outages.
• Mid-Term Reliability: Resolution E-5446 approves two SDG&E mid-term reliability contracts with Golden Fields Solar VI, LLC for standalone battery storage projects totaling 92 MW of nameplate capacity, consisting of a 44 MW four-hour system and a 48 MW eight-hour system expected to begin deliveries on June 1, 2027.
• SGIP: A decision denies Bloom Energy Corp.’s 2024 Petition for Modification of a 2011 decision (D.11-09-015), which governs aspects of the Self-Generation Incentive Program.

The CPUC also delayed consideration of Draft Resolution E-5436 until March 19. As currently worded, that draft resolution increases funding for the California Distributed Generation Statistics platform to $2.6 million per three-year contract and allows annual inflation-indexed adjustments to support ongoing maintenance and expansion.

Greater detail is provided below.

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INTEGRATED RESOURCE PLANNING

A decision orders California load-serving entities to undertake a new tranche of electric resource procurement for reliability during 2029–2032 while also transmitting recommended resource portfolios to the CAISO for the 2026–2027 transmission planning cycle.

"This decision is a true behemoth," said Commissioner John Reynolds, who noted the agency received over 800 pages of comments in the lead-up to its adoption.

The decision finds that rising load forecasts (driven by data centers, electrification, and reduced behind-the-meter resources) combined with uncertainty around project timelines and expiring federal incentives create a need for additional capacity beyond prior Mid-Term Reliability orders.

Accordingly, the decision requires:

• An incremental 2,000 MW of Net Qualifying Capacity online by no later than June 1, 2030;
• An additional 2,000 MW NQC by June 1, 2031; and
• A further additional 2,000 MW NQC by June 1, 2032 (6,000 MW cumulative), with at least one-quarter of each LSE's total obligation due by no later than June 1, 2032 coming from long-duration energy storage resources (able to discharge for at least eight hours) and/or clean firm resources with capacity factors of at least 80% that are not use-limited.

Eligible resources must be new, zero-emitting or renewable, and generally subject to the same compliance framework as earlier procurement mandates.

The decision also provides the CAISO with a reliability- and policy-driven base-case portfolio aligned with California's greenhouse-gas trajectory (targeting about 25 million metric tons of electric-sector emissions by 2035) along with a sensitivity portfolio testing a worst-case slowdown in all wind development, including onshore and offshore.

These portfolios will inform transmission expansion needs under the Transmission Planning Process, where approved projects can receive cost recovery through transmission charges. The CPUC's reliability modeling indicates that even with existing contracts and prior procurement, additional capacity is needed to meet the planning standard of one expected loss-of-load day in 10 years, particularly if long-lead-time resources are delayed.

An accompanying attachment allocates the procurement obligations across individual LSEs based on their share of forecasted 2026 load, specifying annual capacity targets for 2030–2032 and the portion that must be long-duration storage or clean firm resources. For example, the largest bundled utilities (SCE at 2,088 MW and PG&E at 1,077 MW) receive the biggest obligations, while numerous community choice aggregators and electric service providers receive smaller, proportional requirements.

In total, the allocation sums to 5,998 MW of new capacity statewide by 2032, including about 1,505 MW that must come from long-duration storage or clean firm technologies.

Commissioner John Reynolds added:

We must always be sensitive to the ways our models do and do not reflect reality and adapt accordingly. Firm, weather-independent power and storage that can deliver eight or more hours of capacity are exactly the kinds of resources that keep the lights on during a heat wave or extended cloudy weather.

Regarding the transmission side of the decision, Reynolds said that least-cost transmission planning only works if "we know where the power is coming from," and this decision gives the grid operator the necessary info in that regard.

Regarding ratepayers, Reynolds said:

Planning ahead is always cheaper than scrambling for emergency resources when the grid is stressed. This procurement ordered now is how we avoid that scramble. Customers deserve a reliable, clean grid, and they deserve to get it at the lowest feasible cost, and today's decision works towards that exact goal.

INSTANT ANALYSIS: This decision is a forward reliability order disguised as routine IRP housekeeping. By mandating 6,000 MW of new clean capacity across 2030–2032 (with a hard carve-out for long-duration storage and clean firm), the CPUC is pre-positioning the system for potential post-Diablo Canyon conditions, data-center load growth, and the likely shortfall of long-lead resources already slipping to the right.

• The allocation table confirms the burden will fall primarily on the big IOUs and the largest Community Choice Aggregators, meaning procurement activity (and developer leverage) will concentrate in those counterparties over the next 24–36 months.
• Equally important, transmitting portfolios to the CAISO for the 2026–2027 TPP ties procurement directly to transmission expansion, increasing the probability that new lines (and associated cost recovery) follow these resource assumptions. That linkage raises downstream rate exposure risk, because transmission approvals triggered by these portfolios will flow through the TAC regardless of whether load growth materializes as forecast. The decision therefore functions as both a capacity mandate and a transmission cost pipeline.

In short, the decision is an early reliability shock absorber for 2029–2032 that shifts procurement risk onto LSEs now to avoid emergency actions later.

Stakeholders who should care most are IOU procurement teams, large CCAs, storage developers, transmission planners, and large customers exposed to future Transmission Access Charge and Resource Adequacy cost escalation. The practical effect is to pull forward contracting timelines and intensify competition for deliverable clean firm and long-duration storage projects statewide.

NATURAL GAS PRICE INVESTIGATION

A decision in Investigation 23-03-008 concludes that the extraordinary spike in California natural gas prices during winter 2022–2023 resulted primarily from severe market conditions rather than misconduct by regulated utilities.

"The '22-'23 gas price spike was a serious and painful event for California ratepayers," said Commissioner John Reynolds, "and a stark reminder of how our energy system remains dependent on commodity prices."

The Commission finds that prolonged below-normal temperatures and high precipitation levels drove unusually high demand at the same time that supply was constrained by:

• Interstate pipeline outages and maintenance;
• Reduced gas flows from the Permian Basin, Canada, and the Rocky Mountain region; and
• Unusually low storage inventories across the western United States.

Price volatility was further amplified by the convergence of Winter Storm Elliot with the monthly "bidweek" purchasing window, when the January 2023 index price locked in at levels reflecting the December spot surge.

After reviewing extensive evidence, the decision determines that California gas utilities, their procurement departments, and independent storage providers did not intentionally or improperly cause the spike, and that customer bill increases largely reflected prevailing commodity market prices.

FERC separately referred one unnamed market participant for investigation but completed its analysis in November 2024 without additional referrals; the identity of the investigated entity remains undisclosed.

The decision formally defines a "gas price spike event" as a 150% increase in the monthly core procurement price relative to the 10-year average for that month during the winter season (November through March), creating the trigger for the following mitigation measures:

• A temporary cap on utilities' Core Procurement Charge during defined spike events;
• Amortization of under-collections within nine months;
• Enhanced customer notifications within one business day of identifying a spike event;
• Pre-winter early warning notifications no later than October 15 if forward prices indicate a spike;
• Greater transparency around procurement incentives, including a shift from advice letter to formal application process for shareholder awards under PG&E's Core Procurement Incentive Mechanism and SoCalGas's Gas Cost Incentive Mechanism;
• Increased storage reporting, including mandatory public monthly reporting by ISPs and base volume disclosure on PG&E's Pipe Ranger and SoCalGas's Envoy platforms; and
• Planning requirements to incorporate similar constraints into future procurement and hedging strategies.

The decision considers and declines to adopt several additional measures, including a disconnection moratorium, a ban on credit reporting of delinquencies, a residential fixed charge, fuel cost sharing, climate credit changes, and LNG export mitigation tools.

In comments from the dais, Commissioner John Reynolds pointed out that SoCalGas customers absorbed the worst of the price spike because Southern California's gas system was running on a single remaining artery (the El Paso pipeline had been out since the August 2021 rupture) while Aliso Canyon was throttled to reduced capacity. Two critical infrastructure buffers degraded simultaneously. PG&E's territory, by contrast, had geographic diversification and independent storage access that kept its market more liquid.

Reynolds also noted a CAISO report, which showed $3.9 billion in additional wholesale electricity costs in December 2022 and January 2023 alone, driven by the same gas price spike. Gas generators are noncore customers outside CPUC procurement jurisdiction, but these costs flow straight through to ratepayers via the generation charge. Meaning the gas spike was also an electricity spike.

On the decision itself, Reynolds backed the new consumer protection package: a temporary winter-only cap on the core procurement charge, nine-month cost amortization, and mandatory customer notification within one business day of a spike identification. He specifically rebutted the argument that rate caps erode price signals, noting that core gas customers currently have zero real-time rate visibility (bills arrive after the fact). The mandatory notification framework, he argued, actually creates a more functional price signal than the status quo silence.

Last, Reynolds noted that, although previous storage limits on Aliso Canyon were not arbitrary, they were a response to the facility's 2015 leak, "a better stocked Aliso Canyon – operated safely – is a meaningful buffer against the kind of dual market shock that we saw in the winter of '22 and '23."

Reynolds also added that his remarks should not be construed to mean that Aliso Canyon should operate indefinitely or without scrutiny. "The right answer going forward," he said, "will require weighing affordability, reliability, safety and California's long-term decarbonization goals together."

INSTANT ANALYSIS: This decision is a comprehensive exoneration of regulated gas utilities and storage providers for the Winter 2022–2023 price shock. The decision firmly attributes the spike to upstream market fundamentals (weather-driven demand, pipeline outages, reduced imports, and depleted storage) rather than procurement misconduct or market manipulation.

The Commission's policy focus therefore shifts from enforcement to resilience: it establishes a formal "gas price spike event" trigger, authorizes temporary caps on the Core Procurement Charge with amortization, and mandates advance customer notifications and transparency reforms.

For stakeholders, the real significance is prospective: the decision creates a regulatory trigger framework for future volatility, strengthens oversight of procurement incentive mechanisms by requiring formal applications rather than advice letters for shareholder awards, and elevates storage transparency (including public ISP inventory reporting). All of these actions will shape winter reliability planning, hedging strategies, and rate design debates going forward.

Several issues are deferred to other proceedings.

ELECTRIC PROGRAM INVESTMENT CHARGE (EPIC)

A decision adopts a comprehensive set of strategic objectives to guide the Electric Program Investment Charge Program’s 2026–2030 investment cycle, continuing the state’s ratepayer-funded energy innovation efforts while refining governance and accountability.

• The decision authorizes the investor-owned utilities to remain EPIC administrators, permits collection of funds for the next cycle, and updates program rules on intellectual property, evaluation, and oversight.
• The decision establishes 13 measurable objectives under five Strategic Goals (e.g., Transportation Electrification, DER Integration, Building Decarbonization), clarifying that future EPIC projects must advance at least one objective but administrators need not address all 13 in their investment plans.
• The decision authorizes a new program evaluation in 2028 to address data gaps that may inform Commission consideration of whether to continue EPIC past its current 2030 sunset, while extending the deadline for EPIC 5 investment plan applications to August 26, to accommodate the new requirements. IOU community engagement plan advice letters are due by June 26.

INSTANT ANALYSIS: This decision translates previously adopted Strategic Goals into 13 binding objectives that will govern EPIC’s 2026–2030 investment cycle under continued utility administration, narrowing how ratepayer-funded RD&D must align with electrification, DER integration, building decarbonization, gas transition, and climate adaptation priorities.

The consequential move is the scheduled 2028 evaluation, positioned to inform whether EPIC continues beyond its 2030 sunset. Program survival is now tied more explicitly to demonstrable ratepayer value and measurable outcomes, while the August 26 application deadline (preceded by June 26 community engagement filings) forces administrators to sequence stakeholder input before proposing portfolios.

VEHICLE-to-EVERYTHING PILOT

Resolution E-5434 approves, with modifications, PG&E’s request to adjust its Vehicle-to-Everything (V2X) Microgrid Pilot #3, which is designed to test how bidirectional electric vehicles can support community microgrids during outages.

The resolution grants PG&E additional time to complete Phase I demonstration work at the Redwood Coast Airport Microgrid, setting a final completion date of June 30, so the utility can repair damaged chargers, resume testing, and collect operational data.

• The Commission finds the extension reasonable given delays outside PG&E's control, including federal funding timing, equipment failures, vendor issues, and technical challenges encountered during early testing of frequency-based controls that allow vehicles to charge and discharge in response to grid conditions.
• PG&E must file a Tier 2 Advice Letter within 30 days providing both an updated Phase I completion schedule with revised milestones and a narrative explaining how it will meet the pilot's original success metric of demonstrating five to 10 bidirectional vehicles, as only two are currently participating.

For Phase II, the resolution approves PG&E’s shift from a customer enrollment and incentive program to a “Hybrid Support Model.” Under this approach, PG&E will stop enrolling new participants, return unspent customer incentive funds to ratepayers by reducing the pilot’s authorized budget, and instead provide technical consulting to community microgrid projects using internal resources.

Regulators conclude that this change reflects market realities, including the limited availability of operational community microgrids, slow development timelines, equipment constraints, and the early stage of bidirectional charging technology. Neither the Schatz Energy Research Center nor the Vehicle Grid Integration Council opposed the modifications. The Council recommended redirecting freed resources to the Residential and Commercial V2X pilots.

The modified pilot is intended to apply lessons learned from Phase I to emerging microgrid projects while limiting costs and protecting ratepayers, reducing the pilot's budget from $1.5 million to $750,000 and lowering the Vehicle Grid Integration subaccount cap within the Transportation Electrification Balancing Account from $11,700,000 to $10,950,000.

INSTANT ANALYSIS: This resolution basically downgrades PG&E’s V2X microgrid pilot from a deployment program to a contained learning exercise, reflecting continued immaturity in bidirectional EV and community microgrid readiness. By extending Phase I but halting enrollment, cutting incentives, and demanding justification for missed success metrics, regulators are prioritizing data extraction and cost control over expansion.

The Hybrid Support Model preserves PG&E’s technical role in future microgrid development while limiting ratepayer exposure, suggesting a shift toward slow capacity-building rather than near-term commercialization of V2X microgrid integration. VGIC's recommendation to redirect freed pilot resources toward the Residential and Commercial V2X pilots signals where future funding pressure may concentrate.

MID-TERM RELIABILITY

Resolution E-5446 approves two SDG&E mid-term reliability contracts with Golden Fields Solar VI, LLC (Clearway) for standalone battery storage projects totaling 92 MW of nameplate capacity, consisting of a 44 MW four-hour system and a 48 MW eight-hour system expected to begin deliveries on June 1, 2027. Both are 15-year power purchase tolling agreements.

The contracts, awarded through SDG&E's Tranche 3 solicitation under the state's Integrated Resource Planning procurement mandates, are intended to help the utility meet its 2027 reliability requirements ordered in D.23-02-040. SDG&E's broader mid-term reliability procurement obligation also includes 103 MW of zero-emitting capacity to replace generation retiring at Diablo Canyon, though that requirement applied to resources online by 2025.

Notably, shortlisted projects were unable to hold original offer prices due to supply chain cost volatility driven by increased import tariffs, leading SDG&E to negotiate price adjustments. SDG&E asserts the final negotiated prices still resulted in high positive net market values and remained the least-cost/best-fit solutions.

The resolution finds the solicitation process, least-cost/best-fit evaluation, and negotiated agreements reasonable, and approves recovery of contract costs from customers through the Portfolio Allocation Balancing Account:

• The 8-hour Power Purchase Agreement via the 2021 Power Charge Indifference Adjustment vintage; and
• The 4-hour PPA via the 2023 vintage (applicable to bundled and departing load customers).

INSTANT ANALYSIS: Three things matter here.

• First, SDG&E renegotiated prices after shortlisting because bidders couldn't hold offers through import tariff-driven supply chain volatility (and the draft resolution blessed it without protest). This is now a template for every utility running storage procurement in 2026-2027.
• Second, both contracts go to Clearway (Golden Fields Solar VI), consolidating developer concentration inside SDG&E's portfolio (two standalone battery projects, same developer, same commercial operation date, 15-year tolling agreements).
• Third, the 48 MW 8-hour system overshoots SDG&E's 41.5 MW long-duration storage requirement a year early, locking in 8-hour lithium-ion at 2024 bid prices before longer-duration mandates potentially expand under the next IRP cycle.

While this matter was unprotested and routine on the surface, the renegotiation precedent, developer concentration, and early long-duration positioning suggest where the next procurement round is heading.

SELF-GENERATION INCENTIVE PROGRAM

A decision denies Bloom Energy Corp.’s 2024 Petition for Modification of a 2011 decision (D.11-09-015), which governs aspects of the Self-Generation Incentive Program. Bloom sought to increase the program’s annual export cap from 25% to 50% of a project’s net generation, arguing that advancements in its fuel cell technology and evolving SGIP policies now justify greater exports to the grid.

The CPUC finds the petition procedurally deficient under its Rules of Practice and Procedure, which requires petitions for modification to be filed within one year of a decision’s effective date unless the petitioner explains why it could not have done so earlier. Because Bloom filed its petition nearly 13 years after the original 2011 decision and relied primarily on technological evolution and policy changes as justification, the CPUC concludes that the late filing was not adequately explained.

Although Bloom’s position was supported by the Bioenergy Association of California and jointly by SoCalGas and the Center for Sustainable Energy, Cal Advocates opposed the petition, arguing that SGIP’s purpose is to promote self-generation, not expanded grid exports.

INSTANT ANALYSIS: This decision keeps export-dependent distributed generation models constrained under current SGIP rules and warns developers that technology evolution alone will not justify reopening settled program limits.