November 20, 2025 CPUC Voting Meeting Preview

The CPUC’s November 20 voting meeting features items that collectively illustrate a tightening focus on cost discipline, auditability, and program sunsets.

From the closure of legacy incentive programs to the recalibration of market-transformation budgets and undergrounding rules, the CPUC's agenda is indicative of a gradual shift from the open-ended experimentation of previous years to measured execution.

Across numerous proceedings, the Commission appears to be injecting fiscal realism e.g., quantifiable benefits, verified compliance, and clear exit pathways. The true challenge for the agency, however, will be producing outcomes that convince ratepayers this course correction is working, and that California’s energy governance is accountable (in addition to being ambitious).

Below are summaries of most key items.

Undergrounding of Electrical Equipment

Draft Resolution SPD-37 updates and refines the CPUC’s Senate Bill 884 program, which governs the expedited undergrounding of electric distribution lines by large utilities.

The draft resolution builds on Resolution SPD-15 (2024) and aligns CPUC procedures with the Office of Energy Infrastructure Safety’s 2025 guidelines for 10-year Electric Undergrounding Plans (EUPs). The new resolution expands Phase 2 of the review process (covering cost applications and conditional approvals) by adding detailed data and audit requirements to ensure costs are just, reasonable, and ratepayer-protective.

If Draft Resolution SPD-37 is adopted, utilities such as PG&E, SCE, and SDG&E would be obligated to:

• Submit standardized project datasets, revenue-requirement models, and Key Decision-Making Metrics;
• Justify any work outside of high-fire-threat areas; and
• Include only projects with benefit-cost ratios ≥ 1 that meet specified project-level risk thresholds.

The draft resolution also establishes new conditions for cost recovery, requiring that undergrounding projects outperform alternative mitigations, remain within approved cost and benefit thresholds, and satisfy Energy Safety performance standards.

Additionally, the draft resolution introduces an annual EUP Audit to verify compliance and ensure costs are used and useful. A cumulative memorandum-account cost cap is added to prevent unlimited cost transfers.

Instant Analysis: Draft Resolution SPD-37 trades speed for greater certainty: it slows execution but adds new oversight layers, in an effort to pursue undergrounding not merely as wildfire symbolism, but as infrastructure risk mitigation that can withstand audit, appeal, and political scrutiny. Union criticism, however, argues that this approach sacrifices urgency for bureaucracy by delaying shovel-ready work and weakening the state’s frontline defense against catastrophic fires.

Self-Generation Incentive Program Ends

If adopted, this proposed decision would close out the ratepayer-funded Self-Generation Incentive Program (SGIP) and establish procedures for returning unspent funds to customers while launching a "Greenhouse Gas Reduction Fund" (GGRF) version of the SGIP.

As conceived, the GGRF would allocate $280 million in funds to provide solar-plus-storage incentives, specifically for low-income residential customers, including those served by public utilities. Unlike the original SGIP, which was financed through utility rate collections, the GGRF draws from Cap-and-Trade revenues.

All new ratepayer-funded SGIP applications and waitlists will close on December 30, 2025, with unallocated funds refunded through annual Tier 1 advice letters using existing rate true-up mechanisms. (Tier 1 filings take effect automatically, unless staff objects.) Utilities must return remaining funds by 2033, and new projects will have a shortened two-year performance-based incentive period.

The PD also grants up to four additional six-month extensions for delayed non-residential equity projects and removes the COVID-era “Stay on Cancellation” policy. (The latter policy temporarily paused the automatic cancellation of SGIP projects that were delayed due to pandemic-related disruptions, allowing participants more time to complete installations.)

Instant Analysis: This PD formally winds down two decades of ratepayer-funded SGIP activity and shifts the program toward a state-funded future. The PD closes the books cleanly (returning unused funds, shortening incentive timelines, and tightening oversight) while focusing on low-income customers with the new GGRF-backed incentives.

PG&E Zonal Electrification Pilot at California State University Monterey Bay

This proposed decision grants PG&E's motion to withdraw its application (A.22-08-003) for a zonal electrification pilot project at California State University Monterey Bay.

• PG&E had sought approval to substitute a planned gas-pipeline replacement with an all-electric conversion of several hundred campus dwellings, capitalizing the costs like a regulatory asset so shareholders could earn a return.
• The project aimed to test building-level electrification as a substitute for gas-infrastructure investment, advancing California’s decarbonization goals. After protracted procedural delays, PG&E exercised its contractual right to terminate the project, citing safety risks and a 2026 remediation deadline that conflicted with the regulatory timeline.

Several parties (including TURN, Natural Resources Defense Council, Sierra Club, and the Environmental Defense Fund) opposed the withdrawal, arguing that PG&E’s rationale was vague and possibly aimed at avoiding an adverse outcome. Others, such as Indicated Shippers/Agricultural Energy Consumers Association, supported withdrawal, saying the issues could be better handled in broader proceedings like the Long-Term Gas System Planning docket.

The PD finds the withdrawal reasonable and in the public interest since PG&E’s termination renders the project moot. Still, the PD preserves policy value: it directs PG&E to file a “lessons-learned” report within 90 days, to disclose this record in future electrification or decarbonization filings for three years, and to make the evidentiary record available for use in later proceedings.

Instant Analysis: This PD demonstrates pragmatism regarding experimental electrification projects – it allows PG&E to abandon a pilot that became impractical, while salvaging its informational and policy value. Significantly, this proceeding revealed an enduring friction over cost allocation, as PG&E's plan would've spread electrification costs across all gas ratepayers for a localized benefit zone. That discussion will surely carry over into the Long-Term Gas Planning proceeding as Senate Bill 1221 implementation picks up steam.

Mobilehome Electrification Initiative

This PD establishes a joint Mobilehome Park Electrification Pilot Initiative with the California Energy Commission. Under the pilot, PG&E, SCE, and SDG&E will partner with the CEC’s Equitable Building Decarbonization (EBD) program to fully electrify selected mobilehome parks while converting their submetered systems to direct, utility-owned electric service under the existing Mobilehome Park Utility Conversion Program (MHP UCP).

• Participating parks must agree to permanently retire gas infrastructure, replace appliances with efficient electric models, and receive necessary in-home rewiring and panel upgrades. The goal is to study the technical, legal, and cost implications of full electrification and inform future modifications to the MHP UCP.
• The PD directs utilities to coordinate with CEC staff and regional administrators but prohibits them from installing new gas infrastructure or recovering additional ratepayer funding. Instead, the program will leverage non-ratepayer sources, primarily the EBD program’s $567 million budget supported by state and federal funds.
• Tenant protections mirror those in the MHP UCP and EBD guidelines, ensuring residents are informed, protected from rent hikes, and supported during construction.

Instant Analysis: By merging the Mobilehome Park Utility Conversion Program with the CEC’s Equitable Building Decarbonization initiative, the Commission is testing how to scale end-to-end electrification without burdening ratepayers. The PD seems to represent a broader intent to retire small gas systems, leverage federal Inflation Reduction Act funds, and coordinate cross-agency decarbonization in disadvantaged communities.

Energy Efficiency Market Transformation

The CPUC is scheduled to review competing proposed decisions to address energy efficiency market transformation. If adopted, Commissioner Matt Baker's alternate proposed decision (APD) would approve ratepayer funding for only one "Market Transformation Initiative," or MTI (the Room Heat Pump program), while denying the California Market Administrator (CalMTA)'s proposed Induction Cooktop MTI and related future initiatives.

Commissioner Baker's APD authorizes a six-year six-year budget of $54.87 million (2026–2031), which is about half the amount recommended by the Administrative Law Judge in a competing PD.

The APD orders CalMTA to:

• File annual reports;
• Submit a 2028 Tier 2 advice letter detailing its transition to non-profit status and plans for seeking non-ratepayer funding (Tier 2 filings are reserved for substantive but routine matters);
• Provide the CPUC a perpetual license to its internal cost-effectiveness tool; and
• Undergo annual audits by the CPUC’s Audit Branch.

By rejecting $27.6 million for the Induction Cooktop MTI and $139 million in unspecified future work, the APD narrows CalMTA’s scope, aligns funding with ratepayer affordability under Executive Order N-5-24, and conditions future MTIs on demonstrated fiscal transparency and diversified funding sources.

The CPUC was originally set to consider this item on October 30 but delayed action until November 20.

Instant Analysis: By authorizing only the Room Heat Pump initiative and cutting the total program budget nearly in half, the APD redefines what “market transformation” will mean under heightened affordability concerns. The move aligns with Executive Order N-5-24, reinforcing a shift toward targeted, measurable electrification investments over expansive decarbonization pilots. The strengthened audit, non-profit-transition, and non-ratepayer-funding requirements point to a future in which CalMTA must operate more like a public-benefit enterprise than a ratepayer-funded laboratory. (Note that, typically, commissioner APDs tend to win out in the voting process over ALJ PDs.)

Avoided Cost Calculator

This proposed decision revises the Avoided Cost Calculator (ACC) process and increases its consultant budget from $350,000 to $1.2 million per year.

The ACC, which quantifies avoided generation, transmission, and emissions costs for Distributed Energy Resources, will now follow a streamlined biennial update cycle. This cycle will align with the CPUC’s Integrated Resource Planning Transmission Planning Process portfolio when the "Preferred System Plan" is unavailable.

As a reminder, the Commission develops two key portfolios in the IRP process:

• The Preferred System Plan, which shows the optimal mix of resources to meet climate and reliability goals; and
• The Transmission Planning Process "base-case" portfolio, a closely related dataset sent to the CAISO for use in planning its transmission buildout.

The revised ACC process removes automatic evidentiary hearings and multiple comment rounds but preserves workshops and allows hearings if factual disputes arise, to deliver faster, more consistent updates.

Instant Analysis: This proposal represents an attempt to modernize the CPUC’s cost-effectiveness framework for DERs, by replacing procedural inertia with tighter coordination and current data inputs. The budget increase reflects growing model complexity, inflation, and the expanding role of DER valuation in grid planning.

Distributed Energy Resources

This proposed decision denies a petition filed by the California Efficiency + Demand Management Council to modify a 2019 decision (D.19-05-019), which had established the "Total Resource Cost" (TRC) test as the primary framework for evaluating Distributed Energy Resources.

The Council sought to replace the TRC with the "Program Administrator Cost" test for budget allocations, arguing that TRC penalizes high-upfront-cost measures. The PD finds the petition procedurally deficient and untimely.

Major parties including Cal Advocates, PG&E, SCE, SoCalGas, and SDG&E opposed the petition, asserting that its arguments belonged in current DER or energy-efficiency proceedings (not this rulemaking, which was launched in 2014). NRDC and Recurve supported the petition.

Instant Analysis: By rejecting the Council’s petition, the Commission's message seems to be that debates over cost-effectiveness frameworks, however imperfect, will not be reopened without compelling new evidence or timely justification. The PD also suggests that broader policy shifts, such as executive orders or auditor critiques, do not automatically warrant retroactive regulatory changes. For stakeholders, the apparent message is that any future push to recalibrate DER valuation or affordability metrics must occur within active proceedings.

Mid-Term Reliability

Draft Resolution E-5428 approves eight new mid-term reliability contracts and one amendment submitted by SCE under its 2025 procurement plan. The portfolio includes solar-plus-storage projects in Kern and Riverside Counties and a solar project in Arizona, totaling about 498 megawatts, plus a 75-MW amendment to the Gateway battery facility in San Diego that extends its delivery date to 2027 following a 2024 thermal event investigated by the CPUC and the Environmental Protection Agency.

Collectively, these contracts supply roughly 151 MW of effective capacity toward SCE’s obligations under the CPUC's original "mid-term reliability" decision (D.21-06-035) and a supplemental procurement decision (D.23-02-040). The solar agreements also contribute to SCE’s Diablo Canyon Replacement and Renewable Portfolio Standard targets.

Draft Resolution E-5428 finds the contracts consistent with SCE’s 2024 RPS Procurement Plan, competitively priced, and procured through a transparent, least-cost/best-fit process verified by independent evaluator Sedway Consulting.

Costs will be recovered through the Portfolio Allocation Balancing Account (the 2021 sub-account for solar and 2023 for storage) with all ratepayers sharing benefits and costs. Contract prices and cost data are confidential, pursuant to the Public Utilities Code.

Instant Analysis: By approving SCE’s solar-plus-storage portfolio and extending the Gateway BESS contract after a 2024 fire, the Commission is demonstrating some flexibility toward operational realities. The confidential pricing underscores a cautious stance toward market sensitivity, which is par for the course on these types of agreements.

Bioenergy Market Adjusting Tariff

This proposed decision denies 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 (BioMAT) program through December 31, 2025.

In their petition, the Association sought to remove or extend that sunset date to 2035 and make several programmatic changes, arguing the program supports wildfire mitigation, waste reduction, and air-quality goals.

• The PD finds that the BioMAT, which was created under Senate Bill 1122 (2012) to procure 250 megawatts of small-scale bioenergy, is underused, high-cost, and duplicative of other procurement mechanisms such as the Renewables Portfolio Standard, Renewable Market Adjusting Tariff, BioRAM, and Qualifying Facility contracts.
• Only about 21% (51 MW) of the authorized 250 MW has been subscribed since 2016, despite numerous rule changes. Energy prices under BioMAT (12.8 ¢/kWh to 20 ¢/kWh) substantially exceed other renewable options (which are approximately 8 ¢/kWh).

The PD concludes that continuing the program would conflict with the Governor’s Executive Order N-5-24 on affordability, which directs agencies to sunset underperforming or high-cost initiatives.

Instant Analysis: Some critics would argue, perhaps rightly, that the Governor’s Executive Order N-5-24 carries more than a trace of performative self-protection for a leader whose national aspirations are well known. Nevertheless, the CPUC seems to be treating the governor's affordability directive as substantive policy rather than symbolic gesture. This PD serves as additional proof.

Union Island Pipeline

This proposed decision denies a request of California Resources Production Corporation (CRPC) for a Certificate of Public Convenience and Necessity (CPCN) to operate the 35-mile Union Island natural gas pipeline as a public utility gas corporation.

The PD finds that CRPC does not currently qualify as a “gas corporation” or “public utility” under California law because it no longer holds valid franchise rights in Antioch and Brentwood (those expired in 2021), and it stopped transporting gas in May 2023.

The PD also cites ongoing litigation in which Antioch argues CRPC abandoned its pipeline interests, concluding that CRPC does not own, control, or operate the full pipeline and therefore cannot dedicate it to public use. The PD denies CRPC’s request to substitute a subsidiary into the application and the cities’ request to pause the proceeding, but grants CRPC’s motion to keep financial documents sealed for three years.

Instant Analysis: This PD shows the CPUC’s unwillingness to extend public utility privileges to entities that lack clear, current control of infrastructure or local operating rights. The PD also reinforces that dormant or speculative operations cannot satisfy statutory definitions of “gas corporation” or “public utility.” (For more info on this item, please see our November 7 Aggregate, which details CRPC's recent motion to reopen the record.)

Crude Oil Transportation

This proposed decision authorizes Crimson California Pipeline, LP to raise its crude-oil transportation rates on its Southern System by 26.35%, retroactive to August 1, 2024, with interest.

The PD finds the increase just and reasonable after Crimson removed parent-company CorEnergy's finances from its filing and adopted a 60/40 equity-to-debt ratio, 12% cost of debt, and 15% return on equity, consistent with Bluefield and Hope standards for financial soundness. According to the PD, a smaller 10% increase would have left Crimson operating at a loss.

Instant Analysis: By approving a 26.35% increase (more than double the statutory 10% self-implementation cap) the Commission is telegraphing that maintaining safe, solvent operations outweighs short-term rate stability. The PD also establishes an apparent precedent: parent or affiliate financials cannot be used to inflate cost recovery. But once excluded, the CPUC will still accommodate reasonable equity returns to prevent underinvestment or safety degradation.