FRIDAY AGGREGATE: Resource Adequacy Priorities; Residential Rate-Design Debates; Demand Surges

Common themes in today's briefing center on how California will price, plan, and pay for its hyper-ambitious energy transition.

• The CPUC's new Resource Adequacy rulemaking heard from multiple parties, with Slice-of-Day transactability, Unforced Capacity, Loss of Load Expectation, and numerous other key subjects under the microscope.
• Debates in SCE's General Rate Case Phase II cover fixed charges and demand-based pricing, with SCE advocating for cost-based electrification tools while Cal Advocates and SEIA question legality and customer readiness. TURN injects Net Energy Metering disputes into the mix.
• A technical skirmish over pre-2019 banked Renewable Energy Credits in SCE's 2026 ERRA Forecast raises the question of whether cost-indifference principles can be rewritten outside of formal policy proceedings.
• As planning reports from all three investor-owned utilities confirm that electrification will drive massive grid investment, PG&E is struggling to keep pace with demand surges, which raises serious questions about whether planning cycles can match the speed of California's clean-energy ambitions.

Parties Provide Initial Responses to New Resource Adequacy Rulemaking

Multiple parties filed responses to the CPUC's Resource Adequacy successor docket, which launched last month. Below are micro-summaries from select parties.

• CAISO: The CAISO supports the Commission's move toward an Unforced Capacity-based Resource Adequacy framework, and urges updates to storage qualifying capacity calculations to better reflect operational realities.
• CAL ADVOCATES: Cal Advocates supports the new rulemaking but urges the Commission to revise its schedule to add formal comment periods for the Loss of Load Expectation study and its inputs, and to allow more time for stakeholders to respond to party proposals.
• CALIFORNIA COMMUNITY CHOICE ASSOCIATION (CALCCA): CalCCA urges the Commission to prioritize fixing Slice-of-Day (SOD) transactability in the new RA rulemaking, and to modify the schedule so parties can update proposals after the Energy Division issues its SOD transactability report. CalCCA also asks the rulemaking to (i) include load forecasting, (ii) clarify how Central Procurement Entities should use local RA data, (iii) align Maximum Import Capability rules with SOD, and (iv) address Demand Response/Distributed Energy Resources/microgrid counting.
• PG&E: PG&E supports the new rulemaking but asks to split Track 1 so most refinements are filed in January 2026 and to delay SOD transactability proposals until after the Energy Division SOD report. PG&E also prioritizes updates to RA compensation data, load-migration rules, self-shown resource remarketing, Demand Response export eligibility, and RA treatment of large load facilities.
• SCE: SCE supports the successor docket but asks the Commission to expand the scope to include Demand Response accreditation and off-peak import rules.
• TURN: TURN argues that the CPUC’s Resource Adequacy program must begin accounting for greenhouse gas emissions from capacity resources, as current rules allow load-serving entities to rely on fossil-based reliability resources without any emissions attribution.

PG&E General Rate Case Phase 2

A new PG&E motion asks the CPUC to adopt a schedule for the separated Real-Time Pricing (RTP) track of its General Rate Case Phase II. Following an earlier ruling that split RTP into its own track, PG&E proposes a two-step process.

• First, PG&E seeks expedited approval of a “Stop-Gap” plan to extend the current Hourly Flex Pricing pilots, which are set to expire on December 31, 2027. In PG&E's view, this will ensure that customers continue to have RTP options until the utility’s billing modernization is completed, which is not expected until 2030. PG&E plans to submit testimony for this Stop-Gap proposal by January 30, 2026, aiming for a final CPUC decision by November 2026 so implementation can begin in 2027.
• Second, PG&E proposes a longer-term schedule to develop and implement permanent post-pilot RTP rates. This second phase would begin with updated testimony in late 2027, incorporating cost estimates, system upgrades, and lessons from pilot evaluation results and the CPUC’s Enhanced Demand Response rulemaking.

PG&E argues that its approach balances administrative efficiency with the need to maintain uninterrupted customers' RTP options.

INSTANT ANALYSIS: PG&E seems to be saying that full-scale dynamic pricing cannot happen on any timeline but its own. If the CPUC accepts this structure, customers may not see post-pilot RTP rates for several years, underscoring how legacy billing infrastructure is shaping California’s rate-design trajectory as much as regulatory intent.

SCE General Rate Case Phase 2

Parties filed opening briefs in SCE's General Rate Case Phase II (A.24-03-019) to address three main issues:

• SCE’s proposed TOU-D-PRIME Plus rate;
• Baseline allowance treatment; and
• Transmission marginal costs.

SCE argues that its new optional PRIME Plus rate, which features a $49 fixed charge and on-peak demand charge, better reflects cost causation, supports electrification, and should be approved. Cal Advocates and SEIA oppose it, arguing the rate misaligns with real grid stress, lacks evidence of customer demand or understanding, and includes non-marginal distribution costs in the fixed charge in violation of law. Both groups argue that existing dynamic rates or volumetric TOU structures are superior.

TURN limits its brief to baseline allowances. TURN urges the Commission to require SCE to include behind-the-meter Net Energy Metering generation in baseline usage calculations. In TURN's view, excluding this solar production artificially lowers measured average usage, leading to reduced baseline allowances that disadvantage non-solar customers. SCE counters that such a change exceeds statutory authority and should be considered in a broader rulemaking.

SEIA also presses for adoption of a $73/kW-year marginal transmission capacity cost for SCE, using a methodology previously approved for PG&E, while SCE and Cal Advocates say the proposal is premature and outside scope. Cal Advocates further opposes using the Avoided Cost Calculator to set export credits in the Vehicle-to-Grid settlement.

INSTANT ANALYSIS: The evolution of this discussion may offer key insights into how far the CPUC might go in shifting residential rate design toward cost-based electrification tools like fixed charges and demand components. SCE is pushing PRIME Plus as a new form of residential pricing (with a higher fixed charge, demand charge, and lower volumetric rates). Cal Advocates and SEIA both argue the proposal is misaligned with real grid stress, is unsupported by customer data, and is potentially unlawful due to the inclusion of non-marginal distribution costs in the fixed charge. TURN injects NEM into the discussion, with another variation of the ongoing cost-shift argument.

SCE ERRA FORECAST

In reply briefs for SCE's 2026 ERRA Forecast application, the California Community Choice Association (CalCCA) defends its proposal to value all banked Renewable Energy Credits (RECs), including those generated before 2019, at the Market Price Benchmark (MPB) in the year they are retired.

• CalCCA urges the Commission to harmonize REC treatment across all investor-owned utilities, notes inconsistencies in prior ERRA cases, and asserts that its proposal does not create double-charging but simply credits departed customers for their past contributions. CalCCA also states that issues related to its rehearing request for a 2025 decision (D.25-06-049), which was denied, are now moot.
• SCE’s reply strongly opposes CalCCA, arguing that precedent expressly limits REC valuation to post-2018 procurement and supports valuing pre-2019 banked RECs at zero for PCIA purposes. In Edison's view, CalCCA is attempting to rewrite policy in a non-policy setting, which creates double-payment risks for bundled customers, and ignores complexities in REC vintaging and cost allocation.
• SCE also asserts that CalCCA’s arguments on RA MPB and retroactive ratemaking improperly attack D.25-06-049. On rate impacts, SCE argues Power Charge Indifference Adjustment volatility is the result of corrected RA MPB methodology and historical swings have also benefited departing load customers.

Last, SCE maintains its October Update corrections to its RA modeling were technical fixes, not policy shifts, and asks the Commission to approve its $4.689 billion revenue requirement and associated PCIA and balancing account recovery.

INSTANT ANALYSIS: The dispute over pre-2019 banked RECs raises the question of whether ERRA is a policy forum and how far the CPUC will stretch “indifference.” CalCCA is pushing the Commission to require utilities to credit the value of older banked RECs to departed customers using current-year MPBs, arguing that this approach simply honors what customers already paid for and should be standardized across IOUs.

Edison characterizes this as an attempt to retroactively rewrite PCIA rules, which violates bundled customer indifference, directly contradicts prospective-only REC valuation that the CPUC established in a 2019 decision (D.19-10-001), and would create double-payment and cost-allocation distortions.

The CPUC’s handling of this matter may demonstrate how tightly it intends to police procedural boundaries and the limits of cost neutrality.

DISTRIBUTION PLANNING

In our November 5 Wednesday Aggregate, we reported on draft "Electrification Impacts Study: Part 2" reports that PG&E and SCE filed in the CPUC's High DER Future proceeding (R.21-06-017). The utilities' reports show that electrification will require massive-but-manageable upgrades to the state's distribution grid, with costs that can be partially offset by load growth and demand flexibility.

SDG&E also provided its draft report. SDG&E's analysis shows that equity scenarios increase infrastructure needs and costs the most, while demand flexibility reduces them by lowering peak loads.

Separately, PG&E filed its 2025 Distribution Planning Advisory Group (DPAG) Independent Professional Engineer (IPE) Report. The report evaluates and verifies PG&E’s 2025 Grid Needs Assessment (GNA) and Distribution Upgrade Project Report, which together outline distribution system needs and planned investments for the 2025–2026 Distribution Investment and Deferral Framework cycle.

The IPE methodology for reviewing PG&E’s planning includes how the utility forecasts load growth, how it incorporates DERs, how it models circuit-level conditions using AMI-based hourly load profiles, and how it identifies grid deficiencies in capacity, voltage support, reliability, and resiliency.

The report notes procedural changes, such as the elimination of deferral solicitations under a 2024 CPUC decision (D.24-10-030), and highlights that PG&E expanded its planning horizon for GNA to 13 years.

The report also summarizes the volume and types of grid needs (over 1,000 total deficiencies), examines planned investments to address them, evaluates PG&E’s known load tracking and forecasting accuracy, and provides recommendations, particularly around tracking pending loads, refining data transparency, and assessing whether planned projects remain necessary as conditions evolve.

INSTANT ANALYSIS: PG&E is entering a period of accelerated stress, driven by surging load requests and mass electrification. And while its planning tools are improving, PG&E risks running behind real-world demand unless it tightens validation of load materialization, incorporates pending load tracking, and more aggressively confirms whether planned upgrades are still timely and sufficient.

UNION ISLAND PIPELINE

Last month, Administrative Law Judge Jeffrey Lee issued a proposed decision denying 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 (which will be considered by the Commission no earlier than November 20) 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.

In response, CRPC has filed a motion to reopen the record, arguing that new evidence undermines key findings in the proposed decision. CRPC points to the City of Antioch’s Second Amended Cross-Complaint in related litigation, which acknowledges that CRPC or an affiliate currently owns or controls the Antioch portion of the pipeline.

CRPC argues that this directly contradicts the PD's conclusion that it lacks ownership and control and says it could not have submitted the new evidence earlier because the cross-complaint was only received after the CPUC deemed the proceeding submitted on October 10, 2025.

INSTANT ANALYSIS: CRPC is making a last-minute push to salvage its CPCN request by introducing evidence that appears to contradict one of the PD's foundational determinations. This is a strategic but narrow play by CRPC: while the new cross-complaint from Antioch supports CRPC’s ownership claims, it does not address the other deficiencies cited in the PD (namely, the absence of valid municipal franchise rights and the cessation of gas deliveries since 2023).

CODA

Please see recent standalone pieces from CRI:

• A seemingly routine electrical upgrade at PG&E's Hinkley Compressor Station has potential to become a test case for how California will handle major gas infrastructure investments as the state moves away from fossil fuels.
• PG&E and SoCalGas/SDG&E filed responses to an Administrative Law Judge ruling in the CPUC's Long-Term Gas Planning docket (R.24-09-012), providing detailed cost and operational data on gas distribution infrastructure (LINK).