Simplifying Policy Management

on Verification of Self-Generation Incentive Program High Total Eligible Project Cost Before Distributing Incentive Payments (Verification ACR) (Mar. 13, 2026). They support the Commission’s goals of ensuring low-income customer access to RSSE funds and addressing TEPC and potential customer out-of-pocket cost concerns.

Key argument: high TEPC does not equal customer costs

Responding to TEPC ACR Q7b, the Joint CCAs argue that TEPC above maximum SGIP incentives does not necessarily mean low-income customers pay $2,000–$11,000 out-of-pocket. CCA partners (notably Haven Energy) have 1,500+ RSSE projects with TEPCs exceeding maximum incentives where customers incurred no out-of-pocket or financing costs. Excess costs were covered by SGIP incentives, ITC, and absorbed by the developer, as shown in customer contracts at the RRF stage.

TEPC verification process and recommendation

While supporting the Verification ACR’s prioritization of pre-February 20, 2026 submissions and eased requirements for low/no out-of-pocket projects, the Joint CCAs note the existing hold on ICF payments harmed vendors and halted installs. They recommend exempting Group A and Group B projects (per Verification ACR OPs 3a and 3b) from additional audit/review when developers demonstrate no customer charges, with immediate approval after PA review of the TEPC verification form to prevent delays, vendor insolvency, and cancellations.

Conclusion

Adopt the Verification ACR process with the proposed narrowly tailored modification to protect vendors and ensure low-income access to RSSE funds.

Supporters of the extension include Public Advocates Office at the CPUC, Environmental Defense Fund, Small Business Utility Advocates, California Solar & Storage Association, Utility Consumers’ Action Network, California Community Choice Association, Clean Coalition, Leap, Universal Devices, Advance Energy United, 350 Bay Area, and the Coalition of California Utility Employees. Interstate Renewable Energy Council, CALSTART, and Renew Home took no position. No parties opposed.

Revised Deadlines and Workshop

• Opening comments due April 20, 2026.
• Reply comments due April 30, 2026.
• Workshop materials for the proposed IOU DER orchestration framework application process due May 8, 2026.
• Workshop rescheduled to May 21, 2026. Additional workshop content and logistics will be provided later.

Guidance and Administrative Details

Parties should use the extended schedule to respond to the March 23 Ruling questions and review other inputs before the May 21 workshop, filing comments and submitting materials by the new dates and following any further CPUC guidance. Ruling issued by ALJ Jack Chang; Docket Office will file. Contact: Jack.chang@cpuc.ca.gov | 415-703-2837.

Last Week's New Comment +1

Introduction and context

IREC submits comments responding to the Assigned Commissioner’s and ALJs’ Ruling (Feb. 6, 2026) and the Track 3 All-Party Workshop Report (Mar. 20, 2026) in R.21-06-017. The All-Party Workshop demonstrated feasibility via PG&E’s Flex Connect; PG&E EPIC pilots, including AMI 2.0 and Cloud Aggregated Management, may close out by the end of 2026.

Overall objective and timeline

The near-term objective is to adopt a territory-wide dynamic flexible connection Standard Offer 1.0 across PG&E, SCE, and SDG&E. The target adoption timeline is PG&E within one year and SCE and SDG&E within two years. Standard Offer 1.0 should generate data and experience to evolve into a long-term tariff.

Utility readiness and pilots

PG&E is the most advanced, with Flex Connect, DERMS integrated with ADMS, and SCADA visibility; it is currently feasible mainly for large EV and BESS sites. SCE is deploying ADMS and DERMS but is behind PG&E. SDG&E is at the proof-of-concept stage. EPIC pilots could expand applicability to single-phase EV customers by the end of 2026.

Stakeholder engagement and procedural steps

• Issue a proposed ruling to solicit comments and adopt Standard Offer 1.0.
• Establish a Flexible Interconnection Working Group immediately and meet monthly for one year.
• Convene a multi-day stakeholder workshop before the end of June to define the offer.
• Require utilities to provide draft offers three months before release and revise them before the CPUC decision.
• Use the CHARGED initiative as a model.

Data, design questions, and costs

The Commission should collect utility, customer, and ratepayer cost-benefit data, including communications and control hardware, DERMS and ADMS, soft costs, and operational, customer, and ratepayer benefits. Key design questions include eligible technologies, connection and interconnection process changes, constraint types, rollout strategy, capacity allocation methods, and metrics. A priority is reducing customer implementation costs through standardization of protocols, gateways, and CEMS.

Medium-term roadmap and tariff goal

After Standard Offer 1.0, the Commission should consider Standard Offer 2.0 and related options, including non-bridging offers and secondary constraints. It should compare IOU DERMS roadmaps to alternative pathways such as aggregators, MoHCA, template envelopes, decentralized AMI control, and LGP/LLP baselines. The goal is to culminate in a dynamic flexible interconnection tariff for all three IOUs within one to two years of initial progress.

implemented.

Track 3 scope and overall approach

• TURN recommends adding two issues to Track 3: revising the RPS Market Price Benchmark calculation to include long-term fixed-price transactions and developing monthly MPB values.
• CLECA urges a comprehensive, data-driven review of PCIA policy and process reforms focused on customer indifference and rate affordability, including possible changes to the RPS MPB calculation and related benchmark methodologies.
• AReM/DACC support addressing all identified Track 3 issues through collaborative workshops and party proposals, organized into parallel sub-tracks so work on one issue does not delay the others.
• PG&E and the other Joint IOUs recommend prioritizing a set of Track 3 issues, including interim reform to the RPS MPB, reform to the Energy Index MPB, re-vintaging standards for utility-owned resources, Slice-of-Day RA-related MPB changes, negative PCIA treatment, and ERRA Trigger reform.
• CalCCA supports a broad Track 3 scope that includes the OIR’s listed issues plus additional structural PCIA and ERRA reforms, including potential changes to benchmarks, cost categories, allocation of energy and attributes, and PCIA sunset concepts.

RPS Market Price Benchmark methodology

• TURN argues the current RPS MPB methodology is too narrow because it relies on short-term PCC1 transaction data and excludes long-term fixed-price agreements, which TURN says are a large part of actual RPS procurement. TURN asks the Commission to revisit the calculation and include long-term fixed-price resources.
• PG&E and the Joint IOUs support interim reform to the RPS MPB and say recent benchmark increases show the need for change, particularly as the current compliance period ends and the market may become more constrained.
• AReM/DACC recommend re-examining whether the RPS benchmark should remain in the PCIA calculation and, if so, whether a published index for PCC1 RECs or another approach would better reflect portfolio value and reduce volatility.
• CalCCA supports reconsidering the RPS benchmark and related PCIA valuation methods as part of broader structural reform, with changes grounded in full data access and analysis.

Monthly versus annual benchmark values

• TURN supports developing monthly MPB values, saying annual values can mask large seasonal differences and create mismatches between benchmark pricing and actual monthly procurement or outage costs.
• PG&E and the Joint IOUs support reform to the Energy Index MPB, which would include better alignment of benchmark values with actual market conditions; their filing does not endorse the same monthly structure proposed by TURN but favors faster refinement of the benchmark approach.

Energy Index MPB and benchmark volatility

• PG&E and the Joint IOUs say the Energy Index MPB has contributed to significant undercollection and should be reformed in Track 3A as an interim priority.
• AReM/DACC state that the current use of data requests has produced questionable RA and RPS MPBs and recommend reviewing alternative data sources, including market indices, to improve accuracy and reduce volatility.
• CLECA supports consideration of modifications to the MPB calculation but emphasizes that any reforms should preserve stability and avoid policy whipsaw effects.

Data access, confidentiality, and verification

• CLECA argues that complex PCIA reforms will require access to commercially sensitive, non-public transaction data and recommends milestones for protective orders or NDAs, along with additional anonymized public data over time.
• CalCCA says broad data access is essential for meaningful participation and asks for a two-phase process in which confidentiality and data access are resolved before substantive proposals are developed, using a protocol modeled on prior PCIA proceedings.
• AReM/DACC support access to the data needed to test and verify proposals, including under NDAs if necessary, and say IOUs should run scenarios when full data cannot be shared.
• PG&E and the Joint IOUs say standard Commission confidentiality and discovery rules should govern unless a narrow, specific exception is justified; if the Commission departs from standard practice, they want a reciprocal non-standard protection framework with defined scope and timelines.

Timing, sequencing, and implementation

• CLECA recommends a deliberate schedule extending through mid-2027 or longer, with prospective and possibly phased implementation to avoid rate shock and allow sufficient analysis.
• CalCCA recommends at least six months after full data production for parties to develop substantive proposals and suggests Track 3 may take one to two years depending on data access and scope.
• AReM/DACC say Track 3 could be completed for implementation in January 2028 and recommend a decision by September 2027 if reporting requirements do not materially change.
• PG&E and the Joint IOUs propose a multi-track schedule beginning in mid-2026, with an expedited Track 3A for interim MPB reforms and a later Track 3B for more comprehensive issues, concluding in early 2028.

RA, vintaging, and other PCIA reforms

• CLECA supports revisiting the bundled/unbundled allocation framework, including the bundling of system, local, and flexible RA into a single MPB, and wants stronger transparency into PCIA calculations.
• AReM/DACC urge a full reconsideration of how RA portfolios are valued in light of Slice-of-Day implementation and also seek clearer rules for re-vintaging utility-owned and purchased-power assets.
• PG&E and the Joint IOUs recommend addressing Slice-of-Day RA valuation, re-vintaging standards for utility-owned resources, and the legal treatment of forecasted negative PCIA rates in Track 3B.
• CalCCA asks Track 3 to consider structural changes such as revised cost categories, GHG-free valuation, additional benchmarks, PCIA sunset concepts, securitization, and better forecasting tools for departing-load customers.

Assessment by a short amount of time.

2028 LOLE Study Schedule Update

The first ruling modifies the schedule for the 2028 LOLE study originally set in the Assigned Commissioner’s Scoping Memo and Ruling. It responds to Energy Division’s notice that the Draft Inputs & Assumptions report will be delayed until April 9, 2026, rather than March 30, 2026.

• Draft Inputs & Assumptions report: by April 9, 2026
• Remote workshop on Draft Inputs & Assumptions: April 14, 2026
• Comments on Draft Inputs & Assumptions: due April 24, 2026
• Final Inputs & Assumptions report, and any alternative Inputs & Assumptions filings by parties: June 5, 2026
• Draft 2028 LOLE studies and PRM proposals: August 14, 2026
• Workshop on LOLE studies: mid-September 2026
• Final 2028 LOLE studies and PRM proposals: October 2026
• Opening and reply comments on LOLE studies and PRM proposals: TBD

Parties are instructed to review the draft Inputs & Assumptions when issued, participate in the April workshop, and meet the revised comment and filing deadlines. The ruling leaves the later comment dates on the LOLE studies and PRM proposals open for future scheduling.

Track 1 Schedule for 2027 LCR and FCR Analysis

The second ruling grants CAISO’s request to adjust the Track 1 schedule after CAISO indicated it could not meet the original April 1, 2026 deadline for the draft 2027 LCR Report. The schedule is changed only in limited ways, with all other dates from the earlier scoping ruling remaining in place.

• Draft 2027 LCR Report: April 3, 2026
• Comments on draft 2027 LCR Report: April 20, 2026
• Final 2027 LCR Report: May 1, 2026
• Comments on final 2027 LCR Report: May 8, 2026
• Reply comments on final 2027 LCR Report: May 13, 2026
• Final 2027 FCR Report: early May 2026
• Comments and reply comments on final 2027 FCR Report: mid-May 2026

Parties are directed to use the revised dates for review and comments on the draft and final LCR report, as well as the final FCR report. The broader Track 1 framework remains unchanged apart from the limited timing adjustment.

Practical Implications for Parties

For both rulings, the main change is procedural timing rather than substantive policy direction. Parties should monitor the revised publication dates, prepare comments on the updated draft reports, and be ready for additional filings later in the year where dates are still to be set.

Last Week's New Comments +8

Overview

This week’s filings in CPUC Rulemaking R25-10-003 continue the same core debate from last week over whether Slice-of-Day (SOD) resource adequacy requirements create transactability problems and whether hourly load obligation trading or related reforms should be adopted. This is a continuation of the discussion from last week, and this digest incorporates both last week’s and this week’s comments. The new filings also add further discussion of market design and implementation questions, including the appropriate evaluation standard for transactability, cost-allocation and PCIA issues, and proposed rules for long-duration storage accreditation. This is a sampling of parties’ positions.

Transactability and Hourly Load Obligation Trading

• Middle River Power LLC (MRP) argues the Transactability Report was limited to assessing whether transactability problems exist after the first year of binding SOD implementation and whether HLOT would be a reasonable response, and says the record does not show a systemic inability to meet hourly requirements using existing procurement and contracting mechanisms.
• MRP says HLOT would create a secondary compliance market that decouples RA obligations from actual load, could misalign incentives, and is not a substitute for physical capacity needed for reliability.
• California Community Choice Association (CalCCA) urges the Commission to adopt hourly LOT within the SOD RA framework, arguing it could reduce ratepayer costs, remove structural market barriers, and reduce reliance on fossil resources.
• CalCCA says the Commission should reject Vistra’s objections and treat LOT as a cost-reducing compliance tool that can be implemented without requiring a full intermediary.
• San Diego Gas & Electric Company (SDG&E) opposes adoption of any hourly load obligation trading mechanism, saying the record does not show a structural transactability problem and that the Energy Division report should be treated as dispositive.
• SDG&E argues that an hourly trading mechanism would let some LSEs lean on others’ procurement without increasing total capacity and would undermine the existing procurement incentive structure.
• Pacific Gas and Electric Company (PG&E) supports the Energy Division finding that SOD has not created material transactability barriers and says LOT would produce only modest, uncertain savings relative to its implementation complexity and risk.
• PG&E recommends postponing any LOT decision until downstream effects are better evaluated, especially impacts on PCIA, RA market benchmarks, and related ratemaking issues.
• Southern California Edison Company (SCE) agrees with Energy Division that market performance should continue to be monitored and says HLOT should be delayed until broader procurement and cost-allocation issues are resolved.
• SCE adds that if HLOT is adopted, IOU participation should be voluntary.
• Forward Market Design LLC (FMD) says the main disagreement in the record is about evaluation standard, with proponents focusing on cost-efficiency and opponents focusing on feasibility, and argues the Commission’s prior decisions support considering whether reliability can be achieved more economically.
• FMD says the evidence shows both the Energy Division and CalCCA agree that limited transactability can increase procurement costs, with the main dispute being the magnitude of those costs.

Cost Savings, Market Design, and Evaluation Standard

• CalCCA says the Energy Division understates the affordability benefits of LOT and argues the Commission should evaluate whether hourly obligations can be met at lower cost, not just whether compliance is technically possible.
• CalCCA cites estimated annual savings from avoided RA purchases and says LOT can improve market efficiency even in a bilateral market.
• PG&E says Energy Division’s savings estimates are reasonable and that CalCCA’s larger savings estimate is less well supported, relying on speculative indirect benefits and broader extrapolation.
• PG&E also supports Energy Division’s approach of using existing market data to estimate potential savings rather than assuming broad systemwide optimization.
• FMD says marginal price is the more relevant basis for estimating compliance costs than a multi-year average transaction price, and argues the existing record can support refined estimates using Energy Division’s model.
• SCE says the benefits claimed for HLOT do not justify the administrative burden, noting that the record shows only limited hourly scarcity value in the simulation evidence presented by CalCCA.
• SDG&E says parties supporting HLOT have not shown with evidence that a structural reform is needed, and that more recent compliance data show SOD did not prevent bilateral market functioning.

Cost Allocation, PCIA, and Other Downstream Impacts

• PG&E warns that CalCCA’s proposal has not fully addressed downstream effects on PCIA ratemaking, revenue allocation, and whether LOT transactions should be treated as retained or unsold capacity for valuation purposes.
• PG&E says these issues could affect bundled and departing-load customers and should be resolved before any reform is adopted.
• PG&E also raises concerns about impacts on RA market price benchmark calculations, IOU approval and prudency processes, and verification of resales and transaction chains.
• SCE similarly says any future HLOT proposal should address cost allocation, RA benchmark impacts, and PCIA issues before adoption.
• SDG&E says an hourly trading product would be available only to LSEs and would undermine procurement incentives created by the existing penalty structure.

Long-Duration Storage Accreditation

• Long Duration Energy Storage Council (LDES Council) urges the Commission to adopt the Joint LDES Parties’ proposal for accrediting long-duration storage under Slice-of-Day, including the use of an initial state of charge assumption and “excess energy” methodology.
• LDES Council says the Joint proposal better reflects how long-duration storage is likely to operate in practice and should be adopted now, with tuning later as operational data develop.
• LDES Council opposes the Cal Advocates approach, arguing it is too restrictive and could understate the charging capability of long-duration storage.
• LDES Council also supports using slack values and prior-day energy assumptions to better represent charging conditions and avoid unnecessary administrative complexity.

Oversight and Intermediary Issues

• CalCCA supports the idea that an intermediary is not required for most of the benefits of LOT, while saying implementation can still be improved through validation and reporting processes.
• FMD says an intermediary could reduce implementation risk and transaction friction, but that most of the benefits of LOT could still be achieved in a bilateral market without one.
• California Solar & Storage Association (CalSSA) did not file in the material provided for this week’s transactability comments.
• SEIA did not file in the material provided for this week’s transactability comments.
• Advanced Energy United did not file in the material provided for this week’s transactability comments.