Simplifying Policy Management

external funding anticipated from U.S. EPA’s Solar for All award was terminated in August 2025 and $33 million previously appropriated to the Commission reverted to the General Fund as part of California’s 2025–2026 Budget Bill. The proceeding A.22-05-022, et al., is closed.

Key factual context and statutory constraints

• D.24-05-065 created the new community renewable energy program subject to later implementation details and envisioned relying on existing PURPA-compliant tariffs (ReMAT and the PURPA Standard Offer Contract) as the cost foundation.
• The U.S. EPA terminated California’s Solar for All award in August 2025; federal tax credits for residential and commercial projects were accelerated by Public Law 119-21 (residential credits end 2025; commercial 2027).
• $33 million that D.24-05-065 contemplated for community renewable energy and storage-backed programs reverted to the General Fund in the 2025–26 budget.
• ReMAT contracts can be up to 20 years; PURPA Standard Offer Contracts allow up to 12 years for new facilities.
• Compensation above PURPA avoided costs would conflict with Pub. Util. Code §769.3(c).
• Increasing maximum project size to 5 MW or lifting statewide capacity caps would require legislative action.
• Resolution E-5367 approved the DAC-GT cost containment cap on July 24, 2025.
• The modified Green Tariff is voluntary and participant-funded; prior oversight mechanisms and reporting requirements (from D.15-01-051 and related orders) are being replaced.
• The Commission directed that program reporting migrate to DGStats (or its successor) as specified in D.24-05-065.

Major conclusions and program guidance

• The Commission adopts a Community Renewable Energy tariff consistent with Pub. Util. Code §769.3(c) and directs each investor-owned utility (IOU) to use its ReMAT tariff as the cost and generation resource foundation for that tariff.
• Community Choice Aggregators (CCAs) participating in the program should align their tariffs with the IOU ReMAT pricing and PPAs for their service territory to minimize impacts on nonparticipating customers. CCAs and Electric Service Providers (ESPs) may begin or end program participation by filing a Tier 1 advice letter notifying the Commission.
• Compensation for Community Renewable Energy projects must not exceed PURPA avoided costs and any external funding proposals must be presented in a Tier 3 advice letter if and when such funds become available.
• Procurement oversight for modified Green Tariff programs may occur through IOU procurement review group (PRG) meetings; cost oversight is to occur via Energy Resource Recovery Account (ERRA) proceedings. The decision discontinues prior requirements for monthly/annual reports, annual forums, and advisory board meetings for IOU Green Tariff programs.
• DAC-GT programs will be funded using public purpose program surcharge collections consistent with Pub. Util. Code §748.5(c); AB 1207 discontinues DAC-GT funding via available GHG allowance proceeds beginning July 1, 2026.
• Program evaluations for DAC-GT and Community Solar Green Tariff (CSGT) programs will proceed consistent with Ordering Paragraph 7 of D.18-06-027; Energy Division will share evaluation results and recommendations within two years of this decision’s issue date.
• The Commission authorizes recovery of costs to implement the D.24-05-065 reporting requirements and directs a transition to DGStats (or successor) for required program reporting.

Specific orders, deadlines, and actions by named parties

• Within 90 days of the issue date (June 11, 2026), Pacific Gas and Electric Company (PG&E), San Diego Gas & Electric Company (SDG&E), and Southern California Edison Company (SCE) must each file a Tier 2 advice letter proposing a new customer Community Renewable Energy tariff consistent with D.24-05-065 and this decision.
• If external funding is later identified, PG&E, SDG&E, and SCE must submit Tier 3 advice letters detailing the external funds, any tariff modifications required to accommodate funding terms, a program implementation and marketing plan, and establishment of a balancing account to record incremental implementation, marketing, and administration costs. The tariff’s costs to nonparticipating customers must not exceed avoided costs (Pub. Util. Code §769.3(c)(3)).
• CCAs and ESPs intending to participate shall notify the Commission via a Tier 1 advice letter when they begin or end participation.
• This decision supersedes specified reporting and meeting requirements in D.15-01-051 (monthly/annual reports, annual forums, advisory groups) for PG&E, SDG&E, and SCE effective the issue date.
• Within 90 days after the issue date, PG&E, SDG&E, and SCE must each file a Tier 2 advice letter modifying their Green Tariff as ordered in D.24-05-065; those filings must include timelines and transition plans for migrating legacy Green Tariff customers to the modified Green Tariff if the Tier 2 advice letters are approved.
• Within 30 days after the issue date, PG&E, SDG&E, and SCE must each file a Tier 1 advice letter to establish balancing accounts to record and recover modified Green Tariff program costs (incremental admin costs, renewable attributes/RECs provided to participants, customer billed revenues, true-ups, and interest).
• Within 60 days after their last Green Tariff customer has migrated, each IOU must file a Tier 2 advice letter to close out Green Tariff memorandum and/or balancing accounts; any undercollections will be handled in the utility’s next ERRA compliance proceeding.
• If no developer executes a ReMAT PPA for a new community renewable energy project within two years after the IOU’s Tier 2 Community Renewable Energy tariff advice letter is disposed, the IOU may discontinue its program via a Tier 1 advice letter.
• Within 30 days after the issue date, PG&E, SDG&E, and SCE must each file a Tier 1 advice letter updating their DAC-GT tariffs to reflect funding via public purpose program surcharge collections; the Community Solar Green Tariff will also continue to be funded via such surcharge collections.
• This decision supersedes Ordering Paragraph 14 of D.24-05-065 for DAC-GT and CSGT program evaluation; evaluations shall follow Ordering Paragraph 7 of D.18-06-027 and results will be shared within two years.
• New CCA DAC-GT programs receiving funds consistent with D.18-06-027 must be implemented via Tier 2 advice letter (supersedes D.18-06-027 Ordering Paragraph 17).
• Within 90 days after DGStats vendor notification that the platform is ready, PG&E, SDG&E, SCE, and other Program Administrators must complete transition of required reporting (DAC-GT, Green Tariff, CSGT, and community renewable energy program data) to DGStats.
• Within 180 days after the issue date, PG&E, SDG&E, and Program Administrators shall execute co-funding agreements with SCE (consistent with Section 5 of the decision) for costs of DGStats integration and data migration.
• Applications A.22-05-022, A.22-05-023, and A.22-05-024 are closed.

Other procedural rulings

All Administrative Law Judge and assigned Commissioner rulings in this proceeding are affirmed; all motions not yet ruled on are denied.

Effective date and signatories

The order is effective June 11, 2026. The decision is signed by CPUC President John Reynolds and Commissioners Karen Douglas and Christine Harada.

Implications and limits

The decision preserves PURPA-based cost constraints (no compensation above avoided costs), requires IOUs to anchor Community Renewable Energy pricing to ReMAT, and leaves larger structural changes (e.g., higher project size limits or statewide cap increases) to the Legislature. It pauses previously expected external funding use pending any future Tier 3 filings, and transitions oversight and public reporting to streamlined mechanisms (ERRA/PRG and DGStats).

LSE procurement to achieve SB 100, SB 2010, and AB 1279 goals while leaving RA and RPS unchanged.

Adopted PSP/TPP portfolios will identify system needs at five, ten, and fifteen years and be tested to LOLE < 0.1 using production cost and RESOLVE modeling.

The ruling focuses on five-year needs quantified as NQC by attribute-based resource categories.

• Annual marginal ELCC studies are published in August when PSP/TPP are adopted, and marginal ELCC converts resources to NQC.
• Penalty studies are published every other August.

Allocation, Compliance, and Enforcement

LSE allocations use the CEC IEPR forecast, typically adopted in January or February, and allocations are posted publicly by the end of March.

LSEs must contract 100% of allocations with contracts of at least 10 years three years after portfolio adoption, and resources must be online five years after adoption.

Compliance filings occur June 1 each year, and the first full procurement compliance deadline is June 1, 2033.

• Example timeline: IEPR/PSP adoption in February 2028; allocations in March 2028; ELCC in August 2028; LSE IRPs due June 1, 2030; contracting due June 1, 2031.

Penalties include net CONE-based penalties for total NQC deficiencies, applied annually over ten years; category shortfalls are penalized using the highest-cost marginal resource; and contracting shortfalls are subject to an administrative-style penalty.

Interaction with DWR/CPE LLT procurement under D.24-08-064 would deduct contracted LLT from LSE obligations.

The proposal assumes CAISO TPP operates on a two-year cycle under FERC Order 1920 and proposes a four-year IRP interval starting June 1, 2030.

June 24, 2026.

Extension Request and Support

On June 24, 2026, PG&E counsel requested a 48-hour extension (to COB Friday, June 26, 2026) citing near-daily coordination, multiple drafts exchanged, and integration of ALJ guidance.

Parties supporting the extension included:

• PG&E
• SCE
• SoCalGas
• SDG&E
• Cal Advocates
• MGRA
• EPUC/IS
• TURN

Small and Multijurisdictional parties were solicited and did not respond.

ALJ Decision and New Deadline

ALJ Thomas granted the request in part. The filing deadline is extended from 5:00 PT on June 24, 2026 to 5:00 PT on Friday, June 26, 2026 (COB). The Docket Office is directed to file the Ruling.

Expectations and Administrative Details

Parties must continue near-daily coordination and further integrate guidance from the OIR and the PHC into any joint proposal. By 5:00 PT on June 26, 2026, parties should file the agreed joint schedule and specific recommendations on workshop format, scope, timing, and roles.

Issued by Sarah R. Thomas, Esq.; contact sr@cpuc.ca.gov; 415-703-2310.

Last Week's New Comment +1

Proceeding context and participants

This filing responds to ALJ Sarah Thomas’s June 17, 2026 oral ruling and presents a joint compromise schedule and workshop recommendations for Rulemaking 26-04-016 (Risk OIR). Filers: PG&E (on behalf of PG&E, SCE, SoCalGas, SDG&E), Cal Advocates, MGRA, EPUC/IS, and TURN. Parties met June 18, 22, 23, 24, and 25 to narrow differences on sequencing Risk Tolerance and Risk Scaling.

Agreements and core dispute

Parties jointly support Phase 1 and Phase 2 schedules. Dispute centers on sequencing Risk Tolerance and Risk Scaling, yielding two alternatives:

• Alternative 1 (IOU-supported): Risk Tolerance first, Risk Scaling second.
• Alternative 2 (MGRA, Cal Advocates, EPUC/IS, TURN-supported): Risk Scaling first, Risk Tolerance second.

Key party positions and timing constraints

PG&E and other IOUs want Risk Tolerance prioritized to inform PG&E’s 2028 RAMP and would place Risk Scaling in Q3 2027 after PG&E’s expected May 2027 GRC decision. TURN prefers Risk Scaling in Q2 2027 (target decision Oct 2027) or excludes Risk Tolerance entirely. MGRA and Cal Advocates favor Scaling before Tolerance to align 2028 RAMP and Electrical Undergrounding Plans, but warn against starting Scaling before A.26-02-005 and A.25-05-009 decisions. EPUC/IS support Scaling-first but insist Risk Tolerance be addressed.

Agreed Phase schedules and targets

Phase 1 (Q4 2026): SMJU Reporting, SB 254, RAMP — staff proposals Oct 16 and Sept 25, workshops Nov 2/Oct 9, comments Nov 13–20/Oct 23–Nov 6; target final decision January 2027. Phase 2 (Q1 2027): BCR refinements — staff proposal Feb 1, workshops Feb 8–15, comments Mar 15/29; target final decision June 2027.

Workshops

Recommend 48-hour advance materials, Q&A time, conduct rules, recording/transcription (clarify AI transcripts), neutral moderation, and a mechanism to move materials into the evidentiary record.

incorporates both last week’s and this week’s comments.

Core dispute over valuation and customer indifference

• CalCCA argues that Pre-2019 Banked RECs have deferred RPS compliance value that should be recognized when IOUs actually use them for bundled-customer compliance, and that a $0 valuation causes cost shifts to Later Departing Customers who helped fund those RECs.
• The Joint IOUs maintain that Pre-2019 Banked RECs should remain valued at zero for PCIA purposes, arguing that CalCCA has not shown a present-day cost shift or a legal entitlement for Later Departing Customers to receive separate compensation.
• AReM/DACC supports recognizing non-zero value for pre-2019 banked RECs, saying the RECs have tangible compliance value when used and that valuing that benefit is consistent with the indifference standard.

Legal theory, burden of proof, and scope of Track 2

• CalCCA says Track 2 was specifically opened to resolve the unresolved treatment of Pre-2019 Banked RECs, that prior interim treatments do not control, and that the Commission may adopt a different approach if it gives a reasoned explanation under the indifference statutes.
• The Joint IOUs argue that CalCCA is seeking to reopen settled ratemaking outcomes, that prior decisions and workgroup processes already addressed REC disposition, and that CalCCA has not met its burden to justify changing the existing zero-value approach.
• AReM/DACC says the PCIA framework is designed to implement statutory indifference through allocation of above-market costs and does not prevent assigning value to the RPS component of banked RECs.

Proposed valuation methods

• CalCCA proposes valuing Pre-2019 Banked RECs at the RPS market price benchmark when they are used for bundled compliance, with the value credited back to the vintage year in which the RECs were generated through the existing PCIA vintaging tool.
• CalCCA also proposes a fallback 90/10 composite valuation and, if needed, an allocation approach using offsetting entries in compliance reporting.
• The Joint IOUs reject CalCCA’s RPS MPB approach and continue to favor a zero-dollar value; if a non-zero value is adopted, they support a modified Staff Proposal 4 and say any unbundled portion should be benchmarked to PCC-3 rather than the RPS MPB.
• AReM/DACC opposes creating an additional PCC-3-based benchmark, saying it would add complexity without necessity and that existing PCIA price separation is sufficient to evaluate the REC value issue.

Allocation mechanics and treatment of customer cohorts

• CalCCA says benefits should be allocated by vintage so Later Departing Customers receive a fair share of the value they helped fund, and it offers an alternative involving offsetting entries tied to RPS compliance reporting templates.
• The Joint IOUs argue the PCIA methodology does not provide for separate payments to subgroups such as Later Departing Customers and say CalCCA’s approach would improperly require bundled customers to compensate a narrow class of former customers.
• AReM/DACC says the central issue is proper allocation of REC value, not whether a separate subgroup payment is conventional, and argues that correcting prior cost shifts is consistent with indifference.

Market effects, affordability, and implementation

• CalCCA disputes claims of major market harm, arguing the REC market is oversupplied, price impacts would be limited, and implementation can be handled through existing PCIA, ERRA, and reporting processes.
• The Joint IOUs say a non-zero valuation would raise bundled-customer costs, distort procurement incentives, and could create stranded resources and other downstream harms.
• AReM/DACC characterizes those warnings as speculative and inconsistent, and says if banked RECs truly have zero value, they should not also be able to reduce procurement obligations.

Timeliness and earlier proceedings

• CalCCA says no cognizable harm arose until the IOUs began using Pre-2019 Banked RECs for current bundled RPS compliance, and it argues that prior zero valuations were expressly interim and preserved for this rulemaking.
• The Joint IOUs respond that CalCCA and other CCAs waited too long to challenge the treatment of these RECs, pointing to earlier workgroup participation and arguing laches and prejudice weigh against relief.

Joint Parties sought to move Opening Comments from June 26, 2026 to July 15, 2026 and Reply Comments from July 3, 2026 to July 22, 2026.

Decision and adopted schedule

The Commission denied the longer schedule proposed by the Joint Parties and instead granted a shortened extension. New deadlines are:

• Opening Comments due July 6, 2026, revising the June 26, 2026 deadline
• Reply Comments due July 13, 2026, revising the July 3, 2026 deadline

Procedural basis and instructions

The ruling was issued under Rule 11.6. Parties must file Opening and Reply Comments responding to the June 12, 2026 Ruling on the Data Working Group Final Report according to the revised deadlines. No other procedural changes were made; the ruling documents denial of the longer extension and sets the new comment schedule.

Dated June 22, 2026, San Francisco, California.

Last Week's New Comments +6

R.22-11-013: Sample Update on 2026 ACC Comments

This is a sampling of parties’ positions on the revised 2026 Avoided Cost Calculator (ACC) staff proposal in CPUC Rulemaking 22-11-013. This week’s filings continue last week’s discussion of the Integrated Calculation, GHG avoided costs, and transparency, and add more detailed arguments about how the GHG cap should be applied, whether the capacity calculation should be tied to IRP shadow prices, and how the hybrid resource assumptions should be structured. This digest incorporates both last week’s and this week’s comments.

Integrated Calculation design and the role of GHG shadow prices

• SCE supports the revised Integrated Calculation framework and says it should remain aligned with IRP/RESOLVE inputs, while retaining a GHG avoided cost cap to protect customers from premature or unsupported GHG assumptions.
• PG&E supports the revised Integrated Calculation and views the use of IRP-derived GHG shadow prices as a helpful step toward greater alignment across proceedings, while also cautioning that capacity outputs should be checked for consistency.
• SEIA supports the simplified Integrated Calculation, but opposes using an undefined Commission discretion standard to substitute IRP capacity shadow prices when the two methods diverge; SEIA says the IC and RESOLVE serve different purposes and should not be expected to match exactly.
• CLECA does not support the revised Integrated Calculation as proposed, arguing that it is not truly technology-agnostic, relies on unstable exogenous assumptions, and effectively turns the IC into a residual calculation that undervalues generation capacity.
• SoCalGas supports aligning electric and gas GHG avoided costs on an interim basis and supports moving the IC to Excel for transparency, provided the Excel version preserves the core functionality and accuracy of the Python model.

GHG cap placement and calibration

• SEIA opposes applying a GHG cap after the Integrated Calculation, saying any cap should be addressed in the IRP process first and, if used in ACC, should be applied before the GHG value is fed into the IC.
• PG&E agrees that any avoided GHG cap should be applied before the ACC model is run, rather than as a post hoc adjustment to final outputs.
• SCE supports retaining the staff-proposed GHG cap and says it should be applied to the IC outputs as a post-processing measure to prevent the ACC from reflecting unusually high or unsettled GHG values.
• CLECA says the GHG cap must be applied within the Integrated Calculation, not outside it, and further argues that the cap should be set no higher than the Base social cost of carbon.
• SEIA and CLECA both argue that post-processing the cap can suppress generation capacity values and distort cost recovery, though they differ on the best remedy.
• SCE rejects the argument that the Commission’s recent IRP approval automatically endorses those same GHG shadow prices for ACC use, and says the ACC should not import higher shadow prices before broader policy processes are complete.

Generation capacity values, resource mix, and hybrid assumptions

• CLECA argues the revised model still undervalues generation capacity, including for resources relied on by large industrial customers, and says the model should use a diverse IRP-representative resource mix rather than a single fixed solar-plus-storage hybrid.
• SEIA agrees that the single hybrid structure is problematic because it can mask under-recovery for standalone solar or storage resources, and recommends expanding the resource panel to include additional IRP-selected resources.
• SCE supports the hybrid-based IC structure and argues that the capacity result should be aligned more closely with IRP/RESOLVE signals; it also says Energy Division should be able to rely on IRP capacity shadow prices if the ACC result diverges materially.
• PG&E supports using IRP shadow prices as a consistency check for ACC generation capacity values, while warning that capacity and GHG outputs should not be assumed to move identically.
• SoCalGas says it has no detailed substantive position on the capacity calculation at this time beyond supporting the overall move toward greater transparency.

Floor values, smoothing, and treatment of volatility

• CLECA says the floor for avoided generation capacity remains too low and supports raising it at least to reflect taxes and insurance for the marginal gas plant, with a broader future update tied to IRP resource costs.
• SEIA also supports raising the floor to reflect updated going-forward O&M costs and says the current hybrid-based approach can leave standalone resources unable to fully recover costs in some years.
• CLECA supports smoothing the calculated generation capacity values over a longer window, and recommends adopting a ten-year smoothing period rather than the shorter window in the Revised Proposal.
• SCE says generation capacity values should also be smoothed to reduce volatility and better align ACC outputs with longer-term resource planning.
• SEIA supports addressing volatility and says the methodology should better reflect step changes in resource economics rather than relying on a narrow hybrid assumption.

Hourly marginal resource and avoided emissions assumptions

• PG&E says the Commission should review the hourly avoided-emissions assumptions and ensure the model only treats emitting resources as marginal in appropriate hours.
• CLECA argues the hourly avoided-emissions method can overstate GHG avoided costs by assuming gas is on the margin when it often may not be, and says the methodology should be revised to identify the actual marginal resource hour by hour.
• SCE does not accept CLECA’s critique as a basis to eliminate the GHG cap, but says the ACC should remain conservative until broader policy processes resolve the underlying questions.

Transparency and further process

• CLECA says stakeholders need to see both smoothed and unsmoothed values, as well as pre- and post-cap outputs, to understand how the revised methodology affects results.
• PG&E and SoCalGas both support greater transparency in the model and continued stakeholder review, with SoCalGas specifically supporting the Excel transition so long as accuracy is preserved.
• SEIA and CLECA both call for additional review if the Commission expands the IC resource mix or changes how the cap is applied.
• SCE says the Commission should adopt a clear, customer-protective approach now and continue to evaluate broader methodology questions in the appropriate policy venues.

products should be subject to zero-dollar bidding and revenue-allocation rules.

Energy-only resources and charging sufficiency

• California Independent System Operator Corporation (CAISO) supports deferring broader energy-only eligibility for storage charging sufficiency pending CAISO analysis and says co-located energy-only support should remain limited and subject to safeguards.
• Pacific Gas and Electric Company (PG&E) supports adding an Energy Division study of qualifying capacity treatment for solar and wind energy-only resources, while also supporting only a narrow interim rule for co-located energy-only charging value.
• Southern California Edison Company (SCE) supports counting excess energy from co-located energy-only resources toward charging sufficiency up to the point-of-interconnection limit, but says the accounting should be tied to the energy-only resource, not the storage resource.
• California Community Choice Association (CalCCA) supports broader changes to charging sufficiency rules, including allowing geographically paired energy-only and storage resources to count together under an expanded framework.
• Solar Energy Industries Association (SEIA) opposes deferring the issue entirely and urges a clearer path for evaluating and expanding energy-only eligibility, including use of CAISO’s 2026 TPP process.
• American Clean Power – California urges faster expansion of energy-only and energy-storage eligibility, with clearer calculation rules and a near-term framework for standalone energy-only resources to count toward charging sufficiency.
• REV Renewables LLC supports allowing energy-only resources to count toward storage charging sufficiency, or at least setting an expedited timeline to revisit the issue.
• NextEra Energy Resources, LLC supports counting co-located energy-only solar toward charging sufficiency and says the excess output should be credited after battery charging needs are met.
• ENGIE North America, Inc. supports a broader interim geographic footprint for energy-only eligibility than the proposed decision adopts and asks for a clear procedural path if additional CAISO analysis is needed.
• EDF power solutions says the proposed decision relies too heavily on a CAISO study that is not yet clearly scoped and supports broader interim eligibility or a timebound process to resolve the issue.
• California Energy Storage Alliance (CESA) supports broader interim energy-only eligibility and says the record supports including standalone energy-only resources, not just co-located resources.
• Alliance for Retail Energy Markets (AREM) supports broader treatment of energy-only resources in the charging sufficiency context and favors flexible commercial arrangements rather than rigid location-based limits.

Long-duration storage, charging sufficiency, and state of charge assumptions

• Form Energy, Inc. supports the proposed long-duration storage framework in principle but says the charging sufficiency design is too conservative, especially the use of a worst-day-only approach and a zero initial state of charge assumption.
• Hydrostor, Inc. supports the long-duration storage definition and forward charging period concept, but argues the proposed decision understates available charging energy and should adopt a higher interim initial state of charge proxy.
• Southern California Edison Company (SCE) supports a simpler, more conservative long-duration storage multiplier approach and says the proposed decision should avoid over-accrediting long-duration storage.
• California Energy Storage Alliance (CESA) supports the long-duration storage framework but argues the initial state of charge assumption should be higher than zero and that the record supports using energy available before the worst day.
• Vistra Corp. supports long-duration storage treatment but asks the Commission to clarify the forward charging period multiplier and its interaction with round-trip efficiency and continuous-hour duration.
• Cal Advocates/M.Miley/CPUC supports the blended long-duration storage compromise in the proposed decision but asks for clarification of the charging methodology and reporting.

Storage qualifying capacity, foldback, and UCAP

• California Independent System Operator Corporation (CAISO) supports the proposed storage qualifying capacity clarifications and says CAISO can coordinate implementation changes for storage nonlinearity and foldback.
• Pacific Gas and Electric Company (PG&E) supports incorporating foldback into storage qualifying capacity but asks for implementation to begin with the 2027 compliance year rather than immediately.
• Southern California Edison Company (SCE) supports reflecting foldback in storage qualifying capacity and wants CAISO and Energy Division to coordinate the calculation details to avoid inconsistent treatment.
• California Community Choice Association (CalCCA) asks for hourly variability in storage qualifying capacity so the resource can better align with slice-of-day needs.
• American Clean Power – California supports accounting for foldback and says CPUC should coordinate closely with CAISO to avoid double-penalizing storage for the same physical limitation.
• California Energy Storage Alliance (CESA) says foldback should be reflected in qualifying capacity, not treated as a forced outage in EFORd, and warns against double counting.
• ENGIE North America, Inc. argues foldback is a known physical characteristic and should be handled through qualifying capacity, not EFORd.
• Calpine LLC, Hydrostor, Inc., Terra-Gen, LLC, Vistra Corp., and Middle River Power LLC all raise implementation concerns about how foldback or nonlinearity is treated in UCAP and want clearer rules to avoid double counting or misapplication.

UCAP implementation, outages, and must-offer obligations

• California Independent System Operator Corporation (CAISO) supports adopting UCAP in 2028 and says unresolved implementation issues can be handled in parallel.
• Pacific Gas and Electric Company (PG&E) recommends delaying UCAP’s first compliance year to 2030 and using 2028–2029 as transition years.
• Southern California Edison Company (SCE) supports UCAP beginning in 2028 but wants the period treated as a non-binding test year with binding compliance starting in 2029.
• San Diego Gas & Electric Company (SDG&E) supports UCAP but also prefers a 2028 non-binding test year and 2029 binding implementation.
• Vistra Corp. supports UCAP for 2028 but wants it limited to System RA, with key implementation issues resolved in Track 2 and with Pmax capped at deliverable output.
• Middle River Power LLC wants Pmax retained as the must-offer obligation for UCAP resources and asks for exclusion of certain gas-curtailment outage codes from UCAP.
• Independent Energy Producers Association (IEP) asks that outage codes outside a generator’s control be excluded from UCAP calculations.
• California Energy Storage Alliance (CESA) and ENGIE North America, Inc. both say forced-outage accounting should not capture known, deterministic limits like foldback or other design characteristics.
• Calpine LLC seeks a refined UCAP approach for interdependent units, while Terra-Gen, LLC and Hydrostor, Inc. ask for clearer UCAP treatment for hybrids and storage-specific accounting.

Imbalance Reserve and Reliability Capacity products, zero-dollar bids, and revenue allocation

• California Independent System Operator Corporation (CAISO) opposes applying zero-dollar bid rules and revenue-return requirements to Imbalance Reserve and Reliability Capacity products and says economic bidding should be allowed under the CAISO tariff.
• Pacific Gas and Electric Company (PG&E) opposes the zero-dollar bid requirement for Imbalance Reserve products and says the Commission should not force recovery of IR revenues under existing contracts at any cost.
• Southern California Edison Company (SCE) supports future-contract treatment for these products but opposes retroactive application to existing contracts and wants only the capacity-related portion of IR revenues assigned to the RA buyer.
• California Community Choice Association (CalCCA) opposes the zero-dollar bid and revenue-allocation requirements for IR and RC and says the Commission should preserve contractual flexibility.
• San Diego Gas & Electric Company (SDG&E) also opposes zero-dollar bidding for IR and RC and requests prospective-only treatment of any new contracting rules.
• Western Power Trading Forum (WPTF), Independent Energy Producers Association (IEP), Calpine LLC, Hydrostor, Inc., Vistra Corp., Terra-Gen, LLC, REV Renewables LLC, Middle River Power LLC, American Clean Power – California, California Energy Storage Alliance (CESA), and EDF power solutions all argue that IR is not a traditional RA capacity product and should not be subject to zero-dollar bid or mandatory revenue-diversion rules.
• Cal Advocates/M.Miley/CPUC takes a narrower approach, supporting reporting and monitoring changes while asking for gross-cost reporting and a correction to the ordering paragraph covering DAME metrics.

Existing contracts and prospective application

• Pacific Gas and Electric Company (PG&E), Southern California Edison Company (SCE), San Diego Gas & Electric Company (SDG&E), Vistra Corp., Calpine LLC, and American Clean Power – California all ask the Commission to make any new DAME or revenue-allocation rules prospective only and not retroactive to existing contracts.
• California Community Choice Association (CalCCA) and California Energy Storage Alliance (CESA) similarly caution against forcing contract renegotiation and prefer contract terms to remain subject to bilateral agreement where possible.

Data centers and large load forecasting

• City of San José urges the Commission to adopt a milestone-based process for assigning RA obligations to data center load, rather than relying only on broad forecasting or interconnection status.
• California Community Choice Association (CalCCA) supports a durable data center RA allocation process and says the proposed meet-and-confer process is not enough on its own.

Hourly load obligation trading and local procurement transparency

• California Community Choice Association (CalCCA) supports adopting hourly load obligation trading as a way to better match hourly RA obligations with procurement.
• San Diego Gas & Electric Company (SDG&E) opposes hourly load obligation trading and asks that it be denied with prejudice.
• CEJA and Sierra Club call for greater transparency around local procurement needs, coordination with IRP and CAISO, and a public-facing tracker for charging limits and local resource planning.

Other implementation and reporting issues

• Cal Advocates/M.Miley/CPUC asks for gross-cost reporting for Imbalance Reserve and Reliability Capacity products and a fix to the ordering paragraph that omits one of the DAME revenue items.
• Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (SCE) both request clarifications on reporting requirements and large-load information sharing.
• Western Power Trading Forum (WPTF) asks for a structured Track 2 process to resolve UCAP implementation details.
• NextEra Energy Resources, LLC asks for an interim attestation-based verification approach for energy-only charging sufficiency and better CPUC-CAISO alignment on UCAP implementation.
• Middle River Power LLC requests a more explicit process for resolving UCAP open items and alignment of UCAP values with LOLE timing.