Simplifying Policy Management

proposal by March 27, 2026.

Staff Report and Record

The Staff Report, prepared by Energy Division, analyzes recommendations from opening and reply testimony and proposes four valuation methodologies for Commission consideration. The Amended Scoping Memo directed parties to file opening and reply comments on the Staff Report concurrently with opening and reply briefs.

Deadlines and Filing Instructions

• Opening comments on the Staff Report are due with opening briefs on May 22, 2026.
• Reply comments on the Staff Report are due with reply briefs on June 5, 2026.

Questions for Parties

Parties must address whether the Commission should adopt, revise, or reject components of the Staff Report using Track Two issues as a framework, and answer specific questions about accuracy of Staff characterizations; which ED Staff proposals, if any, capture value of Pre-2019 Banked RECs for PCIA; potential modifications to proposed methodologies; and whether proposals address impacts on RPS compliance and LSE procurement strategies, including the availability of compliance deferrals.

Ruling

Notice is given of Attachment A; filing deadlines are May 22, 2026 and June 5, 2026.

Integrated Resource Planning (IRP) process, and provide comprehensive quantitative and narrative assessments of procurement strategies, project development, risk mitigation, costs, and system reliability through 2036. These requirements enable the Commission to review, accept, modify, or reject proposed plans, ensure prudent and reliable procurement, and fulfill legislative reporting and oversight obligations.

Background

This proceeding was initiated by the California Public Utilities Commission (CPUC) under Public Utilities Code §399.13(a)(1) to review and approve the 2026 Renewables Portfolio Standard (RPS) Procurement Plans of all retail sellers, including investor-owned utilities, community choice aggregators, and electric service providers. It implements statutory requirements such as SB 100 and SB 1174, and aligns RPS planning with the Integrated Resource Planning (IRP) process and the state’s clean energy goals. The proceeding streamlines and standardizes filing requirements, reporting templates, and data submissions, including cost and transmission reporting, to ensure consistency and compliance. Retail sellers must address risk mitigation, project development, procurement strategies, and provide both public and confidential plan versions for Commission review. The CPUC will review, modify, or approve these plans on a set schedule, supporting legislative reporting and oversight of California’s renewable energy targets.

(Aug. 11, 2023) and the FGS Report (Gridworks, 2024), the Ruling prioritizes five areas:

• DER Visibility to DSO
• DER Visibility to CAISO
• DER dispatchability/control
• Open access to distribution system
• Reliability coordination at the T&D interface

The framework centers on DSO-led orchestration to enable DER flexibility for reliability, outage mitigation, infrastructure deferral, and electrification while preserving open access.

Proposed Framework and Next Steps

Orchestration is is defined as coordinated DSO management of DERs using visibility, forecasting, and control. Initial steps include:

• Develop cost-effective service models
• Advance interoperable communications
• Enable DER visibility to CAISO and DSO–CAISO coordination
• Evaluate compensation options
• Define performance metrics
• Identify pilot locations

Two Commission-led workshops precede IOU-specific applications; a joint workshop with CAISO will address TSO-DSO coordination and CAISO visibility.

Other Key Procedural Items

Questions for parties span objectives, valuation frameworks, guiding principles, SSM, interoperability, ADMS/DERMS readiness, phased implementation, aggregator participation, and cost-benefit methods. The Ruling asks whether ICA quarterly workshops should shift to biannual timing and proposes Appendix A as a standardized format for IOU biennial Grid Modernization Reports; the next statewide GMR is due Feb. 1, 2027.

at no upfront cost. Over 175 CPA low-income customers pursue RSSE-funded systems through CPA’s SBAP developer.

Support and Concerns

CPA supports Commission goals to limit unusually high RSSE TEPCs and protect customers from out-of-pocket costs. CPA appreciates clarifications in the Mar. 13 ACR and expedited procedures but urges narrowly tailored verification processes to avoid penalizing good-faith applicants or causing project delays/cancellations.

Key Issues and Recommendations

• Data: D.24-03-071 maximum incentives and reliance on Energy Sage averages may not reflect RSSE-targeted customer cost variability; the storage incentive was set at the lower end of suggested levels. CPA recommends broader market data.
• Funding gap: CPA confirms SBAP customers pay no upfront costs; CPA’s contracted developer finances gaps between TEPC and SGIP incentives/tax credits.
• Verification timelines: require PAs to verify TEPC within one week for RSSE projects with TEPC at 90–100% of max SGIP incentive, and within two weeks for TEPC above 100% to allow additional review.
• Penalties and cure: define “consistently overstated” narrowly (intentional/fraudulent only) and implement a cure period to remedy unintentional errors; avoid automatic cancellation of unrelated projects.

Conclusion

CPA asks the Commission to adopt these deadlines, narrow penalty definitions, and a cure process to protect SGIP funds while preserving timely low-income customer access.

Capacity (UCAP) design, timing, and alignment with CAISO; local RA tools such as the LCR‑RCM and transparency; treatment of data center load; and bidding/revenue rules for EDAM-related products. This is a sampling of parties’ positions.

Energy-Only Resources and Charging Sufficiency

• Ava Community Energy (Ava) supports moving now to recognize EO resources for charging sufficiency, arguing CAISO’s future TPP study should not delay action and at minimum asking the Commission to allow CalCCA’s proposal for EO resources co-located with fully deliverable resources behind a single POI, with combined operation capped at POI deliverability.
• CalCCA urges adoption of its EO proposal without waiting for CAISO’s TPP, limiting EO counting to capacity co-located at deliverable POIs and within POI deliverability limits to mitigate deliverability concerns.
• SCE recommends adopting only its limited, “studied” EO approach in Track 1—allowing EO energy behind a deliverable POI to count for charging sufficiency within that POI’s deliverability limit—and deferring broader EO proposals until after CAISO completes its off-peak deliverability study.
• Cal Advocates/M.Miley/CPUC (Cal Advocates) does not change its previously stated skepticism toward broad EO use, instead emphasizing the need for conservative energy sufficiency assumptions and maintaining the SOD requirement that LSEs explicitly account for charging energy.
• GreenGenStorage, LLC (GreenGen) supports allowing EO resources to satisfy charging sufficiency under SOD and, while endorsing CAISO’s broader study of EO deliverability, urges near-term adoption of narrower, low-risk EO reforms such as POI-bounded co-location proposals from CalCCA and SCE.
• Middle River Power LLC (MRP) strongly supports deferring any EO charging sufficiency reforms until CAISO’s 2026‑2027 TPP deliverability analysis is complete, arguing that location- and time-specific congestion information is needed before changing EO treatment.
• Calpine LLC (Calpine) is open to limited EO use for charging sufficiency but recommends waiting for CAISO’s deliverability analysis before modifying EO treatment in the RA program.
• Sierra Club (with CEJA) urges the Commission to include EO resources in the RA program at least for charging sufficiency in Track 1, particularly co-located EO resources using POI‑based deliverability checks, and opposes deferral to Track 2 or to CAISO studies.
• American Clean Power – California (ACP‑California) supports broadening EO eligibility for charging sufficiency, urges the Commission to signal near-term intent to adopt an actionable EO‑ES framework by the 2028 RA year, and supports CAISO’s deliverability study as an input but not a reason to delay program design.
• Alliance for Retail Energy Markets (AReM) supports allowing EO resources to supply battery charging sufficiency beginning in the 2028 compliance year but only after CAISO’s transmission studies on off-peak charging are available to inform the design.
• NextEra Energy Resources (NextEra) continues to support prompt EO‑based charging sufficiency reforms (from prior filings), warning of potential stranding of large quantities of EO solar and storage if EO contributions remain unrecognized.

Long-Duration and Multi-Day Storage (LDES/MDS) Accreditation

• Cal Advocates supports adoption of its Multi-Day Energy Sufficiency Requirement (MDESR) proposal, which allows LDES/MDS to count for up to 24 SOD slices if LSEs show realistic pre‑worst‑day charging capability, incorporates an MCDD parameter for future multi-day dispatch orders, and assumes zero initial state of charge to ensure charging energy is fully accounted for.
• Ava Community Energy (Ava) backs moving toward recognition of pre‑peak charging for LDES in RA accreditation, supports a single seven‑day Forward Charging Period (FCP) aligned with CAISO’s extreme weather practices, endorses a simplified monthly “slack value” method to represent pre‑ and post‑peak demand margins, and opposes adopting an MCDD requirement at this time based on its empirical analysis.
• GreenGenStorage, LLC (GreenGen) finds Cal Advocates’ MDESR assumptions overly restrictive, urges rejection of worst-day-based charging sufficiency constructs, and supports the Joint LDES Parties’ approach as better reflecting LDES operational capabilities; it also argues open‑loop PSH with non‑grid charging should not be subject to the same SOD charging sufficiency rules as grid‑charged LDES.
• CalCCA urges the Commission to reject Cal Advocates’ LDES counting approach as unrealistic and likely to underestimate charging capability, and indicates support for alternatives (such as Joint LDES Parties’ proposals) that better reflect multi‑day operational characteristics.
• SCE identifies adoption of an MDESR framework as a Track 1 priority, supports Cal Advocates’ general direction more than competing LDES proposals, and argues that storage non‑linearity and foldback effects should be captured in QC rather than UCAP to avoid double derating.
• Alliance for Retail Energy Markets (AReM) recommends that the Commission and CAISO conduct stochastic modeling of multi‑day storage before selecting a technology‑neutral valuation methodology, objects to unsupported assumptions such as a 50% initial SOC, and calls for consistent treatment across multi‑day storage technologies, including requiring open‑loop PSH to show charging sufficiency.
• American Clean Power – California (ACP‑California) supports LDES methodologies (e.g., Joint LDES Parties’ approach) that recognize multi‑day charging and discharging in a way that aligns with IRP modeling and helps meet significant near‑term reliability and procurement needs.
• NextEra Energy Resources (NextEra) continues to back LDES accreditation frameworks that recognize multi‑day contributions and cautions that overly conservative assumptions, like those in MDESR, could undermine development of advanced storage resources needed to meet IRP targets.

UCAP Design, Timing, and Alignment with CAISO

• SCE supports implementing a resource-specific UCAP framework for the 2028 compliance year with an accompanying UCAP‑to‑PRM translation, a technology-neutral forced‑outage standard, clear data validation and refresh processes, limited and temporary use of class-average UCAP values, and treatment of storage foldback in QC rather than UCAP.
• Calpine LLC (Calpine) supports UCAP in principle but favors a phased implementation with additional OMS data validation and indicative UCAP/PRM values in 2028–2029, leading to binding UCAP in 2030, and advocates applying the same “best 3‑in‑4 years” UCAP performance methodology to gas units as to other technologies.
• Alliance for Retail Energy Markets (AReM) emphasizes the need for CPUC–CAISO alignment on UCAP implementation to avoid dual PRMs and conflicting compliance regimes, supports using UCAP for both Commission SOD compliance and CAISO RA validation while keeping must-offer obligations at Pmax, and endorses facility-level UCAP treatment for interdependent plants like Calpine’s Geysers.
• Ava Community Energy (Ava) supports Energy Division’s focus on unit-specific UCAP values, opposes class-average UCAP implementation because it would distort incentives, and is willing to accept limited delay only if data quality constraints make immediate unit-level UCAP infeasible.
• GreenGenStorage, LLC (GreenGen) generally supports adopting UCAP to assign forced‑outage risk to individual resources, stresses coordination with CAISO’s RAAIM and RAMPD initiatives to avoid duplicative or conflicting incentives, and calls for transparent, technology‑appropriate provisional UCAP treatment for new or data‑limited technologies with a clear path to resource-specific values.
• Middle River Power LLC (MRP) urges deferral of UCAP implementation beyond 2028 until methodological, data, and policy issues are resolved (including hybrid treatment, force‑majeure exclusions, and reset methods), and supports Vistra’s concept of maintaining separate ICAP-based QC values and PRMs for CAISO operations alongside UCAP-based values for CPUC SOD compliance.
• CalCCA opposes exemptions from UCAP for existing long‑term contracted resources (such as Hydrostor’s request), arguing UCAP should apply uniformly so reliability contributions are accurately represented and PRM is not inflated.
• American Clean Power – California (ACP‑California) supports UCAP in concept but focuses on ensuring it is calibrated within the broader RA accreditation framework and coordinated with CAISO market rules so as not to send conflicting performance signals or over‑penalize new technologies.
• Sierra Club (with CEJA) continues to advocate that UCAP design should avoid over‑crediting fossil units and should reflect performance under cycling and extreme-event conditions, while preserving Commission discretion to balance costs, reliability, and environmental goals.

Planning Reserve Margin (PRM), LOLE Standard, and Reliability Target

• Middle River Power LLC (MRP) supports adopting CAISO’s proposal to set RA requirements explicitly to meet a 0.1 LOLE standard, with an LOLE study and seasonal PRM values for 2028–2029, and opposes approaches that merely “target” 0.1 LOLE without binding PRM calibration.
• Sierra Club (with CEJA) opposes mandating a strict 0.1 LOLE requirement, supports Cal Advocates’ view that the Commission must retain discretion under Public Utilities Code §380 to balance reliability with affordability and environmental objectives, and cites prior Commission decisions rejecting a hard 1‑in‑10 standard.
• SCE supports translating UCAP-based accreditation into a commensurate PRM so that system RA requirements are directly aligned with resource-specific availability, but does not in these comments take a separate position on a mandatory 0.1 LOLE standard.
• Alliance for Retail Energy Markets (AReM) calls for additional stochastic analysis—particularly around multi‑day storage—before locking in PRM decisions that purport to meet 0.1 LOLE, to ensure the adopted standard is analytically supported across resource mixes.
• Cal Advocates/M.Miley/CPUC (Cal Advocates) maintains that while reliability analysis should inform PRM, the Commission should not be bound to a strict 0.1 LOLE metric and should instead preserve the ability to set “just and reasonable” reliability levels considering cost and policy tradeoffs.

Local RA Tools, Transparency, and LCR‑RCM

• CalCCA opposes eliminating the LCR‑RCM, arguing it was intentionally designed to incentivize new preferred and storage resources for local capacity and that limited participation reflects program scope and implementation burdens rather than lack of value; CalCCA instead supports improved local RA transparency and consistent CPE use of data.
• SCE supports eliminating the LCR‑RCM, citing minimal participation, administrative complexity, and concerns about extending market‑power premiums, and argues existing procurement and cost‑allocation mechanisms are sufficient without this additional tool.
• Sierra Club (with CEJA) supports retaining the LCR‑RCM at this time, viewing it as an important incentive for clean local capacity and cautioning that removal without a replacement could allow CPEs to rely on LSE procurement for local benefits without appropriate compensation.
• Ava Community Energy (Ava) opposes elimination of the LCR‑RCM, stating that limited historical use does not prove it lacks value and that the mechanism provides procurement flexibility and competitive pressure in constrained local areas; Ava recommends targeted reforms over removal.
• Alliance for Retail Energy Markets (AReM) supports increased transparency around local procurement and generally backs aggregated, accessible data on local RA positions and development activity to inform LSE decisions, while not taking a specific position on LCR‑RCM elimination in these comments.

EDAM / DAME Products, IR/RC Bidding, and Revenue Allocation

• SCE backs adoption of a modified version of Energy Division’s “Proposal G” for RC/IR treatment, supports including requirements for future contracts to address allocation of RC/IR revenues, and opposes zero‑dollar bid mandates, required renegotiation of existing contracts, and a new memorandum account subject to ERRA review.
• Alliance for Retail Energy Markets (AReM) supports allowing bilateral negotiations to determine revenue allocation for EDAM-related products (Imbalance Reserves and Reliability Capacity) rather than Commission‑mandated splits, and recommends the Commission monitor EDAM implementation and consider RA rule changes for compliance year 2028 if needed.
• CalCCA opposes prescriptive IR/RC bidding and revenue‑sharing mandates, arguing that bilateral contracting should govern these terms and that forced allocation rules could disadvantage jurisdictional LSEs relative to non‑jurisdictional entities.
• American Clean Power – California (ACP‑California) supports market-based bidding and flexible contract terms for EDAM/DAME products, cautioning that overly rigid CPUC rules on bidding or revenue allocation could undermine efficient participation and investment signals.
• Sierra Club (with CEJA) recommends deferring broader EDAM‑related RA design decisions until after EDAM goes live, so that actual market operations can inform any necessary RA adjustments.

Storage QC, Non-Linearity, and BESS Showing Requirements

• GreenGenStorage, LLC (GreenGen) supports clarifying that storage QC should only reflect the portion of state of charge that can be discharged continuously at full output for at least four hours, and that ranges affected by foldback or non‑linearity (e.g., warranty constraints) should be excluded from QC-based accreditation.
• SCE agrees storage non‑linearity and foldback should be accounted for in QC, not UCAP, to avoid double penalizing storage; SCE also urges OMS corrections for hybrids so model‑driven SOC limits are not mislogged as forced outages.
• Middle River Power LLC (MRP) recommends that BESS showing requirements continue to require sustaining full RA qualifying capacity for four consecutive hours and minimum availability over three consecutive days, and opposes CalCCA’s proposal to count a four-hour BESS that offers a derated fourth hour.
• CalCCA opposes CAISO’s QC approach to storage foldback that averages over continuous four‑hour windows, and instead proposes a SOD‑compatible method that allows full capacity in some hours and derated capacity in others, subject to MWh and foldback limits.
• Alliance for Retail Energy Markets (AReM) supports limiting QC to sustainable output ranges and recommends that open‑loop PSH be modeled with explicit pumping energy requirements so that both hydro generation and storage-like services are accurately represented in reliability metrics.
• NextEra Energy Resources (NextEra) supports storage accreditation methods that do not over‑discount storage based on non‑linear operating constraints, emphasizing the need to maintain viable investment signals for storage resources required under IRP.

Data Center Load and RA Obligations

• CalCCA continues to urge prompt adoption of its data center load allocation proposal, which would tie RA obligations to specific interconnection milestones for large, discrete data center loads, arguing this better aligns RA procurement with near‑term load realization than relying solely on IEPR forecasts.
• Alliance for Retail Energy Markets (AReM) supports accommodating data center load risk within RA design, agrees with CalCCA that relying only on IEPR forecasts may not adequately reflect timing of large single‑meter loads, and emphasizes that the serving LSE should bear RA responsibility for these customers while avoiding unnecessary over‑procurement if interconnections are delayed.
• SCE highlights rapid data center growth as a planning concern and supports prioritizing Track 1 decisions that clarify how RA requirements will account for these new loads, though it does not propose a distinct methodology beyond those already in the record.
• Sierra Club (with CEJA) underscores that data center growth may significantly impact RA planning and supports measures that ensure such load growth does not undermine reliability or shift disproportionate costs to existing customers.
• Cal Advocates/M.Miley/CPUC (Cal Advocates) continues to support use of IEPR-based forecasts as the primary RA planning tool while remaining open to coordination between CPUC and CEC to better capture emerging large load drivers such as data centers.