Simplifying Policy Management

context

• The Commission’s PCIA framework is intended to preserve “customer indifference” — preventing cost shifts between bundled (IOU-served) customers and departing load (customers who leave bundled service). The framework was first revised in Decision (D.) 11-12-018 (2011), which required bundled customers to pay/credit departing load the market value of renewable resources in the resource generation year.
• The Legislature directed flexible REC banking in SB 1078 (2002). The Commission authorized REC banking in D.10-03-021 (2010), which was stayed until D.11-01-025 (January 14, 2011).
• The PCIA methodology was later revised in D.18-01-019 (2018) and D.19-10-001 (2019) to require bundled customers to credit departing load for REC components in the year RECs are sold or used for bundled compliance; D.19-10-001 stated explicitly that its RPS valuation methods apply prospectively to RECs generated commencing January 1, 2019.

Key dispute and parties

• CalCCA (the California Community Choice Association) argued that valuing Pre-2019 Banked RECs at zero denies value to “Later Departing Load” (customers who left bundled service after bundled customers had paid for RECs in the generation year) and thus violates indifference statutes (including Pub. Util. Code § 366.2(g)).
• Joint IOUs and other stakeholders relied on the finality and prospective scope of the earlier decisions and on Working Group statements (including co-chairs CalCCA and PG&E) that RECs generated in 2018 or earlier had already been “bought and paid for” by bundled customers via prior RPS adders.

Findings of fact

• The Commission’s 2011 methodology allocated costs/benefits of renewable resources in the generation year, regardless of whether RECs were banked or later used; it did not treat “Later Departing Load” as a distinct category entitled to an additional credit when banked RECs were later used.
• Stakeholders, including CalCCA, understood that the valuation method in D.19-10-001 would apply only prospectively (to RECs generated on or after Jan. 1, 2019). CalCCA did not seek rehearing of D.11-12-018 or D.19-10-001 on the basis now asserted.
• The alleged cost shift CalCCA seeks to redress existed under the pre-2019 framework and was known when the Commission adopted that methodology; parties relied on that finality when making procurement and market decisions.
• The Staff Report presented alternative proposals to value Pre-2019 Banked RECs at other than zero, but it did not analyze precedent or procedural constraints.

Conclusions of law

• Bundled customers satisfied the indifference mandates when they credited departing load the market value of Pre-2019 Banked RECs in the generation years under D.11-12-018. No additional credit is required when those RECs are later used for bundled compliance.
• D.19-10-001’s RPS valuation rules were adopted prospectively, applying only to RECs generated beginning January 1, 2019. Retroactively requiring additional payments or credits for Pre-2019 RECs would be inconsistent with D.11-12-018 and D.19-10-001 and would violate indifference mandates.
• Requiring isolated retroactive redress for a single alleged prior cost shift would be arbitrary; CalCCA’s proposal is unreasonably delayed, and CalCCA acquiesced to the prospective scope of D.19-10-001. Applying CalCCA’s proposal now would prejudice parties who relied on the prior methodology; laches therefore bars CalCCA’s claim.

Order

Effective immediately:

• Pre-2019 Banked RECs shall be valued at zero dollars for purposes of calculating PCIA indifference amounts for PG&E, SDG&E, and SCE.
• This methodology is effective immediately and must be incorporated into each IOU’s 2027 Energy Resource Recovery Account (ERRA) October Updates, affecting 2026 true-ups and 2027 forecasted rates. (D.25-12-028 and D.25-12-027 specifically required SCE and PG&E to apply the methodology in their October Updates.)
• Rulemaking (R.) 25-02-005 remains open.

Practical effect

• No additional PCIA credit will be required when Pre-2019 banked RECs are used for bundled customer compliance; those RECs are treated as having been compensated in their generation years.
• IOUs must reflect this zero valuation in 2026 true-ups and 2027 forecasts through the October ERRA updates.
• The Commission leaves open its rulemaking R.25-02-005 for any further proceedings.

Dates and references cited in decision

SB 1078 (2002); D.10-03-021 (2010); D.11-01-025 (Jan. 14, 2011); D.11-12-018 (2011); D.18-01-019 (2018); D.19-10-001 (2019) — which applies prospectively to RECs generated commencing Jan. 1, 2019; and the current decision’s incorporation into 2027 ERRA October Updates (impacting 2026 true-ups and 2027 forecasts).

filings

D.24-10-030 (October 23, 2024) required PG&E, SCE, and SDG&E to file an advice letter on increased project sizing; the Large IOUs filed a Joint Sizing AL on December 15, 2025 (SCE 5706E). D.26-02-025 (February 5, 2026) adopted a Standard Offer for Flexible Service Connections and directed PG&E and SCE in OP 1 to explain normal and emergency ratings and durations. PG&E and SCE filed a Joint SO AL on April 13, 2026 (SCE 5790E) identifying IOU documents with the required rating information. The ACP Comment Ruling (July 7, 2026) proposed official notice of several documents.

Official notice taken and directives

The Commission officially notices the documents in Section Five of the ACP Comment Ruling. By August 24, 2026, PG&E must file capability sheets for all service conductors and secondary transformers commonly used for distribution customers and, if not stated, specify emergency ratings and allowable durations. By the same date SCE must file engineering standards for those conductors and transformers and specify any emergency ratings and durations if not documented.

Objection process and procedural

The Joint Sizing AL (December 15, 2025) is proposed for official notice under Rule 13.9 and Cal. Evidence Code Section 452; parties opposing that notice must file and serve a motion to object within 10 days of this ruling. The Docket Office will file this ruling; issued by Justin Regnier, ALJ, CPUC.

response to the Assigned Commissioner’s Scoping Memo and Ruling dated July 20, 2026. The Scoping Memo also directs SPD to file a proposal on risk tolerance by November 16, 2026.

Purpose of Requested Information

The Commission seeks clarification about the Bibliography appended to the Joint IOU Risk Tolerance Survey Report—specifically how the Joint IOUs used the cited literature (chemical, nuclear, earthquake, etc.) jointly or separately in preparing the Report and whether any materials were derived from that literature and applied in regulatory submissions.

Required Filings and Specific Questions

Deadline: within 10 days of August 11, 2026 (i.e., by August 21, 2026, subject to calendar specifics). Filings must include copies of responsive records and materials. The ALJ lists six specific questions requiring the Joint IOUs to:

• identify summaries or notes generated from the Bibliography;
• file those summaries or notes;
• file any additional supporting materials;
• state the extent of application of Report approaches in a RAMP or GRC Application;
• state the extent of application in a WMP; and
• state the extent of current use to inform RAMP, GRC, or WMP.

improve transparency, safety, reliability, and resilience of the distribution grid. Rulemaking R.24-05-023 is closed.

Key reporting requirements and schedule

• Annual report: Beginning in 2027, and no later than 30 days after July 15 each year, PG&E, SCE, and SDG&E shall submit a completed customer reliability report and data submission to the CPUC’s Safety Policy Division that complies with the Template & Customer Reliability Schema. These annual submissions will be resolved through a Resolution presented to the Commission for vote. The Annual Electric Reliability Report submission is also required through July 15, 2027 procedures, but the Annual Electric Reliability Report requirement ends on August 15, 2036.
• Quarterly data updates: Beginning October 2027, and two weeks after the start of each new quarter (October 15, January 15, and April 15), the three investor-owned utilities (Joint IOUs) shall submit updated data submissions aligning with the annual report. These quarterly data files shall be submitted to CPUC Safety Policy and Energy Division staff via secure File Transfer Protocol as compliance filings.
• Sunset: The customer reliability report and data submission obligations terminate on August 15, 2036.
• Triennial review: Every three years from July 15, 2027 (first due July 15, 2029), the Joint IOUs shall report—via Advice Letter—whether the CPUC should consider updates or enhancements to the Template. The scope of such changes must be narrow and focused on data relevance, reporting mechanisms, cadence, timing, sequencing, and integration with existing reporting.
• Workshop: Within 90 days of July 15, 2027, the Joint IOUs must host a workshop with CPUC staff and stakeholders to identify clarifications, implementation challenges, reporting limitations, data quality improvements, and other enhancements. The workshop is explicitly not a forum to relitigate settled issues.

Content and data elements required by the Template

• Narrative and supplemental content: Annual narrative on planned and unplanned outages; an annual summary of each utility’s Wildfire Mitigation Data Report; explanations of customer notifications before, during, and after outages; and descriptions of mitigation actions.
• Shared definitions: The decision adopts specific definitions for use in the Template, including:
  • “Public safety partner” — first responders (local, state, federal), water and communications providers, community choice aggregators, affected publicly-owned utilities/electrical cooperatives, the CPUC, California Office of Emergency Services, and CAL FIRE.
  • “Customers with medical needs” — households enrolled in the Medical Baseline program or receiving a medical discount, plus customers who have self-identified as including a person with a medical condition (as authorized in R.18-12-005).
• Outage classification: Utilities must separately identify and define Public Safety Power Outage and Protective Equipment and Device Settings (PEDS, also referred to as Fast-Trip) as distinct outage types from other outages, and explain how PEDS settings have changed over time and whether such changes contributed to repeated interruptions.
• Circuit- and customer-level technical reporting: For each outage at the customer level, utilities must report overhead versus underground circuit outages, the percentage breakdown between overhead and underground, and conductor type (bare/covered/insulated) for the affected circuit or segment.
• Customer populations: For each recorded outage, utilities must report impacts on customers with access and functional needs, Medical Baseline/essential customers, and other specified populations to ensure these groups are accounted for in oversight.
• Reliability metrics and tables: The Template requires reporting of Customers Experiencing Multiple Interruptions (CEMI), Customers Experiencing Long Interruption Duration (CELID), SAIDI, SAIFI, CAIDI, and MAIFI — each reported with and without inclusion of Major Event Days (MEDs). Utilities must also provide Customer- and Outage-Level tables to avoid siloed information.

Findings and legal conclusions

• The CPUC found that climate change, wildfire risk, and wildfire mitigation practices (including PSPS and Fast-Trip/PEDS) create new priorities and risks that warrant modernized outage reporting.
• The Joint IOUs’ proposed Template & Customer Reliability Schema is considered reasonable with modifications and is adopted (see Appendix A).
• The CPUC ordered the actions above (annual/quarterly reporting cadence, workshop, triennial review, definitions, metric reporting, and the sunset date), affirmed prior ALJ/Assigned Commissioner rulings, denied unresolved motions, and closed R.24-05-023.

Effective date

The order is effective August 13, 2026.

applications, but they differed in how they estimated costs, how much automation they said is already in place, and whether project size alone is a reliable basis for scaling fees.

Data Tracking and Methodology

• PG&E said it could not provide the exact template requested because it does not track staff time by individual project. It instead used best-estimate cost and hour data for 2024 and 2025, attributed across applications using order-level and application-count information, and said it would improve tracking and correct a prior accounting misallocation affecting some NEM multiple-tariff reporting.
• SDG&E said it also does not maintain project-level time tracking for every application and used an experience-based methodology, drawing on workflow data, staff input, and representative average hours by function to build its estimates.
• SCE said it does not maintain an end-to-end project-level time-tracking system for non-NBT/NEM applications and relied on estimated staff hours, fully loaded labor rates, and portal/workflow assumptions for its estimates.

Whether the $800 Fee Covers Initial Review Costs

• PG&E said the $800 fee did not cover its estimated initial-review costs for 2024 non-NEM applications, but that 2025 initial-review revenues slightly exceeded estimated costs for that year overall. PG&E’s estimates showed an undercollection in 2024 and an overcollection in 2025 for the initial review phase only.
• SDG&E said the fee under-collects relative to its modeled processing costs for non-NBT/NEM applications, and estimated about $1.1 million in under-collection across 1,012 approved projects in 2024–2025.
• SCE said the current $800 fee under-collects for both standard exporting and standard non-exporting projects, with larger under-collection for exporting projects and additional cost recovery gaps for non-standard projects that require cost estimate reports or site visits.

Project Complexity, Size, and Fee Scaling

• PG&E said project capacity is only a proxy for complexity and that context, technology, and grid conditions matter. It said smaller projects under 30 kW are generally less complex, while storage, machine generation, and limited/non-export configurations can increase review effort.
• SDG&E said there is no single MW/kW threshold that automatically determines complexity and that system conditions, not size alone, drive the need for more detailed review. It pointed to factors such as relay schemes, telemetry for projects above 1 MW, and complex power control configurations.
• SCE said project complexity depends on Rule 21 screen results and project configuration rather than a simple size threshold. It identified non-export versus export status, storage configurations, and power control systems as key drivers of review effort.

Screening Outcomes and Triggers for Additional Study

• PG&E said about 98% of non-NEM interconnected projects in 2024–2025 passed initial screens without supplemental or detailed engineering review, with only a small share moving to supplemental or system impact studies.
• SDG&E said most approved non-NBT/NEM projects required deficiencies and resubmittal activity, with an average of about 2.28 deficiencies per project and roughly three technical reviews per application on average.
• SCE said 98.4% of non-NBT/NEM projects in 2024–2025 passed Initial Review without Supplemental Review or Detailed Study, and that screen failures can still be resolved through mitigation or agreement rather than detailed study.

Automation, Portals, and Process Changes

• PG&E said its primary automation is the Distribution Generation Screening Tool for Initial Review and that it is evaluating additional automation and better time/billing tracking.
• SDG&E said its Customer Generation portal and new cloud-based interconnection platform automate submission, status tracking, notifications, and some business-rule checks, but it could not yet quantify future cost reductions from further automation.
• SCE said its interconnection portal has limited automation for some tasks, with enhanced time reporting for some assigned resources, and that broader automation for some non-NBT/NEM standard projects is still under development.

Timelines, Application Mix, and Hourly Rate Assumptions

• PG&E reported average application-to-PTO timelines that were much longer for non-residential than residential projects, and said its internal implied fully loaded labor rates were lower than the tariff’s referenced hourly fee, while also noting those internal rates excluded some overhead items.
• SDG&E said utility-controlled processing time should be separated from customer-driven delays, and it used an estimated fully loaded engineering rate for custom studies as a planning and cost-recovery assumption.
• SCE said it applied 2026 midpoint wages and a companywide overhead factor to estimate labor costs, and said its estimates excluded additional unquantified support functions such as legal, IT, and management.

how to treat existing resources and long-lead-time projects, and whether reliability and clean-energy compliance should be handled in one framework or split across multiple mechanisms.

Overall support for a recurring, planning-based procurement program

• Pacific Gas and Electric Company, Southern California Edison Company, SAN DIEGO GAS & ELECTRIC COMPANY, California Independent System Operator Corporation, Clearway Energy Group LLC, California Resources Corporation, Ormat Technologies, Inc., Fervo Energy Company, Hydrostor, Inc., REV Renewables, LLC, American Clean Power - California, Solar Energy Industries Association, Long Duration Energy Storage Council ("LDES Council"), The Utility Reform Network, Sierra Club, Green Hydrogen Coalition, and Shell Energy North America (US) generally support moving away from ad hoc procurement toward a recurring, planning-based framework tied to IRP/PSP/TPP outputs.
• Silicon Valley Clean Energy, Ava Community Energy, and California Large Energy Consumers Association support more structured procurement, but argue the proposal needs substantial revision to avoid locking in a single modeled future or creating inflexible procurement obligations.
• Western Power Trading Forum, Calpine LLC, and Middle River Power LLC support the concept of a durable framework but say the proposal is not ready to be adopted as written because of unresolved design issues.

Need determination and procurement design: attributes, categories, and flexibility

• Pacific Gas and Electric Company, Southern California Edison Company, SAN DIEGO GAS & ELECTRIC COMPANY, California Independent System Operator Corporation, Solar Energy Industries Association, California Energy Storage Alliance, Calpine LLC, NextEra Energy Resources, LLC, Clearway Energy Group LLC, Form Energy, Inc., Hydrostor, Inc., Fervo Energy Company, Green Hydrogen Coalition, Long Duration Energy Storage Council ("LDES Council"), Shell Energy North America (US), and Southern California Gas Company favor some form of attribute-based procurement rather than purely technology-specific mandates.
• California Large Energy Consumers Association, Silicon Valley Clean Energy, Ava Community Energy, and The Utility Reform Network stress that attributes should remain broad enough to preserve competition and least-cost procurement.
• Ormat Technologies, Inc., California Resources Corporation, and California Independent System Operator Corporation favor more specific resource categories for certain needs, especially clean firm, geothermal, and location-constrained resources, to better match planning and transmission assumptions.
• California Community Choice Association is not among the filings provided in the record excerpt, so no position is summarized here.
• California Energy Storage Alliance, Long Duration Energy Storage Council ("LDES Council"), and Form Energy, Inc. argue storage should be distinguished by duration, with longer-duration and multi-day storage treated separately from short-duration resources.
• Western Power Trading Forum, California Large Energy Consumers Association, and Shell Energy North America (US) support broad, tradable attributes and oppose overly narrow technology definitions or category caps that would distort market choices.
• Southern California Gas Company, Green Hydrogen Coalition, California Resources Corporation, and Ormat Technologies, Inc. emphasize that specific clean-firm or fuel-based categories should remain eligible, including gas-system-linked repowers, hydrogen pathways, CCS retrofits, and geothermal.

Existing resources, repowering, and retention of the baseline fleet

• Western Power Trading Forum, Middle River Power LLC, Clearway Energy Group LLC, California Energy Storage Alliance, Independent Energy Producers Association, and California Resources Corporation argue Option 3 should explicitly address existing resources, repowering, augmentation, and retrofit pathways so the framework does not assume the baseline fleet will remain online without a support signal.
• REV Renewables, LLC and The Utility Reform Network support the new-resource focus of Option 3 more than earlier alternatives, but REV Renewables, LLC separately says repowering of existing resources should be addressed quickly.
• San Diego Gas & Electric Company, Southern California Edison Company, PG&E, and CAISO all note that existing resources remain important for reliability and that procurement rules should avoid duplicative treatment or accidental retirement signals.
• Silicon Valley Clean Energy, Ava Community Energy, and Cal Advocates/M.Miley/CPUC emphasize that existing resources and repowers should be accounted for up front, not left as an afterthought.

Contracting and online timelines for new and long-lead-time resources

• CAISO, NextEra Energy Resources, LLC, REV Renewables, LLC, Calpine LLC, Southern California Edison Company, SAN DIEGO GAS & ELECTRIC COMPANY, American Clean Power - California, Hydrostor, Inc., Fervo Energy Company, Ormat Technologies, Inc., and several others support early contracting milestones, but many say the proposed T+3 contracting and T+5 online dates are too rigid for many resources.
• Western Power Trading Forum, California Large Energy Consumers Association, Silicon Valley Clean Energy, Ava Community Energy, and The Utility Reform Network argue the timelines are too compressed and need stronger good-faith, cure, extension, or alternative compliance pathways.
• Long Duration Energy Storage Council ("LDES Council"), Hydrostor, Inc., Green Hydrogen Coalition, Fervo Energy Company, and Ormat Technologies, Inc. specifically argue that LLT resources need separate, longer timelines or project-specific COD treatment.
• Cal Advocates/M.Miley/CPUC, Sierra Club, and CEJA/Sierra Club say five-year online deadlines may be unrealistic for some resource types, especially LLT resources, and should be adjusted or paired with exceptions.
• CAISO supports a three-year contracting milestone, but says a uniform five-year online requirement is too inflexible and should be adapted by resource type and transmission conditions.

Accreditation, ELCC, and coordination with RA

• Southern California Edison Company, California Large Energy Consumers Association, Silicon Valley Clean Energy, Ava Community Energy, The Utility Reform Network, and AReM prefer Slice-of-Day or another RA-aligned approach for near-term compliance, and criticize heavy reliance on marginal ELCC for binding procurement.
• PG&E, CAISO, REV Renewables, LLC, NextEra Energy Resources, LLC, Middle River Power LLC, SAN DIEGO GAS & ELECTRIC COMPANY, and Form Energy, Inc. support using marginal ELCC, but want values fixed or vintaged in advance and coordinated with procurement cycles.
• Western Power Trading Forum, Calpine LLC, LDES Council, Sierra Club, and Shell Energy North America (US) all note that accreditation must be stable, transparent, and not retroactively erode the compliance value of executed contracts.
• California Resources Corporation, Green Hydrogen Coalition, and Southern California Gas Company emphasize that accreditation should not be the only measure of clean-firm value and should not exclude resources whose main contribution is emissions reduction or dispatchability during stress conditions.
• CAISO says RA and RCPPP should remain distinct but coordinated, while several parties urge a clearer crosswalk between RCPPP accreditation and RA counting to avoid double counting or conflicting compliance signals.

Load migration, allocation, and cost responsibility

• Western Power Trading Forum, Calpine LLC, Shell Energy North America (US), and AReM say procurement obligations should follow load migration over time, and that snapshot-based allocations can create stranded-cost or free-rider problems.
• PG&E argues the Commission should account for each LSE’s existing resource portfolio, not just load share, when allocating new procurement obligations.
• Southern California Edison Company and SAN DIEGO GAS & ELECTRIC COMPANY both say allocation should reflect LSE-specific portfolios and prior procurement, not only system load share.
• CEJA and Sierra Club focus less on load migration and more on ensuring procurement obligations reflect local and disadvantaged-community impacts.

Central procurement, DWR/CPE, and backstop responsibilities

• Southern California Edison Company, SAN DIEGO GAS & ELECTRIC COMPANY, PG&E, California Resources Corporation, Hydrostor, Inc., Fervo Energy Company, American Clean Power - California, and CAISO support some role for central procurement or subtraction of already-committed central procurement from LSE obligations, but want that treatment clearly defined and time-limited.
• Western Power Trading Forum, Shell Energy North America (US), and AReM caution that LSEs should not automatically absorb shortfalls from centralized procurement they do not control.
• Hydrostor, Inc., Fervo Energy Company, and Ormat Technologies, Inc. want clear coordination between RCPPP and any CPE/AB 1373 procurement track so LLT resources can be procured centrally where appropriate.

Penalties, buffers, and compliance enforcement

• Western Power Trading Forum, Calpine LLC, Shell Energy North America (US), PG&E, and SAN DIEGO GAS & ELECTRIC COMPANY support penalties tied to net CONE or another transparent metric, but argue penalties should be proportionate, cure-friendly, and not duplicative.
• Cal Advocates/M.Miley/CPUC supports net CONE for NQC shortfalls but wants an adaptive retirement allowance and better market-feasibility testing.
• California Large Energy Consumers Association, Silicon Valley Clean Energy, and Ava Community Energy are wary of penalties that could overburden ratepayers or punish LSEs for outcomes outside their control.
• California Energy Storage Alliance and LDES Council support meaningful penalties but want them aligned to the specific missing category, rather than a one-size-fits-all penalty benchmark.
• CEJA/Sierra Club and Sierra Club say the Commission should use fact-specific, transparent compliance and penalty rules, especially where local air quality and disadvantaged communities are affected.
• California Wind Energy Association, while not separately requested here, also argued for transmission-aware penalty waivers where delays are outside an LSE’s control.

Transmission, interconnection, and locational deliverability

• CAISO, American Clean Power - California, Solar Energy Industries Association, Green Hydrogen Coalition, Fervo Energy Company, Ormat Technologies, Inc., and CALIFORNIA ENERGY STORAGE ALLIANCE emphasize that procurement must be coordinated with transmission planning, interconnection, and deliverability timelines.
• CEJA and Sierra Club argue local procurement needs should be more explicit, including transmission-constrained areas and disadvantaged communities.
• Southern California Edison Company, SAN DIEGO GAS & ELECTRIC COMPANY, and PG&E all caution that transmission and interconnection delays make uniform five-year online deadlines unrealistic for many resources.
• Hydrostor, Inc., Fervo Energy Company, and Ormat Technologies, Inc. want RCPPP to align closely with CAISO deliverability processes so long-lead projects can actually reach COD.

Clean-energy accounting, GHG methods, and the role of separate compliance tools

• The Utility Reform Network, Sierra Club, CEJA and Sierra Club, Green Hydrogen Coalition, and California Resources Corporation support clearer GHG accounting, but they differ on how much should remain separate from the reliability framework.
• Southern California Edison Company, PG&E, and Ava Community Energy favor a separate or simplified mass-based clean-energy or GHG compliance framework rather than using the same metric as reliability compliance.
• Cal Advocates/M.Miley/CPUC supports a Clean System Power Calculator-based GHG compliance check, while CURE insists procurement should result in electricity physically delivered to California consumers, not just accounting instruments.
• CAISO, Form Energy, Inc., and California Resources Corporation all want GHG and reliability analysis to be more directly linked to the actual resource mix that will be built and operated.

Long-duration storage, clean firm, geothermal, hydrogen, CCS, and repowering pathways

• Long Duration Energy Storage Council ("LDES Council"), Hydrostor, Inc., Form Energy, Inc., California Energy Storage Alliance, and CALIFORNIA ENERGY STORAGE ALLIANCE all ask the Commission to recognize longer-duration and multi-day storage as distinct procurement needs.
• Green Hydrogen Coalition and Southern California Gas Company support explicit recognition of renewable/clean hydrogen and repowered gas infrastructure as part of the resource mix.
• California Resources Corporation, Calpine LLC, and Southern California Gas Company support CCS or repowering pathways as eligible clean-firm resources.
• Ormat Technologies, Inc. and Fervo Energy Company focus on geothermal and other LLT clean firm resources, saying they need bespoke categories and longer development horizons.
• Middle River Power LLC also supports CCS eligibility and separate treatment of hybrid gas-plus-battery or clean-firm configurations.

Procedural cadence and filings

• PG&E, SAN DIEGO GAS & ELECTRIC COMPANY, CAISO, American Clean Power - California, California Wind Energy Association, and others support a more regular cadence for IRP/TPP/procurement updates, though they differ on whether that should mean four-year IRP cycles, biennial PSP/TPP updates, or interim update filings.
• Silicon Valley Clean Energy and Ava Community Energy are skeptical of moving to longer IRP cycles because market conditions can change quickly.
• Western Power Trading Forum, PG&E, and SDG&E favor streamlined annual or consolidated compliance filings and less duplicative reporting.

Key points of disagreement

• Supporters of Option 3 generally see it as a better bridge between planning and procurement, while opponents or conditional supporters worry it is too rigid and too dependent on a single modeled future.
• There is broad disagreement over whether procurement should be framed mainly by broad attributes, by narrower categories, or by specific resource types for LLT and location-constrained needs.
• Parties also split on whether the Commission should use marginal ELCC, SOD, or a hybrid approach for binding compliance, and on how much flexibility to allow for long-lead-time projects, load migration, and central procurement shortfalls.