Simplifying Policy Management

and coordination, and explores standardizing and improving utility energization processes.

Background

The Commission opened Rulemaking R.24-01-018 on January 30, 2024 to implement SB 410 and AB 50, which require establishing average and maximum energization timelines and a customer reporting procedure for energization delays. On September 17, 2024, Decision D.24-09-020 was issued to set these timelines. SB 254, enacted on September 19, 2025, expanded requirements by directing the Commission to report on linking executive compensation to energization targets, establish enforcement policies with penalties, and require utilities to retain third-party auditors. The Commission has already directed PG&E and SDG&E to retain auditors pursuant to SB 410.

by September 21, 2026.

Materials and guidance

All filing requirement materials necessary for LSEs to prepare individual IRPs are finalized and posted on the CPUC website at the provided 2024-26 IRP cycle events and materials link. Parties should use those materials when preparing submissions and reference the corrected RESOLVE selections in Table 1 when evaluating or commenting on IRPs.

Correction to Table 1 and RESOLVE selections

The March 20, 2026 ruling replaces Table 1 from the January 16, 2026 ALJ ruling with a corrected “Table 1. RESOLVE-Selected New Resources (in GW).” Key entries include Solar (4.0 GW in 2026 to 82.7 GW in 2045), Out-of-State Wind (1.4 GW to 19.0 GW), In-State Wind (0.3 GW to 10.9 GW), Li-ion Battery (4-hr) (2.3 GW to 6.8 GW), Li-ion Battery (8-hr) (0.1 GW to 21.1 GW), Geothermal (0.1 GW to 3.2 GW), EGS (0.0 GW early to 0.7 GW in 2045), and Gas Capacity Not Retained (-0.3 GW each listed year).

Rulings

• Corrected Table 1 replaces the January 16, 2026 table.
• LSE IRP filing deadline: August 10, 2026.
• Deadline for initial comments: September 21, 2026.

The ALJ ruling correcting Table 1 was issued March 20, 2026 (filed 03/20/26).

biogas. ENGIE filed its Petition on October 4, 2024, seeking an exemption for WWTP on-site biogas (which ENGIE asserts is ~60% methane) from the 96% requirement. Responses were filed November 4, 2024 by SoCalGas, BAC, and Cal Advocates; ENGIE filed a Reply November 15, 2024. The record was submitted November 15, 2024.

Legal issue and procedural ruling

The Commission framed two issues: compliance with Rule 16.4(d) and whether to grant the exemption. Rule 16.4(d) requires petitions for modification be filed and served within one year of the decision’s effective date or explain why late filing was unavoidable. ENGIE filed more than one year after D.21-06-005 and argued project timing prevented earlier filing. Cal Advocates contested this. The Commission found ENGIE failed to justify the late filing under Rule 16.4(d) and summarily denied the Petition on procedural grounds.

Outcome and order

Findings: Petition filed > one year after D.21-06-005; fails Rule 16.4(d). Conclusion: denial is reasonable. Order (effective today; Dated March __, 2026, at Sacramento, California):

• ENGIE’s Petition is denied;
• Rulemaking 20-05-012 remains open.

The decision does not address the substantive merits of a WWTP exemption.

Last Week's New Comments +4

Overview

This update summarizes a sampling of parties’ positions in recent comments on the Assigned Commissioner’s Rulings regarding enhanced verification of Self‑Generation Incentive Program (SGIP) Total Eligible Project Cost (TEPC) for the Residential Storage and Solar Equity (RSSE) program in R.20‑05‑012, focusing on TEPC levels, verification approaches, documentation thresholds, and implementation impacts.

Explanations for Higher RSSE TEPC Compared With Incentives and Market Averages

• GRID Alternatives states that RSSE TEPCs are higher due to intensive outreach and customer support for low‑income and disadvantaged community households, higher logistics costs in remote and Tribal areas, frequent enabling upgrades (e.g., critical loads panels, wiring) plus non‑eligible structural work, recent equipment cost inflation tied to tariffs and federal content rules, and ownership/financing costs including extended warranties and the cost of capital while awaiting incentive and tax credit payments.
• CALSSA argues that RSSE costs should not be expected to match “average” SGIP or statewide market projects because RSSE exclusively serves low‑income customers, and points to historical Residential Storage Equity data showing higher TEPC, the prevalence and financing characteristics of third‑party ownership, program‑specific requirements (such as prior demand response enrollment rules) that increased timelines and carrying costs, inflation and tariff‑driven cost increases since 2022, and differences between EnergySage benchmarks and other datasets (e.g., Ohm Analytics, CaliforniaDGStats) as important drivers of higher TEPC.
• CSE cautions that any explanation for higher RSSE TEPCs should be based on actual cost documentation rather than assumptions, and indicates that once new TEPC verification documentation is systematically collected, Program Administrators (PAs) will be better positioned to identify specific cost drivers.
• SoCalGas notes that PAs themselves are not best positioned to explain industry‑wide drivers of higher RSSE TEPC and indicates interest in industry participant input to clarify why RSSE project costs appear higher than incentives and statewide averages.

How Projects Cover Gaps Between TEPC and SGIP Incentives

• GRID Alternatives explains that it provides systems at no cost to participating households and covers the difference between TEPC and combined SGIP/federal incentives with philanthropic contributions and complementary public or utility program funding, such as Transformative Climate Communities grants and utility program funds.
• CALSSA reports that, based on discussions with RSSE developers, nearly all structure transactions so that customers have no out‑of‑pocket cost, with developers or third‑party owners absorbing gaps between TEPC and incentives/ITC through reduced margins, overhead absorption, or financing structures that account for SGIP’s payment timing and project‑failure risk.
• CSE notes that SGIP currently does not collect detailed funding‑source information beyond federal ITC and program incentives, and that while contracts exceeding incentive amounts may imply some customers pay the difference, program administrators have not systematically verified how the TEPC–incentive gap is financed.

Thresholds and Definitions for TEPC Documentation Triggers

• CSE recommends raising the TEPC documentation trigger from TEPC ≥ 90% of the “maximum SGIP incentive” to TEPC > 100% of the maximum incentive, arguing that a 90% threshold would immediately subject thousands of active RSSE applications to additional review and strain administrative resources, and that Commission findings indicate current incentive levels are generally aligned with market prices.
• CSE requests that “maximum SGIP incentive” be defined as the incentive amount a customer will actually receive (after applying limiting factors such as the federal ITC), rather than a theoretical amount based solely on system size times the base rate, to avoid confusion and unnecessary verification for projects whose effective incentives are already limited.
• CSE asks the Commission to clearly define “consistently overstated” TEPC in the context of potential cancellation of all an applicant’s waitlisted projects, to establish an objective standard for when this sanction may be applied and to minimize inconsistent PA interpretations.
• CALSSA contends that using a single maximum incentive value (such as $30,020 for an assumed standard system) as a broad cap or benchmark for reasonableness is analytically flawed, because RSSE projects can legitimately vary in size and load, and emphasizes that historical data and multifamily project characteristics do not support a one‑size‑fits‑all “100% cost coverage” standard.

Preferred TEPC Verification and Documentation Approaches

• GRID Alternatives recommends that TEPC verification rely on portfolio‑level documentation of actual equipment and labor costs from developers with multiple projects, rather than requiring detailed, project‑by‑project documentation, and suggests focusing on the major TEPC components (equipment and labor) while allowing flexible forms of documentation that reflect different business models and accounting practices.
• SoCalGas supports enhanced verification and recommends that applicants with high TEPC either revise TEPC estimates below the verification threshold (if previously over‑stated) or confirm their estimates and provide an itemized cost breakdown at or near the Reservation Request Form stage, so that PAs can understand drivers of high TEPC earlier and identify documentation likely needed for final payment verification.
• SoCalGas proposes that the Commission adopt verification and audit practices similar to those used in the Solar on Multifamily Affordable Housing (SOMAH) program, including the option for PAs to review invoices, proof of payments to vendors, and detailed cost documentation (equipment purchases, labor expenditures) and to request more detailed breakdowns where costs appear unreasonable or are not clearly documented.
• CSE notes that cost‑verification documentation such as equipment receipts and labor documentation is new for SGIP and that PAs are working to collect such information under the ACR, but indicates that the specific list of acceptable documentation types and verification standards still needs to be clarified by the Commission.
• CALSSA supports sharing high‑level pricing models and cost structures to inform TEPC verification but opposes requirements to provide project‑specific documentation for every line item at the Incentive Claim Form stage (including indirect and financing costs), describing such requirements as impractical, difficult to evidence at a per‑project level, and potentially exposing competitively sensitive data without clear standards on how PAs would evaluate that information.

Audit, Enforcement, and Use of Existing Program Tools

• SoCalGas recommends that PAs be able to require detailed breakdowns and explanations when costs appear unreasonable or deviate significantly from earlier reports, and to use audit authority similar to SOMAH—reviewing invoices, payments, and cost justifications—to substantiate TEPC before releasing incentives.
• CSE emphasizes the need for clear definitions (such as for “consistently overstated” TEPC) to guide when strong enforcement measures like cancelling all of a developer’s waitlisted projects are appropriate, to avoid inconsistent or subjective application of penalties across PAs.
• CALSSA points to the existing SGIP infractions and warning framework in the SGIP Handbook as a basis for targeted enforcement against suspected misrepresentation of TEPC, and argues that the Commission could have used these tools to investigate specific cases rather than applying broad, program‑wide TEPC verification measures that significantly disrupt all RSSE projects.
• CALSSA raises concerns about the March 13 Ruling’s proposal to subject certain projects to random audits with a 30% or larger incentive withhold until audit completion, warning that such withholds, on top of already long payment timelines, could create severe cash‑flow pressures for developers and urges either removal of the withhold or strict timelines (such as a 30‑day audit deadline) if it is retained.

Timing, Administrative Burden, and Impacts on Low‑Income Customers

• GRID Alternatives stresses that TEPC verification processes should be designed to be timely and not overly burdensome, warning that extended review timelines or onerous documentation requirements could delay project completion, increase developer costs, and postpone resilience and bill‑saving benefits for low‑income customers who generally cannot bridge gaps if incentives are delayed.
• SoCalGas supports early engagement with applicants (at or near the reservation stage) to obtain cost breakdowns and acknowledgments of new TEPC verification requirements, with the goal of reducing downstream issues at the Incentive Claim stage and preserving low‑income participation levels by avoiding late‑stage surprises that could create customer out‑of‑pocket obligations.
• CSE argues that setting the TEPC documentation trigger at 90% of maximum SGIP incentive would substantially increase administrative workload by immediately subjecting thousands of active applications to additional review, and suggests that a higher threshold would better balance fund protection with limited administration resources.
• CALSSA reports that the February 20 and March 13 rulings have already caused substantial disruption to RSSE developers—citing layoffs, mechanics’ liens, and financial strain stemming from halted payments for projects that had already reached Reserved status—and recommends at least a six‑month extension for RSSE projects as well as more limited and clearly defined verification requirements to avoid prolonged program slowdowns.

Project Prioritization and Use of Data Accessible to Program Administrators

• SoCalGas expresses concern about the March 13 Ruling’s requirement to prioritize projects based on interconnection application date, noting that PAs who are not the servicing electric utility do not have access to that information, and recommends using the final interconnection date (already collected on the Incentive Claim Form) as the prioritization metric to avoid delays and implementation challenges tied to data PAs cannot readily obtain.

storage (LDES) accreditation, and bidding/revenue rules for CAISO’s new DAME products. This is a sampling of parties’ positions.

Transactability, Hourly Load‑Obligation Trading, and SOD Framework

• Middle River Power LLC (MRP) supports Energy Division’s recommendation not to adopt hourly load‑obligation trading (HLOT/LOT) now, arguing the incremental benefits are speculative relative to the administrative burden and operational risks, and urging the Commission to continue monitoring SOD performance before reconsidering HLOT.
• VISTRA CORP. (Vistra) contends the record does not show that SOD has impaired RA transactability, asks the Commission to reject CalCCA’s LOT proposal and WPTF’s request to continue developing it, and supports Energy Division’s focus on whether existing mechanisms allow LSEs to meet hourly SOD obligations.
• Sierra Club (with CEJA) points to Energy Division’s Transactability Report as evidence that SOD may be increasing gas contracting and underutilizing storage, and urges further Commission action on transactability mechanisms (including storage-focused trading), loading‑order compliance, and monitoring of SOD’s interaction with gas contracting.
• Ava Community Energy (Ava) argues transactability should be evaluated on cost efficiency and system utilization, not just the ability to comply, and contends the potential savings are likely understated in Energy Division’s analysis; Ava urges the Commission to either advance LOT now or clearly preserve the option for future adoption, with guardrails to manage complexity.
• CALIFORNIA COMMUNITY CHOICE ASSOCIATION (CalCCA) advocates adopting hourly load‑obligation trading for Commission‑jurisdictional LSEs, asserts Energy Division applied the wrong standard (necessity vs. cost‑effective reliability), and estimates significant annual savings; CalCCA proposes interim caps and other guardrails to limit administrative burden.
• Forward Market Design LLC (FMD) recommends creating an independent, voluntary SOD “intermediary” to coordinate obligation trades, arguing this could capture most gains from LOT while reducing validation and reporting burdens on Energy Division and LSEs.
• Pacific Gas and Electric Company (PG&E) does not directly advocate for or against LOT in these reply comments but focuses on related RA design topics (EO charging sufficiency, UCAP, and LDES timing), suggesting some transactability questions may be better addressed after foundational RA elements are aligned.

Evidence and Perspectives on SOD Impacts and Market Outcomes

• MRP agrees with Energy Division that CalCCA’s comparison of pre‑SOD (peak‑hour) and SOD‑era (24‑hour) procurement is not an apples‑to‑apples assessment, and argues it does not prove SOD has increased costs in a way that LOT would fix.
• Vistra highlights Energy Division’s empirical findings—system‑wide RA surpluses, no multi‑hour MA deficiencies, falling citation counts, and moderate MPB values—as evidence that SOD has not caused a transactability crisis or systemic inefficiency warranting LOT.
• Sierra Club emphasizes Energy Division findings that gas contracting remains high while storage is underutilized in RA showings, interprets these trends as signs SOD may be reinforcing fossil reliance, and calls for closer tracking of RA contracting by resource type.
• Ava points to individual‑LSE hourly deficiencies despite aggregate sufficiency as evidence of a structural granularity issue, and asserts Energy Division’s quantified LOT benefits (for a single month) are a conservative lower bound lacking broader month and price‑effect coverage.
• CalCCA maintains that Energy Division materially understates both excess procurement and potential LOT savings, arguing that reliance on 24x7 resources to cure narrow hourly gaps is a sign of structural inefficiency rather than desirable “conservatism.”
• PG&E notes improved RA outcomes in recent years but focuses its comments on EO and UCAP, indicating that RA cost and reliability performance should be addressed holistically, including alignment with CAISO practices.

Administrative Burden, Preconditions, and Possible Guardrails for LOT

• MRP stresses Energy Division’s finding that LOT would impose “immense” administrative burdens, and recommends three preconditions before revisiting it: (1) recalibrate PRM to achieve 0.1 LOLE directly; (2) confirm Energy Division has adequate software and staffing to process LOT‑based RA plans; and (3) update the Transactability Report after those steps are completed.
• Ava supports using guardrails such as trading caps, earlier trade‑submission deadlines, and simplified validation protocols to reduce LOT implementation costs, and requests further Energy Division analysis on the most effective administrative safeguards.
• CalCCA contends that LOT can be implemented through existing SOD templates with additional validation steps; it proposes a 25% cap on monthly traded load (with de minimis thresholds), and suggests additional staffing and automation could be justified by projected savings.
• FMD proposes that an independent SOD intermediary could perform much of the validation, matching, and data‑standardization work “upstream,” thereby mitigating Energy Division’s concerns about mismatched trades and compressed timelines while preserving bilateral contracting.
• PG&E highlights the current reliance on manual tools (e.g., Excel macros) in RA validation and cautions that any new trading construct will require significant process and system upgrades, reinforcing the need to stage reforms and address capacity constraints at Energy Division.

Environmental Outcomes, Gas Contracting, and Storage Utilization

• Sierra Club cites Energy Division’s findings of persistent gas contracting and unused contracted storage capacity as evidence SOD may not be advancing environmental and affordability goals, and urges measures such as: limited markets for unused storage, RA transparency by resource type, and loading‑order compliance demonstrations by IOUs.
• Ava echoes concerns that transactability constraints may impede cost‑effective use of storage and other clean resources, and emphasizes the importance of enabling more granular RA optimization as storage penetration increases.
• CalCCA argues that LOT would help reduce over‑reliance on 24‑hour thermal contracts, pointing to its estimate that LOT could reduce gas procurement by hundreds of MW and improve utilization of storage already under contract.
• NextEra Energy Resources, LLC (NextEra) links current charging sufficiency rules to the risk that large amounts of standalone storage and EO solar in CAISO’s queue become commercially stranded, which in its view would increase reliance on traditional resources and impede decarbonization.
• Hydrostor, Inc. (Hydrostor) stresses that accurate, inclusive accreditation for LDES within SOD is essential to realizing IRP‑driven clean reliability targets and avoiding unnecessary investment in fossil resources.

Energy‑Only (EO) Resources and Storage Charging Sufficiency

• NextEra strongly urges near‑term Commission action to allow EO solar to contribute to storage charging sufficiency, favoring broad geographic use (e.g., North/South zonal pairing) under frameworks like ACP‑CA and PG&E’s proposals and warning that delay risks stranding tens of GW of standalone storage and EO solar.
• PG&E supports modifying SOD rules on an interim basis so EO resources can meet charging sufficiency, proposes an EOQC methodology based on historical production and NP26/SP26 locational limits, and suggests SC attestations to allow Energy Division verification while containing administrative burden.
• San Diego Gas & Electric Company (SDG&E) endorses allowing EO resources to count for charging sufficiency with interim geographic restrictions (such as NP26/SP26), citing broad support and operational realities around midday charging, but stresses the need to prevent “phantom charging” where EO output cannot physically reach storage.
• California Independent System Operator Corporation (CAISO) opposes allowing EO capacity to meet charging sufficiency at this time, warns that doing so could risk undercharging storage during stressed conditions, and urges the Commission to wait for the dedicated off‑peak deliverability study in the 2026–2027 Transmission Planning Process.
• CalCCA supports crediting EO resources—especially co‑located EO solar—for charging sufficiency where consistent with POI deliverability, and views EO utilization as a way to better align RA rules with actual system operations and IRP assumptions.
• Ava does not address EO directly but supports broader reforms that facilitate more efficient use of existing resources, which could include EO‑based charging once deliverability questions are resolved.

UCAP Framework, Data Quality, and Alignment with CAISO

• NextEra supports the concept of UCAP but urges delaying binding UCAP implementation for storage and hybrids until CAISO OMS data quality issues are resolved; it favors resource‑ or fleet‑specific data where possible, best‑3‑in‑4‑years calculations, and a refresh mechanism so upgrades are fairly reflected.
• PG&E supports adopting a UCAP framework but recommends 2030 as the first compliance year, with indicative values in 2028–2029; PG&E strongly favors a single set of QC/UCAP values used by both CPUC and CAISO to avoid dual metrics and added complexity.
• SDG&E supports UCAP in principle but warns that using UCAP‑adjusted values for SOD compliance while CAISO continues to rely on NQC for supply plans would create a “dual‑compliance” regime; SDG&E recommends aligning CAISO’s Minimum Online Obligation with UCAP‑adjusted QC before UCAP becomes binding.
• CAISO emphasizes in these reply comments that it will not impose a universal storage dispatch limit based on non‑linearity, and reiterates opposition to fleetwide restrictions on RA bidding or revenue eligibility for new DAME products, which would complicate UCAP‑linked incentive signals and contract structures.
• MRP urges that UCAP exclude outages outside management control and provide mechanisms to reset UCAP after major maintenance or force majeure, and asks for clarity on co‑located gas+storage treatment to ensure consistent reliability incentives.
• Hydrostor supports resource‑specific UCAP with sufficient outage history for LDES, while cautioning against methodologies that double‑count limitations already captured in QC or SOD accreditation.

LDES and Storage Accreditation under SOD

• Hydrostor advocates adoption of the Joint LDES Parties’ accreditation methodology, which combines Initial State of Charge, Shifted Energy from prior days, SOD‑period excess energy, and resource‑specific round‑trip efficiency, arguing this approach is technology‑neutral, implementable, and necessary to support imminent LDES procurement under IRP.
• NextEra supports the Joint LDES Parties’ approach to representing multi‑day LDES in SOD showings and views it as important for accurately capturing the reliability contributions of advanced storage without over‑penalizing them via UCAP or QC adjustments.
• PG&E recommends deferring modifications to SOD specifically for LDES, asserting that the current framework can accommodate 8‑hour resources and that LDES‑specific changes should await greater experience with actual multi‑day assets.
• SDG&E highlights concerns that UCAP and SOD frameworks should avoid double‑derating storage (e.g., for foldback/non‑linearity already captured in QC), and supports an “exclusivity” rule to ensure the same physical limitation is not penalized twice.
• Sierra Club supports reforms that would increase utilization of storage contracted for RA, including potentially limited storage‑only trading mechanisms, given evidence of underused storage capacity under current SOD rules.
• CalCCA supports the Joint LDES methodology for representing multi‑day storage and stresses consistency with IRP definitions (8‑hour and longer) so LDES can be procured and valued in line with state planning targets.

DAME (IR/RC) Bidding Rules and Revenue Allocation

• PG&E supports eliminating the zero‑dollar bid requirement for reliability capacity (RC) and imbalance reserves (IR), opposes Energy Division’s proposal to mandate specific contractual revenue‑allocation language, and argues that IOU RC/IR revenues and costs should be handled in existing balancing accounts rather than a new ERRA memorandum account.
• SDG&E backs removal of the zero‑dollar bidding requirement and cautions against prescriptive rules forcing RA contracts to allocate IR/RC revenues in specific ways, citing potential for higher RA prices and reduced contractual flexibility.
• CAISO opposes fleetwide bidding restrictions and mandatory revenue splits for DAME products, argues Cal Advocates’ cost estimates for IR are speculative and based on test data, and expects that IR introduction via EDAM will reduce net costs through regional diversity.
• CalCCA opposes mandatory IR/RC revenue‑sharing requirements, arguing that contract terms should be negotiated bilaterally and that CPUC‑mandated splits could put jurisdictional LSEs at a disadvantage relative to non‑jurisdictional entities.
• Vistra favors CAISO’s approach of allowing market‑based bidding and contract‑level revenue allocation, and opposes zero‑bid or clawback rules that could distort incentives.
• MRP supports flexible RA contract arrangements for DAME products and rejects rules that would force specific revenue pass‑throughs or bid caps, viewing such prescriptive measures as unnecessary and potentially harmful to reliability.

Other RA Framework and Local/Planning Issues

• PG&E reiterates its request to eliminate the Local Capacity Requirement – Reduction Compensation Mechanism (LCR‑RCM), citing limited uptake and evidence that it has not driven incremental local preferred or storage procurement, and suggests alternative mechanisms can be considered in later tracks.
• SDG&E similarly supports eliminating LCR‑RCM to reduce administrative burden, provided existing agreements are honored, and recommends addressing broader local RA design questions in future phases.
• CalCCA opposes eliminating LCR‑RCM without a replacement mechanism, arguing that some means of compensating LSEs for local RA attributes remains important in a decentralized procurement framework.
• CAISO cautions against relying on its historical OPDA study to justify new EO charging sufficiency constructs, explaining that OPDA was not designed for RA purposes and did not examine scenarios with both deliverable and EO resources at high output, and instead points to the forthcoming TPP study as the appropriate basis for policy changes.
• FMD frames SOD obligation trading and related RA reforms as part of a broader shift to more granular, reliability‑aligned markets, and suggests that careful institutional design (such as an intermediary) can reconcile hourly RA constructs with existing monthly resource products.