Simplifying Policy Management

methodologies—including Local Capacity Requirements, Flexible Capacity Requirements, Planning Reserve Margin, and Unforced Capacity implementation details—for the 2028–2030 compliance years.

Additionally, the proceeding addresses the treatment of long-duration storage, resource accreditation, charging sufficiency, and penalty structures to ensure load-serving entities can secure sufficient reliable capacity.

Background

The Commission initiated this Rulemaking to address forward procurement obligations for load-serving entities starting with the 2027 Resource Adequacy (RA) compliance year and to consider broader reforms to the RA program.

A Scoping Memo issued on December 12, 2025, divided the issues into two tracks, with Track 1 issues resolved in Decision 26-07-008.

The Amended Scoping Memo now designates Track 2 issues.

Track 2 Issues

Track 2 issues include 2028–2030 Local Capacity Requirements (LCR), 2028 Flexible Capacity Requirements (FCR), Planning Reserve Margin/Loss of Load Expectation (PRM/LOLE), details of Unforced Capacity (UCAP) implementation, and storage accreditation and charging questions.

Schedule and Coordination

The proceeding is scheduled to conclude Track 2 by June 2027.

Coordination with the Integrated Resource Planning proceeding on the Reliable and Clean Power Procurement Program is also anticipated as needed.

Last Week's New Comment +1

In Rulemaking 25-10-003, filed October 9, 2025, Pacific Gas and Electric Company (PG&E) opposes the August 10, 2026 Motion of the Western Power Trading Forum and the Independent Energy Producers Association (WPTF/IEP) seeking a stay of Ordering Paragraph (OP) 16 of Decision 26-07-008.

Proceeding and Position

• PG&E Under Rule 11.1(e) of the California Public Utilities Commission’s Rules of Practice and Procedure, asks the Commission to promptly deny the Motion.

Irreparable Harm

• PG&E Argues that WPTF/IEP identify only speculative effects on future resource adequacy (RA) negotiations, pricing, and contracting. These potential commercial impacts are not unique to OP 16 and do not establish immediate or irreparable harm.
• WPTF/IEP Identify no imminent compliance violation, threatened penalty, loss of eligibility for existing RA contracts, or mandatory deadline requiring emergency action.
• PG&E The possibility that future contracts may be difficult to unwind is insufficient.
• PG&E Distinguishes Decision 19-12-064, which involved requirements that could immediately affect existing RA contracts before mandatory filing deadlines. Here, WPTF/IEP identify only possible effects on future agreements.

Rehearing and Balance of Harms

• PG&E Contends WPTF/IEP are unlikely to succeed on rehearing because their arguments primarily challenge policy and evidentiary determinations concerning revenues associated with Imbalance Reserve products.
• PG&E Maintains that the Commission acted within its authority and reasonably distinguished Reliability Capacity from Imbalance Reserve products.
• PG&E Further argues that a stay would create uncertainty about revenue-allocation rules applicable to ongoing RA solicitations and negotiations.
• PG&E Keeping OP 16 effective preserves a clear regulatory framework.
• PG&E Requests prompt denial of the Motion.

Upper Bounds, and Smoothing

• PG&E Supports an interim cap on GHG inputs to the Integrated Calculation because the elevated 2026–2027 Transmission Planning Process shadow prices depend on IRP assumptions that may change. PG&E seeks a longer-term containment framework informed by future CARB planning, citing affordability, volatility, and the risk that high short-term values could shape long-term DER procurement and Net Billing Tariff compensation.
• SCE Argues that the Proposed Decision leaves unresolved whether GHG values should have an upper bound and creates an imbalance by retaining floors without a corresponding ceiling. It supports a cap, smoothing mechanism, SDG&E's proposed upper bound, or another safeguard before potentially temporary shadow prices enter long-term DER compensation. SCE's alternative remains ten-year smoothing of the 2026–2027 values.
• SDG&E Maintains that the Proposed Decision addressed only whether the federal Social Cost of Carbon could be used as the cap metric, not whether GHG values should be bounded. It supports an upper bound based on California cap-and-invest valuations that would preserve previously adopted values and avoid reinstating the federal SCC cap. SDG&E opposes ten-year smoothing because it changes timing rather than total costs.
• CLECA Supports establishing a reasonable cap or smoothing mechanism, including the High SCC value as proposed by Staff, SCE, and CUE. It recommends applying any constraint to model inputs rather than calculated outputs.
• SEIA Opposes capping ACC GHG values at the High SCC or at a formula based on 2024 ACC values, arguing that a demand-side cap without a comparable supply-side constraint would undervalue demand-side resources and create inconsistencies across regulatory frameworks. SEIA views smoothing as a preferable response to volatility.
• CUE Supports a High SCC cap for electric and gas GHG values to protect ratepayers and reduce volatility.
• SoCalGas Supports interim use of the electric-sector GHG value for gas modeling while a gas-specific methodology is developed, and supports the Proposed Decision's rejection of an SCC-based cap or floor. It also recognizes that updated cost estimates could protect ratepayers if modeled values prove unrealistic.

GHG Definitions, Cap-and-Invest Treatment, and Sector Rebalancing

• PG&E Requests clarification on whether the RESOLVE shadow price represents the total GHG abatement cost or only one component, and asks the Commission to identify every GHG input used in the Integrated Calculation.
• SCE Asks the Commission to clarify that the RESOLVE shadow price represents the full avoided GHG cost and to address whether adding cap-and-invest costs results in double counting.
• SEIA States that the RESOLVE emissions-constraint shadow price does not include the CARB floor carbon price; adding both produces the total GHG abatement cost rather than double counting. SEIA supports removing the GHG rebalancing adjustment because the IRP uses fixed electric-sector GHG targets and accounts for DER penetration. It maintains that technology-specific issues involving transportation or building electrification should be addressed separately.
• CLECA Concludes that the Integrated Calculation workbook adds the cap-and-invest allowance price twice and urges correction of that error.
• CUE Supports retaining GHG rebalancing, arguing that a single GHG value does not resolve how fixed economy-wide emissions targets should be allocated among sectors. It requests additional analysis of load-reducing DERs and building and transportation electrification.

Generation-Capacity Valuation and the Capacity Floor

• PG&E Argues that high GHG values reduce the residual generation-capacity value and can weaken incentives for dispatchable and reliability-focused DERs. It supports updating generation-capacity floor inputs.
• SCE Requests correction of the generation-capacity floor to include omitted insurance and ad valorem taxes, which it estimates would increase the floor from approximately $39/kW-year to $50/kW-year. SCE states that the omission understates reliability-related DER value and would not affect IRP outcomes.
• CLECA Supports correcting the floor for omitted insurance, ad valorem taxes, and other fixed operating expenses. It also asks the Commission to assess whether the residual calculation undervalues dispatchable resources such as the Base Interruptible Program.
• SEIA Supports including current going-forward fixed operating costs for retained gas plants, including insurance and ad valorem taxes, and argues that the correction would not alter IRP results because the costs concern resources not selected in the IRP.
• SoCalGas Supports capacity valuation that reflects reliability risk, operational flexibility, resource diversity, dispatchability, and resilience during stressed or prolonged system conditions, including testing under future load-growth and electrification scenarios.

Integrated Calculation, Hybrid Resources, and Storage Duration

• SEIA Supports using GHG and capacity values together so the marginal resource can recover its costs in each year. It supports a 2028 transition from a four-hour to an eight-hour hybrid resource because four-hour additions largely end in 2028 and eight-hour storage begins expanding. If 2028 is not supported, SEIA recommends 2030.
• SDG&E Supports retaining 2028 as the transition year, emphasizing that the marginal resource is the resource selected at the margin by IRP optimization. It notes that the 2026 filing-requirements portfolio adds no further four-hour storage after 2028 while adding substantial eight-hour storage.
• CLECA Considers the 2028 transition reasonable because both solar and storage are economically selected across the IRP horizon, and supports increasing avoided generation-capacity costs when the hybrid construct would otherwise prevent standalone solar or storage from recovering costs. CLECA also favors technology-agnostic approaches that could avoid selecting a single hybrid resource.
• Cal Advocates Recommends delaying the transition to eight-hour storage from 2028 to 2031, citing the continued predominance of four-hour storage in the relevant portfolio and the absence of an earlier operational procurement mandate.
• CLECA Opposes treating the predominant existing fleet as the controlling criterion for identifying the marginal resource and notes that the Proposed Decision does not expressly adopt that criterion.

Transmission Costs and Locational Analysis

• SCE States that transmission-project selection follows Energy Division data-request instructions and is not conducted arbitrarily. SCE considers the record insufficient to adopt SEIA's proposed uniform methodology. It also explains that ending LNBA would cause the Alberhill Substation to be included through DTIM rather than LNBA.
• SEIA Requests consistent criteria and project-specific showings across investor-owned utilities when identifying marginal transmission investments and their avoidability.
• PCF Supports retaining LNBA for the 2026 ACC because DTIM lacks comparable locational detail. It requests public documentation of transmission projects considered deferrable and Energy Division review of project classifications.

Model Documentation and Stakeholder Review

• PG&E Requests clearer documentation of ACC assumptions, calculations, calibration inputs, and outputs, along with earlier publication of workpapers. It specifically seeks explanation of the solar-plus-storage hybrid resource, including its composition and relationship to RESOLVE resources and the broader IRP portfolio.
• SCE Agrees that limited data availability constrained meaningful stakeholder review and recommends a future ruling and Commission process addressing data access, timing, and participation in ACC updates.
• CLECA Requests timely draft workpapers, an interactive workshop with Energy Division staff, and earlier pre-proposal workshops with concurrent release of working models and supporting materials.
• SDG&E Requests side-by-side comparisons of revised and prior Integrated Calculation outputs and documentation of upper-bound calculations.
• SoCalGas Requests documentation of SERVM inputs, storage dispatch logic, calibration assumptions, and sensitivity analyses used to derive capacity and hourly allocation values.
• PCF Requests nonconfidential utility explanations of transmission-project inclusion and exclusion decisions, identification of projects assigned to DTIM or LNBA, and further procedural development before LNBA is eliminated.