Simplifying Policy Management

data access, settlement, and public participation.

Additionally, the proceeding aims to identify near-term refinements and explore alternative frameworks to improve consistency, reduce volatility, and achieve statutory requirements for customer indifference.

Background

The Commission initiated Rulemaking R.25-02-005 in February 2025 to update ERRA and PCIA policies and processes.

A prehearing conference was held in April 2025, with Track 1 addressing RA MPB issues, which were resolved by Decision D.25-06-049.

A second prehearing conference in January 2026 launched Track 2, focusing on the valuation of Pre-2019 banked RECs, which remains ongoing.

In July 2026, a Track 3 planning workshop was held to define remaining issues.

The Second Amended Scoping Memo now sets the scope and schedule for Tracks 3 and 4, while preserving earlier rulings.

Procurement Obligations.

Key dates and actions

• Energy Division distributed the Loss of Load Expectation Study for 2028: Draft Results to the service list on August 14, 2026.
• ALJ issued and filed the ruling on August 17, 2026, in San Francisco, California.
• The ruling formally directs that “Energy Division’s Loss of Load Expectation Study for 2028: Draft Results is attached to this ruling as Appendix A.”

Document status

Appendix A is the draft LOLE Study for 2028 and is the sole attachment specified by the ruling. The ruling does not otherwise amend the record or set new procedural schedules.

Guidance for parties

The ruling contains no additional procedural guidelines, deadlines, or specific questions for parties beyond distributing the draft study. Parties should consult Appendix A and the broader Rulemaking 25-10-003 record for next steps, requests for comment, or related procedural requirements.

Last Week's New Comments +2

The August 17, 2026 comments summarize August 14 filings by CalCCA and ACP-California on the 2028 LOLE study and PRM methodology in CPUC Rulemaking R.25-10-003. CalCCA proposes a least-cost, model-based approach to setting PRMs and eliminating the effective PRM, while ACP-California focuses on potential overstatement of neighboring-region imports and resources in LOLE modeling. This is a sampling of parties' positions.

LOLE and PRM methodology

• CalCCA Proposes using monthly risk-reserve curves generated from probabilistic PLEXOS simulations and a constrained optimization that selects PRMs meeting an annual 0.1 LOLE standard at least cost. The proposal evaluates monthly, annual-cost, and single-annual-PRM approaches and does not yet recommend one option.

Modeling assumptions and reliability inputs

• CalCCA Uses Commission inputs for load, weather and load uncertainty, operating reserves, resource outages, storage, renewable and hydro production, and a fixed 4,000 MW of imports. CalCCA reports that its 2028 baseline simulation produced no annual LOLE events.
• ACP-California Raises concerns that the 2024 WECC Anchor Dataset includes planned resources that were later canceled and that adding Perfect Capacity to neighboring regions may create artificial energy or capacity availability during stressed conditions.

Treatment of imports and neighboring-region resources

• ACP-California Argues that reliance on unspecified and uncontracted imports, including modeled levels approaching 10 GW during some off-peak periods and 4 GW during on-peak periods, could understate CAISO capacity needs and produce a PRM that does not satisfy the applicable reliability requirement. It requests a sensitivity study comparing Commission-jurisdictional load with CAISO resources serving those loads and contracted, specified imports, excluding unspecified or uncontracted imports and external build assumptions.

Effective PRM

• CalCCA Recommends eliminating the effective PRM established in D.21-03-056 and replacing it with one standard PRM for all LSEs based on robust LOLE modeling. It argues that the effective PRM can increase RA costs, distort procurement incentives, permit deviations from the 0.1 LOLE standard, disadvantage non-IOU LSEs, limit CAISO backstop effectiveness, and constrain CCA procurement autonomy.

Risk-reserve curve construction

• CalCCA Creates monthly risk-reserve curves by progressively removing capacity through modeled Negative Operating Units, rerunning reliability simulations, and pairing accredited capacity with resulting LOLE outcomes. It treats the Negative Operating Unit as a supply reduction rather than an increase in CAISO demand and fits the resulting points using monotonic spline interpolation.

on the Scoping Memo. This is a sampling of parties' positions.

Proceeding context and purpose of the filings

• EPUC and Indicated Shippers Filed August 18 comments on the Joint IOU Risk Tolerance Survey pursuant to D.25-08-032 and the July 20, 2026 Scoping Memo. The survey was intended to examine how risk tolerance is established, quantified, and applied across specified industries and within the utilities, to inform potential integration of risk tolerance into the Risk-Based Decision-Making Framework.
• MGRA Filed August 19 comments on the Joint IOU Survey to supplement its industry-wide framing with utility- and ratepayer-specific considerations, particularly the relationship between risk mitigation costs and customers’ ability and willingness to pay.
• EPUC and Indicated Shippers Filed August 21 comments responding to Cal Advocates’ August 5 motion seeking clarification of deadlines for opening and reply comments on the Scoping Memo.

Assessment of the Joint IOU survey

• EPUC and Indicated Shippers Conclude that the survey largely does not satisfy the substantive objectives of D.25-08-032 because it provides mainly high-level, qualitative and bibliographic descriptions rather than actionable quantitative benchmarks, examples, and decision criteria.
• MGRA Views the survey as generally reasonable and well-cited and considers it a useful starting point, but finds it incomplete on utility-specific issues, especially the role of ratepayer costs and constraints.

Quantitative thresholds and comparative analysis

• EPUC and Indicated Shippers Identify a lack of numerical risk tolerances, thresholds, metrics, and decision rules across most surveyed industries, with limited exceptions involving nuclear and dam-related examples. They contend that naming regulators or industry bodies without reporting their actual criteria leaves the Commission to conduct the research the survey was intended to provide.
• EPUC and Indicated Shippers Challenge the survey’s characterization of commercial aviation and nuclear activities as especially analogous to electric utilities, asserting that it does not compare relevant attributes such as mobility, impact radius, energy and consequence concentration, or population concentration.

Objectivity and treatment of risk attitude

• EPUC and Indicated Shippers Contend that the survey includes advocacy favoring tail-risk weighting over risk-neutral or expected-value approaches, including repeated assertions that public utility commissions do not mandate risk-neutral treatment of catastrophic events. They also argue that the survey does not adequately explain how regulatory funding denials affect utilities’ internal risk-tolerance decisions.
• MGRA Emphasizes that risk attitude, including risk aversion and the weighting of tail or uncertain risks, is distinct from risk tolerance, which concerns thresholds and limits. It notes that different utilities use different risk-scaling functions and argues that the proceeding should address whose function is applied.

ALARP, F-N curves, and tolerability

• EPUC and Indicated Shippers Find that the survey references ALARP in the chemical, mining, and oil and gas sectors without explaining how tolerability thresholds, cost-benefit considerations, affordability, assumption of risk, or rate impacts are addressed. They also contend that the survey omits discussion of ALARP and F-N or societal-risk tools used in the dam sector despite citing materials that discuss those methods.
• MGRA Notes that the survey’s ALARP materials distinguish intolerable, tolerable, and acceptable risk regions, but observes that the cited chart focuses on avoided fatalities and may imply that some risks are intolerable regardless of cost while others require no further mitigation. MGRA uses this discussion to underscore the distinction between risk weighting and risk thresholds.

Affordability and ratepayer perspectives

• EPUC and Indicated Shippers State that affordability, identified as central to the RDF OIR and D.25-08-032, receives virtually no treatment in the survey. They argue that the omission limits the survey’s usefulness for evaluating tradeoffs between safety improvements and customer rate impacts.
• MGRA Identifies ratepayer willingness and ability to pay as the principal gap in the survey. Because utilities generally recover mitigation costs from customers, MGRA argues that risk tolerance must account for who pays, differing customer exposures, and the ability of customers to absorb additional costs. It further states that socioeconomic status includes both willingness and ability to pay and that unaffordable mitigation may force customers to tolerate higher risks without reducing their risk aversion.
• MGRA Argues that the California Public Utilities Code requirement to provide safe service at reasonable cost constrains utility risk appetite and reflects societal expectations. It also distinguishes concentrated wildfire exposure for wildland-urban interface residents from risks distributed across the broader ratepayer base.

Gas-sector coverage

• EPUC and Indicated Shippers Contend that the survey is disproportionately electric-focused and gives insufficient attention to natural gas transmission and distribution risk metrics and practices, despite the participation of SoCalGas. They recommend adding gas-sector information to create a more balanced record.

Requested survey corrections and additional information

• EPUC and Indicated Shippers Support the ALJ’s August 11 ruling requiring additional information from the Joint IOUs and urge further direction requiring industry-by-industry quantitative thresholds, a comparative asset and exposure matrix, disclosure of how funding denials affect internal risk decisions, fuller treatment of ALARP and affordability, discussion of dam-sector F-N and ALARP practices, and expanded gas-sector coverage.

Procedural schedule for Scoping Memo comments

• EPUC and Indicated Shippers Support Cal Advocates’ motion to clarify deadlines for opening and reply comments on the Scoping Memo. They state that explicit dates would align the Scoping Memo with the RDF OIR, allow parties to address scope and schedule, and support an orderly record.

sampling of parties' positions.

Integrated Calculation and Generation Capacity Valuation

• SEIA Supports the goal of a more robust ACC but argues that using a single hybrid solar-plus-storage marginal resource creates inaccurate outcomes for standalone solar and storage. It recommends increasing avoided generation-capacity values in years when either standalone resource would not recover costs, and correcting technical issues left unresolved by the Proposed Decision.
• CLECA Opposes relying on a single solar-plus-storage hybrid to represent the marginal resource because RESOLVE selects a broader portfolio, including demand response, rather than constructing hybrids. It recommends basing the Integrated Calculation on the full IRP resource mix.
• PG&E Argues that the revised residual calculation can allow high GHG values to suppress generation-capacity avoided costs toward the floor, weakening incentives for dispatchable and reliability-focused DERs. It requests a more balanced treatment of GHG and reliability values.
• SoCalGas Supports refinements to the integrated capacity and GHG calculations but recommends that capacity value reflect reliability risk, operational flexibility, resource diversity, dispatchability, and resilience during stressed or prolonged conditions. It also asks for testing under future load-growth and electrification scenarios.

Generation Capacity Floor and Retained Gas Plant Costs

• SEIA Requests that the floor on avoided generation-capacity costs use current going-forward fixed O&M costs for retained natural-gas plants, including insurance and ad valorem taxes.
• CLECA Characterizes the omission of insurance and ad valorem taxes as a narrow, record-supported error and estimates that correcting it would increase the floor from approximately $39/kW-year to $64/kW-year in 2022 dollars.

GHG Avoided-Cost Caps, Smoothing, and Sector Treatment

• PG&E Requests an interim cap on GHG values used as Integrated Calculation inputs to reduce volatility and prevent high GHG values from displacing reliability value. For the longer term, it recommends developing a cap and valuation method informed by CARB’s next Scoping Plan, with a goal of implementation in the 2028 ACC.
• SDG&E Supports rejecting the federal Societal Cost of Carbon as the cap metric but argues that the Proposed Decision leaves unresolved whether any upper bound is needed. It proposes an upper bound based on the lower of eight times the cap-and-invest allowance price forecast or that forecast plus $226.07 per metric ton, while retaining the RESOLVE shadow price below those ceilings.
• SCE Supports a cost-containment mechanism for sharply increased near-term GHG values. It prefers a High SCC cap, but alternatively proposes a 10-year smoothing period for the 2026–2027 TPP GHG shadow prices. SCE also asks the Commission to clarify that the RESOLVE shadow price represents the full avoided GHG cost and should not be added to cap-and-trade costs.
• CUE Supports capping total electric and gas GHG values at the High SCC to protect ratepayers and limit volatility. It opposes applying a single electric-sector GHG value to gas DERs and recommends retaining separate sector values or developing an economy-wide methodology through cross-sector analysis.
• SoCalGas Supports interim use of the electric-sector GHG value for both models because no durable gas-sector methodology has yet been developed, but seeks a gas-specific methodology in an appropriate forum. It supports the Proposed Decision’s rejection of an SCC-based cap or floor.

GHG Rebalancing and Electrification Impacts

• CUE Urges retaining the GHG rebalancing component, arguing that applying a single GHG value does not resolve how fixed economy-wide emissions targets should be allocated across sectors. It requests separate analysis of impacts on load-reducing DERs, building electrification, and transportation electrification if rebalancing is removed.
• PG&E States that elevated GHG values could increase the apparent cost of incremental electricity use and make transportation and building electrification programs appear less cost-effective, particularly when added consumption occurs outside system-stress periods.

Avoided Transmission Cost Methodology and Locational Analysis

• SEIA Accepts DTIM as an appropriate methodology for marginal transmission costs but asks SCE and SDG&E to use criteria and project-specific showings comparable to PG&E’s when identifying capacity-related and avoidable transmission investments.
• PCF Urges retaining the LNBA for the 2026 ACC because DTIM lacks locational granularity and a more detailed successor methodology is still under development. It also requests public documentation of projects considered deferrable and Energy Division review of project classifications.

Storage-Duration Transition Year

• Cal Advocates Argues that the Proposed Decision’s selection of 2028 for shifting from four-hour to eight-hour storage is inconsistent with IRP selections and utility procurement plans, which continue to favor four-hour storage through 2031. It recommends using 2031 as the switch year.

Model Documentation and Stakeholder Transparency

• SoCalGas Requests documentation of SERVM inputs, storage dispatch logic, calibration assumptions, and sensitivity analyses used to derive capacity and hourly allocation values.
• SDG&E Requests that Energy Division publish a side-by-side comparison of revised and prior Integrated Calculation outputs with the draft 2026 ACC, along with documentation of any upper-bound calculations.
• CLECA Requests timely publication of draft ACC workpapers, an interactive workshop allowing direct questioning of Energy Division staff, and earlier pre-proposal workshops with concurrent release of working models and supporting materials in future ACC cycles.
• PCF Requests nonconfidential utility explanations of transmission-project inclusion and exclusion decisions, identification of which projects are assigned to DTIM or LNBA, and additional procedural development before eliminating LNBA.

Corrections to the Proposed Decision’s Party-Position Summaries

• SDG&E Requests textual corrections stating that it neither endorsed nor opposed adopting a GHG cap, but opposed using the federal SCC as the cap metric. It also asks the Commission to correct passages describing its positions on reliability allocation and energy-price refinements.