Simplifying Policy Management

to conditions creating the need. The Decision allocates pro rata by current managed peak load (OP 1 and OP 6), which Rehearing Parties say ignores the DA Cap and Section 365.1 prohibition on ESPs serving incremental load driving the need. They urge application of the ordinary-meaning test and cite California Supreme Court guidance limiting deference to CPUC statutory interpretations.

Cost Shifting, Precedent, and Reliability

Rehearing Parties cite Sections 454.52, 366.2(d)(1), 365.2, and 366.3 to argue the Decision shifts growth-driven costs to DA customers who did not cause them, contrary to cost-causation principles and precedents (e.g., D.22-05-015, D.23-04-040). Staff’s Sept. 30, 2025 sensitivity did not analyze a flat-load scenario; the Decision did not rely on lower-load sensitivity. The DA Cap prevents existing DA accounts from serving incremental growth absent statute.

Requested Relief and Urgency

Rehearing Parties seek rehearing and revision to reallocate 2030–2032 obligations consistent with Section 397 and the DA Cap using administrable methods (forward-looking load adders, separate treatment of discrete load types, or assigning obligations to LSEs serving incremental load with true-ups). Expedited rehearing is requested to avoid unlawful cost shifting, contracting uncertainty, and irreversible financial burdens.

arguing the June 12, 2026 draft deadline conflicts with two other compliance filings and imposes significant burdens.

Relevant dates and schedule comparisons

The ACR was issued March 27, 2026; draft annual RPS plans are due June 12, 2026. RPS plan templates have been available since the first week of April 2026. By comparison, last year’s analogous ruling was issued April 17, 2025 with draft plans due June 30, 2025 (10 weeks and two business days); the 2026 schedule affords 11 full weeks.

Guidance to parties

RPS Plans’ format and requirements remain substantially unchanged from 2025. Parties may update 2025 RPS plans to conform with the 2026 ACR rather than prepare entirely new documents; Energy Division staff will consider such updated 2025 plans acceptable for 2026 review. The denial is effective as ruled on May 11, 2026 by ALJ Darryl Gruen.

Questions and issues

Key open issues are whether parties will proceed by updating 2025 plans and how they will manage concurrence of the June 12, 2026 deadline with the two other compliance filings cited in the April 22, 2026 communication.

filings add more detail on SB 254 implementation and auditor guardrails, as well as project-level energization clarity for housing development.

Energization timeline compliance, remedial actions, and enforcement

• Cal Advocates recommends that the Commission rely on IOU energization reports, independent SB 254 auditor reports, and party comments to decide when remedial action is needed, while keeping discretion to order remedies when IOUs exceed the average energization timelines established in D.24-09-020.
• Cal Advocates proposes allowing a period equal to the applicable average end-to-end timeline for improvement, then evaluating the next SB 254 auditor report; if noncompliance continues, penalties would be imposed by category based on days exceeded and IOU size.
• Cal Advocates supports penalties under Section 934(g) if an IOU still exceeds timelines after remedial action, with shareholder-funded penalties paid into IOU-specific accounts for energization work.
• HAC says energization timelines should be communicated in a clear, project-specific way with defined dates, reasonable timeframes, and enforceable remedial actions, especially for affordable housing projects that depend on financing and regulatory deadlines.
• HAC recommends the Commission consider triggering remedial actions when an IOU misses a communicated project energization target date and evaluating project-specific consequences when delays materially affect housing delivery.
• SCE says the Phase 1 energization targets were planning goals rather than rigid deadlines and urges the Commission to wait for additional biannual reporting before revisiting targets or adopting broader remedies.
• SCE supports remedial actions only for persistent or material noncompliance and prefers an energization-specific enforcement policy with progressive penalties tied to failure to comply with remedial actions.
• PG&E says the Commission should use the existing compliance framework in D.24-09-020, including step-level reporting that distinguishes utility-controlled and external delays, and should focus remedies on root causes.
• PG&E supports corrective action plans if an IOU is out of compliance but says it is too early to adopt new enforcement structures beyond clarifying how Resolution M-4846 applies to energization timelines.
• LGSEC supports automatic, non-discretionary remedial action for missed deadlines and favors performance-based enforcement tools such as liquidated damages, shareholder-funded penalties, and utility performance-based incentives.
• SPUR supports an enforcement approach that holds utilities accountable for missed timelines and rewards better performance.
• IREC recommends a citation-based enforcement program using biannual report metrics, with penalties that escalate based on the degree of noncompliance.
• Clean Coalition says adopted timelines should function as enforceable standards and that remedial action should be ordered when utilities consistently miss timelines, fail to keep pace with new applications, or fail to implement needed staffing, data, or process improvements.
• EDF says the Commission should set clear remedial-action triggers, require utilities to submit outcome-oriented corrective plans, and use existing enforcement authority for noncompliance with Commission-directed remedies.
• SCTCA says the Commission should adopt firm energization deadlines and automatic remedial action for Tribal and disadvantaged-community projects, with shareholder-funded credits or temporary power if utilities miss deadlines.
• NRDC says the Commission should define clear remedial-action thresholds for sustained underperformance and require corrective measures when utilities repeatedly miss targets or fail to implement prior remedies.

Reporting, staffing, and Section 935(a)

• Cal Advocates proposes more detailed Section 935(a) reporting, including standardized staffing and apprenticeship data, 10 years of historical internal and external labor counts, four-year forecasts, explanations for deviations, sourcing plans, apprenticeship hiring history, and alignment of GRC requests with staffing plans.
• Cal Advocates says recent Section 935(a) reports lack historic, ratio, forecast, and apprenticeship detail, making it harder to assess progress toward SB 410 goals.
• SCE says Section 935(a) should be implemented as an annual workforce report filed by March 31 and limited to the statute’s text.
• SCE argues that biannual workforce reporting would add burden without much added value.
• PG&E says workforce analysis should be reviewed in each utility’s general rate case and that this proceeding should clarify only the timing and cadence of Section 935(a) filings unless broader content is noticed for comment.
• CCUE says the IOUs’ current workforce reports do not satisfy Section 935(a) and that the Commission should require detailed, evidence-based staffing analyses in annual energization reports and GRC applications.
• LGSEC supports geographically granular workforce reports and a standardized Section 935(a) compliance template.
• Clean Coalition says the reporting process should identify whether utilities have enough internal staffing, data systems, and analytical capability to manage energization timelines at lower long-term cost.
• EDF says current workforce filings are insufficient and should explain how staffing forecasts align with energization targets and future electrification demand.
• NRDC says utilities must show staffing levels are adequate to meet both request volume and timeline targets in light of California’s decarbonization goals.
• SCTCA says workforce reporting should include rural and Tribal staffing information, and that missed Tribal energization targets should lead to stronger local apprentice pipelines and hiring of Tribal members.

Auditor selection, independence, and SB 254 / SB 410 coordination

• Cal Advocates says the Commission should retain oversight over SB 254 implementation and can use auditor reports, IOU reports, and party comments to evaluate remedial action and enforcement needs.
• Cal Advocates raises concerns that PG&E’s contracting and interactions with EY may have compromised auditor independence by allowing the utility to influence reporting requirements, draft reports, and meeting structure.
• Cal Advocates urges the Commission to require Energy Division review of auditor contracts, attendance at auditor-IOU meetings, limits on pre-publication IOU edits, attachment of contracts and work plans to biannual reports, a formal comment process, and compliance with Public Utilities Code Sections 940(b) and 940(c).
• Cal Advocates says the Commission may allow the same auditor to perform SB 254 and SB 410 work for a large IOU only if the independence protections apply to both frameworks; otherwise separate auditors should be required.
• Cal Advocates also argues ratepayers should not fund SB 254 auditor costs.
• SCE says large IOUs should not be required to jointly retain one auditor and should instead use competitive procurement to select independent SB 254 auditors.
• SCE says auditor costs are compliance costs and should be recoverable in rates.
• PG&E also opposes a single joint auditor and prefers to retain its existing SB 410 auditor where possible.
• PG&E says auditor costs required by statute or Commission action should generally be recoverable from ratepayers.
• LGSEC says independent audits should be funded by utilities, not ratepayers, and that the Commission should retain auditor selection authority.
• EDF recommends avoiding duplicative audits where SB 410 and SB 254 overlap and supports a single auditor per utility where cost recovery is allowed.
• SCTCA says auditors should have Tribal competency and access to Tribal communications, and that utility-funded audits should not be recovered from ratepayers.

Standardization, reporting templates, and process improvements

• SCE says the Commission should not impose additional standardization beyond the existing eight-step energization process and should instead refine biannual reporting templates to better align with that framework.
• PG&E supports targeted standardization of definitions, data requirements, and reporting conventions, but says more prescriptive operational standardization is premature.
• PG&E also asks the Commission to remove or revise reporting fields it considers infeasible, duplicative, or not useful.
• LGSEC supports a statewide application portal, standardized performance metrics, and a binding shot-clock with transparent ticketing and non-extendable deadlines for each energization step.
• SPUR says the Commission should create a centralized, public-facing energization dashboard that aggregates utility data in a comparable format across IOUs.
• IREC proposes a “pace-of-energization” framework, starting with EV charging, that combines forecasted need, deployed inventory, and IOU pipeline data in a geographic scorecard.
• Clean Coalition says the Commission should pair meaningful timelines with reporting that shows root causes, staffing, process, and cost-control performance.
• CBVA says reporting should measure project time from initial application through final completion so delays are not masked by application rejections or in-progress project exclusions.
• EDF says utilities and stakeholders should develop a methodology for translating statewide electrification needs into energization timeline targets and should update those targets as performance improves.
• SCTCA says Tribal projects should have a standardized statewide application portal, a Tribal Energization Office at each IOU, and real-time monitoring tools showing project status.
• NRDC says the Commission should require stronger transparency into project status, standardized application and review elements, and stage-specific delay identification.

Priority projects, alternative service, and project-specific clarity

• HAC says clear, predictable project-level energization dates are especially important for affordable housing developments that rely on tax credit equity, loans, rate locks, and regulatory milestones.
• HAC says system-level targets alone are not enough and that the Commission should require project-specific communication of energization dates and changes to those dates.
• HAC recommends standardizing customer-facing timelines, milestone tracking, and consequences for missing stated energization dates to reduce uncertainty for developers and lenders.
• LGSEC says essential public projects, including clinics, shelters, affordable housing, and grant-driven projects, should receive expedited energization and, where needed, temporary clean DERs as a stopgap.
• SPUR says the Commission should examine Rule 15 and Rule 16 changes that would allow non-traditional technologies, such as at-the-meter power control systems, to be used for service upgrades.
• IREC says the Commission should focus first on EV charging because the forecast and inventory data are more mature and the geographic concentration of demand makes a pace-of-energization framework more actionable.
• CBVA says broadband deployment projects need a shorter 90-day energization timeline because grant deadlines are time-sensitive and the current process is too slow for funded builds.
• SCTCA says Tribal projects, especially housing, health, and water, should receive priority processing and alternative service options when traditional grid service cannot meet deadlines.
• NRDC says upstream capacity constraints are a major factor in energization delays and should be addressed in any forward-looking timeline and remedial framework.

Workshop will be held in person at the Commission’s headquarters, 505 Van Ness Ave, San Francisco, over three days in June 2026. The workshop is intended to help shape the scope and schedule for Track 3, including substantive topics, sequencing, and related procedural issues. Commissioners or their advisors may attend, but no action will be taken.

• Day 1: June 8, 2026, 1:00 PM to approximately 4:00 PM
• Day 2: June 9, 2026, 9:00 AM to approximately 1:00 PM
• Day 3: June 15, 2026, 10:00 AM to approximately 3:00 PM
• Specific room assignments and agendas will be sent to the service list before the workshop

Workshop topics and party guidance

Parties should be prepared to discuss principles and possible approaches for achieving indifference, alternative indifference frameworks, issues proposed for inclusion in Track 3, and data access and confidentiality concerns. On the second day, parties are expected to focus on scheduling and scoping considerations for proposed issues. On the third day, the discussion is expected to include confidentiality and data access issues, along with any remaining items from earlier sessions.

Track 2 evidentiary hearing notice and schedule

The hearing ruling gives notice of an evidentiary hearing on Track 2 issues and explains the related preparation steps. The hearing is scheduled for June 2, 2026, and is intended to address testimony and cross-examination related to the Staff Report and proposals concerning pre-2019 banked renewable energy credits. The ruling also reflects earlier schedule changes, including the cancellation of an April 28 hearing date and a procedure allowing parties to respond with testimony before briefing.

• Parties were asked to indicate by May 26, 2026 whether they want the June 2 hearing to proceed
• If the hearing goes forward, cross-examination is expected to follow the witness order proposed by the parties
• The hearing is set for a virtual format with a full-day schedule and built-in breaks

Participant registration and hearing logistics

Parties planning to participate actively must email the required speaker information by May 28, 2026. The ruling also provides Webex and phone access details, technical contact information, and instructions for logging in early to resolve any connectivity issues before the hearing begins.

• Parties must provide names of speakers, roles, email addresses, phone numbers, and related identifying information
• Technical issues during the hearing are to be directed to the hearing support contact identified in the ruling
• Participants are instructed to be prepared for a prompt start and to follow the stated ground rules for virtual proceedings

Conduct and ground rules for the hearing

The ruling sets expectations for orderly conduct during the virtual hearing. These include muting when not speaking, identifying oneself for the record, speaking clearly, avoiding interruptions, and making objections in a way that preserves the record. The ruling also requires parties and witnesses to affirm that they will not engage in private communications about the subject matter while witnesses are under examination.

Transcripts, exhibits, and motions

The ruling includes detailed deadlines for transcripts and exhibit handling. Parties seeking expedited or daily transcripts must notify the Chief Hearing Reporter at least three days before the hearing. Final exhibits are due by May 28, 2026, with impeachment exhibits due by the morning of June 2, 2026. The ruling also requires motions for admission of exhibits after the hearing, along with a later deadline for objections to those motions.

• Final exhibits must be served and uploaded by May 28, 2026
• Impeachment exhibits must be served and uploaded by 8:30 a.m. on June 2, 2026
• Motions for admission are due by June 5, 2026
• Objections to admission are due by June 10, 2026

Exhibit log and cross-examination coordination

The ruling requires coordination among parties on the order of witnesses and cross-examination estimates. It also directs PG&E to update the exhibit log used in the case management materials and to circulate the final proposed version by June 2, 2026, or identify an alternate if needed by May 28, 2026. Parties are expected to work together on a cross-examination matrix that identifies witnesses, appearance order, and estimated time for each examination.

Confidential materials and procedural questions

Parties should avoid discussing confidential materials in the public hearing unless advance notice is given so that a confidential session can be arranged. Any party anticipating that need must notify the ALJ, hearing support staff, and the service list at least one business day in advance and provide an authorized participant list. The ruling also asks parties to raise any additional procedural questions to the full service list before the hearing so they can be addressed efficiently.

Key deadlines at a glance

• May 26, 2026: deadline to request that the June 2 hearing proceed
• May 28, 2026: deadline for participant registration information, cross-examination matrix, final exhibits, and any alternate exhibit log designation
• June 2, 2026: virtual evidentiary hearing date; impeachment exhibits due by 8:30 a.m.
• June 5, 2026: motions for admission of exhibits due
• June 10, 2026: objections to exhibit admission due
• June 8, 9, and 15, 2026: Track 3 Planning Workshop dates

within one year of issuance of D.20-08-043. D.20-08-043 set the BioMAT end date as December 31, 2025.

Key dates and actions

• Petition filed: March 6, 2025 (BAC).
• AB 843 (authorizing community choice aggregators to participate in BioMAT) signed by the Governor: September 23, 2021.
• Commission action closing the proceeding and issuing the order: May 14, 2026 (San Francisco).

Findings of fact

• BAC filed the petition more than four years after D.20-08-043 became effective.
• AB 843 expanded participation in BioMAT and was enacted on September 23, 2021.
• The Commission previously indicated on April 6, 2023, that Rulemaking (R.) 18-07-003 was the appropriate venue for considering changes to the BioMAT sunset date.
• BAC did not provide sufficient justification for delaying the petition.

Conclusions of law

• The petition fails the timeliness requirement of Rule 16.4 and therefore must be denied.
• Rulemaking R.18-07-003 is to be closed.

Order

• The March 6, 2025 petition to modify D.20-08-043 is denied.
• R.18-07-003 is closed.
• The order is effective May 14, 2026.

Additional notes

• Commissioner Matthew Baker recused himself from consideration of this agenda item and did not participate in the quorum.
• An attachment referenced is a redline document for R.18-07-003 (file name noted in the decision).

but there was substantial disagreement over whether to use a single cross-sector GHG value, whether to cap avoided GHG values at the social cost of carbon, and whether additional workpapers and review should be required before adoption.

GHG valuation changes

• NRDC opposed applying the electric-sector GHG value to the gas sector and argued that a uniform value could understate the marginal cost of gas-sector decarbonization; NRDC also opposed capping avoided GHG values at the SCC, citing concerns about consistency with supply-side treatment and state decarbonization goals.
• SCE supported capping avoided GHG values at the High SCC, but also recommended retaining a distinct gas-sector avoided GHG value rather than replacing it with the electric-sector value.
• PG&E supported a single GHG value across electric and gas sectors in principle and supported removing GHG rebalancing, but recommended that any cap be tied to CARB Scoping Plan-aligned marginal costs rather than the SCC alone.
• SoCalGas supported temporary alignment of the gas ACC GHG value with the electric ACC value until a gas-specific adder is developed, and opposed capping avoided GHG value at the SCC without a broader policy process.
• CUE supported capping total GHG value at the High SCC, but opposed using the electric-sector value as the gas-sector value and opposed removing GHG rebalancing.
• BayREN and 3C-REN opposed the proposed lower gas GHG value, opposed the SCC cap, and urged deferral of the GHG methodology changes until Track 3 resolves ACC guiding principles.
• CAL ADVOCATES opposed applying the electric-sector GHG value to natural gas, opposed adopting the SCC as an upper limit at this stage, and supported retaining GHG rebalancing if separate sector values remain.
• SEIA supported eliminating GHG rebalancing and supported capping the GHG component at the High SCC, with the caveat that the SCC should be regularly updated.
• CLECA said it had no position yet on the single-value or rebalancing changes, but supported a GHG cap and said the Base SCC should be used for that cap rather than an unsupported selection of the High SCC.

Integrated calculation of generation capacity and GHG values

• SCE supported the shift to an Excel-based integrated calculation and asked for a side-by-side comparison with the prior method using common inputs.
• PG&E generally supported the simplified integrated calculation approach and said it would reduce complexity and improve transparency.
• CAL ADVOCATES supported the integrated-calculation refinement, subject to full workpapers and model outputs, and said the Excel-based approach could improve transparency.
• SEIA said it was not opposed to the new Excel IC, but raised concerns about volatility, smoothing, storage transition assumptions, and the need to incorporate additional resources and disclose more workpapers.
• CUE said the change is methodological rather than merely a platform update, and requested the workbook, benchmark model, sensitivity runs, and detailed comparisons before adoption.
• CLECA argued the proposed 2x2 approach is structurally limited and can distort results, and recommended a broader linear-programming or multi-pair approach using the full IRP resource panel.

Hourly allocation of generation capacity value

• PG&E supported using Loss of Load Hours instead of Expected Unserved Energy, using energy prices instead of temperature to identify high-value days, and distinguishing weekday and weekend reliability risk.
• SCE supported the move to Loss of Load Hours, the use of energy prices to identify high-capacity-value days, and differentiating weekday and weekend risk, while noting the need to review the underlying model details.
• CAL ADVOCATES supported these changes subject to review and asked for published comparisons and workpapers.
• SEIA said the conceptual changes were generally reasonable but could not support adoption without the underlying calculations and workpapers.
• CUE said the energy-price-based day identification was directionally reasonable, but asked for more analysis on how the loss-of-load and weekday/weekend changes would affect different resource types.
• SDG&E supported all three proposed refinements, including LOLH, energy-price-based day selection, and weekday/weekend differentiation.
• SBUA agreed that reliability risk is shifting beyond the hottest summer days, but asked for deeper analysis of the new method and for the proposal to explicitly address additional reliability risks and to test an alternative LOLE assumption.

Transmission capacity allocation

• CAL ADVOCATES supported, subject to further review, the shift from historical load-based transmission allocation factors to IEPR load forecasts.
• SEIA said the proposed transmission allocation changes were directionally understandable, but it could not support adoption without the workpapers and year-by-year comparisons.
• CUE said the concept was reasonable, but requested full 8,760-hour outputs, the IEPR forecast version, and DER-specific impact tables before adoption.

Transparency, timing, and process

• Several parties emphasized the need for additional workpapers, benchmark comparisons, and time to review the revised model before final adoption, including CAL ADVOCATES, SEIA, CUE, CLECA, and SCE.
• CLECA said the proposal should include more stakeholder review, additional written comments, and, if needed, hearings, because the ACC affects downstream cost-effectiveness determinations.
• SEIA and CUE both said the compressed comment schedule limited meaningful review of the new Excel-based materials.
• BayREN and 3C-REN urged deferral of major policy choices until Track 3 resolves ACC guiding principles.