Simplifying Policy Management

ural Objections and Timeline

BAC argues CPUC Rules of Practice and Procedure do not authorize a second Proposed Decision issued by a different ALJ. The Second Proposed Decision was not filed as an alternate under Rule 14.1(d) and Rule 14.2’s “without undue delay” standard is violated: issuance occurred more than one year after BAC’s March 2025 Petition; almost seven months after the First Proposed Decision (Sept. 18, 2025); nearly six months after comments closed; following five scheduled consent-agenda votes; over three months after the Commission terminated BioMAT; and three months after the First Proposed Decision was withdrawn from the voting agenda. BAC also faults the Second Proposed Decision for failing to reference or explain the First Proposed Decision or address party comments and public testimony.

Contradictory Timeliness Findings

The First Proposed Decision found BAC’s March 2025 Petition timely; the Second Proposed Decision reverses that conclusion without explanation, primarily adopting Cal Advocates’ position. BAC says both relied on the same facts—AB 843 implementation in 2023–2024 and the R.24-01-017 scoping memo—and the unexplained reversal is arbitrary.

Substantive Law and Requested Relief

BAC asserts termination of BioMAT violates SB 1122 obligations in Public Utilities Code section 399.20(f)(2) (250 MW collective procurement) and AB 843’s intent for CCA participation given delayed implementation. BAC asks the Commission to reject both Proposed Decisions and continue BioMAT while adopting revisions or a successor program meeting statutory requirements.

ruling applies Rule 14.3 of the Commission’s Rules of Practice and Procedure and sets the limits for party comments on a proposed decision. Each party may file one set of opening comments and one set of reply comments only.

• Opening comments are limited to 15 pages.
• Reply comments are limited to 5 pages.
• Parties may not file multiple separate comment sets in different capacities.
• Parties are reminded to review Rule 14.3(c) for the types of content that may be included in comments.

The ruling also directs the Docket Office to formally file the email ruling and notes that it was circulated to the service list.

Track 1 schedule change for FCR issues

The second ruling revises the Track 1 schedule only for Flexible Capacity Requirement issues. The change is intended to allow expedited review of CAISO’s Final 2027 FCR Report so it can potentially be incorporated into the expected proposed decision.

Under the revised schedule, parties must file and serve responsive comments on the Final FCR Report by the end of the third business day after CAISO files the report. The ruling notes that CAISO had targeted May 15, 2026, for filing the Final FCR Report.

• The previously adopted LCR schedule remains in place.
• CAISO’s draft and final LCR report comment dates are unchanged.
• The expedited FCR schedule is meant to support timely Commission consideration.

Key dates referenced in the rulings

• May 4, 2026: the comment-limit email ruling was issued and circulated.
• May 4, 2026: the schedule-modification ruling was issued.
• May 5, 2026: the rulings were formally filed.
• May 8 and May 13, 2026: existing LCR comment and reply deadlines remain in effect.
• May 15, 2026: CAISO’s targeted filing date for the Final 2027 FCR Report.

Practical impact

Overall, the rulings are procedural rather than substantive. One clarifies how parties may comment on a proposed decision, and the other adjusts timing for FCR-related filings to support the Commission’s schedule while leaving LCR timing unchanged.

deadline extension

The first ruling grants Southern California Edison, Pacific Gas and Electric, and San Diego Gas & Electric an extension of the deadline to submit workshop materials for the May 21, 2026 workshop. The utilities said they needed additional time because of the complexity of the issues and the range of views raised in comments and reply comments. The ruling notes that outreach was conducted under Rule 11.6 to gather party positions on the request.

• The original workshop-materials deadline was May 8, 2026.
• The revised deadline is May 14, 2026.
• The workshop remains scheduled for May 21, 2026.
• Support for the extension was filed by the Public Advocates Office and the Environmental Defense Fund.
• Several parties took no position, and no opposition was reported.

The ruling states that the Docket Office will formally file it.

Request for comments on Electrification Impact Study Part 2

The second ruling asks parties to comment on the Electrification Impact Study Part 2 final reports filed by the utilities on January 28, 2026. It focuses on how the study’s findings should inform the yearly Distribution Planning and Execution Process, and what additional validation or refinement may be needed before the results are used more broadly in planning.

The ruling explains that the study is intended to estimate electrification impacts and costs under multiple scenarios, including primary and secondary distribution upgrade costs. It also notes that prior Commission decisions envision initial use of the study’s findings in the 2025-2026 planning cycle, with more complete integration expected later.

Key issues raised for party input

• How the study’s findings should inform annual distribution planning.
• What each utility learned from the study and how those learnings can be used to reduce costs and improve ratepayer outcomes.
• How equity-related findings should be considered when planning grid upgrades in disadvantaged communities.
• Whether the study’s assumptions on demand flexibility and coordinated DER management are sufficiently supported for planning and forecasting.
• Whether the study’s scenarios should be treated as exploratory or used more directly in future forecasting and investment decisions.
• What methodological limitations or areas needing further validation should be addressed before broader use.
• How distributed energy storage could be modeled as a flexible grid asset and what limitations would need to be resolved first.

Submission deadlines

• Opening comments on the Electrification Impact Study Part 2 ruling are due May 29, 2026.
• Reply comments are due June 5, 2026.

The ruling directs parties to provide detailed responses and notes that the Commission expects the most complete integration of the study’s findings to be addressed in a later proposed decision and subsequent planning cycle.

issued August 17, 2020 set issues and schedule.

Key prior actions and legislative context

Notable prior decisions include D.20-10-025 (Oct. 28, 2020), D.21-06-005 (June 4, 2021), D.21-11-032 (extension to May 28, 2023), D.21-12-031 (Dec. 20, 2021 allocation of approximately $67 million to SGIP energy storage), D.22-04-036 (Apr. 11, 2022), and D.25-05-010 (May 15, 2025 extending the deadline to June 1, 2026). AB 209 (Sept. 2022) amended Public Utilities Code Section 379.6 and added Section 379.10 to direct General Fund monies into SGIP residential solar and storage incentives; an assigned-commissioner ruling on Oct. 26, 2022 sought comments on low-income outcomes and AB 209 implementation.

Reason and legal basis for extension

The Commission found additional time is required to address program closure details and that R.20-05-012 cannot be completed by the current statutory deadline of June 1, 2026. Under Public Utilities Code Section 1701.5(a), the deadline is extended to Sept. 30, 2026. The 30-day public comment period is waived per Rule 14.6(c)(4).

Administrative details

• Assigned Commissioner: Karen Douglas.
• Presiding ALJ: Hazlyn C. Fortune.

Last Week's New Ruling +1

Ruling identification and key dates

This Assigned Commissioner’s Ruling (COM/KDL/vj4) was filed and dated May 8, 2026 (filed 05/08/26 01:57 PM) in Rulemaking 20-05-012 regarding SGIP policies, procedures and rules. It implements direction in the Assigned Commissioner’s Ruling issued March 13, 2026 and is signed by Karen Douglas, Assigned Commissioner, dated May 8, 2026.

Primary directive to Program Administrators (PAs)

PAs shall resume incentive payments for completed RSSE projects once three conditions are met: (1) ICF approval, (2) developer submission of complete cost documentation, and (3) developer submission of the Supplemental Cost Verification Form, consistent with the March 13, 2026 ACR. PAs must collect cost verification documentation per prior rulings and the SGIP Handbook (2026).

Scope and limitations on PA review before payment

PAs will perform a compliance check to confirm required documentation is submitted but will not conduct cost verification prior to payment. The Commission will use statutory audit authority to review cost verification and TEPC compliance for selected audits, enabling prompt payments with post-payment accountability.

Audit program and publication of results

UAB will conduct post-installation audits under Public Utilities Code Sections 314, 314.5, and 314.6 and GAGAS. UAB reports may be posted on its reports page, the proceeding docket, and www.selfgenca.com. Sanctions include suspension, expulsion, or cancellation per SGIP Handbook (2026) Section 14.2.

Instructions and disposition

PAs must implement resumed payment processes consistent with the March 13, 2026 ACR. Developers must submit complete cost documentation and Supplemental Cost Verification Forms and retain records for UAB audits. The ruling (dated May 8, 2026, San Francisco) directs collection of cost verification, payment upon meeting conditions, UAB audits of TEPC, and posting of audit results.

and bill-credit design

• City and County of San Francisco and the Joint CCAs say the CRE program is not viable without external funding sources and that the PD does not adequately explain how customer bill discounts will be calculated or recovered under the adopted framework.
• TURN urges the Commission to reject the PD or substantially revise it, arguing the proposed CREP design is economically unworkable because ReMAT-based compensation would not finance projects or attract developers, especially if it must also support subscriber bill credits.
• PG&E says ReMAT is a viable foundation for CRE and points to continued developer interest in its service territory as evidence that current ReMAT price levels can support project financing and development.
• PG&E also argues CRE should move forward now because it is intended to promote accessibility and affordability without shifting costs to nonparticipants.
• SEIA and CCSA, as referenced by other parties, are cited as supporting concerns that the current ReMAT-based structure is not financeable under present conditions.

Implementation process and advice letters

• SCE supports the PD’s approach of deferring unresolved implementation questions to the advice letter process and asks for a Tier 3 implementation advice letter for CRE within 90 days of the final decision.
• SCE says this approach is consistent with GO 96-B and allows stakeholder input without requiring additional litigation in the main proceeding.
• PG&E similarly supports moving ahead with CRE implementation using the existing ReMAT platform rather than waiting for broader tariff redesign.
• TURN argues the PD’s design issues are too substantive and controversial to be left unresolved if they will prevent a workable program.
• City and County of San Francisco and the Joint CCAs seek implementation flexibility for CCAs and request timely procedural mechanisms for participation and program administration.

Cost recovery, bill credits, and PPP funding

• City and County of San Francisco and the Joint CCAs ask the Commission to ensure consistent Public Purpose Program (PPP) cost-recovery treatment for CCAs and investor-owned utilities if program administrators are allowed to recover CRE-related implementation and outreach costs.
• They also support retaining PPP funding for DAC-GT under Public Utilities Code section 748.5(c) and ask for clarification that Community Solar Green Tariff funding will be administered consistently with that statute.
• SCE argues PPP funds may be used to cover DAC-GT shortfalls and incidental CRE implementation costs, and asks for authority to create a CREPBA subaccount through advice letter filing.
• PG&E seeks authorization to open CRE subaccounts within balancing accounts to track implementation, administration, marketing, education, and outreach costs, with recovery through the PPP charge.
• TURN argues the statute prohibits nonparticipating customers from being charged program costs above avoided costs, particularly if the program does not generate actual subscriptions.

Low-income participation and statutory compliance

• TURN says the PD does not provide a workable mechanism for meaningful low-income participation and argues it fails to reconcile the 51 percent low-income capacity requirement with the proposed bill-credit structure.
• PG&E supports low-income participation but opposes expanding low-income eligibility to small commercial customers, saying the statute does not require that result.
• SCE argues the statute’s restrictions cited by opponents do not bar using PPP funding for DAC-GT and incidental CRE costs, and that ReMAT contracts remain consistent with avoided-cost pricing.
• City and County of San Francisco and the Joint CCAs say the Commission should address the unresolved bill-credit and funding issues before implementation.

ReMAT, pricing mechanics, and resource value

• PG&E says continued contract activity shows ReMAT can support development and that broader ReMAT redesign issues are outside the scope of this proceeding.
• TURN disputes that ReMAT is financeable for CREP under the PD and says splitting ReMAT value between project revenues and customer bill credits would make financing infeasible.
• TURN also argues the PD does not preserve additionality if CREP energy and renewable credits can be used for RPS compliance.
• PG&E rejects attempts to relitigate CRE resource value and says the Commission already addressed that issue in earlier decisions.

Related Green Access Program issues: MGT, DAC-GT, and DG Stats

• City and County of San Francisco and the Joint CCAs support retaining ERRA-based recovery for Modified Green Tariff administrative costs and oppose SDG&E’s proposal to require a separate Tier 2 advice letter process.
• SCE supports using advice letters to establish accounting mechanisms for CRE and MGT-related costs and opposes SDG&E’s proposed participation-based allocation for DG Stats co-funding.
• PG&E seeks explicit accounting authority for CRE costs and supports using ReMAT and existing utility processes to move implementation forward.
• TURN argues the PD cannot justify recovering CRE implementation costs from nonparticipants absent actual avoided costs and subscriptions.

This week, the record also adds utility proposals to streamline screens and reporting, along with technology-specific comments from Ford on bidirectional EV use cases.

Screen Q / Screen R changes and study process alignment

• SDG&E proposes consolidating and strengthening Screen L to use the latest CAISO transmission study outputs and an export-based threshold, and says Screen Q should be eliminated as redundant.
• SDG&E argues the change would reduce serial studies, avoid Rule 21/WDAT reapplication delays, and better align Rule 21 with CAISO and wholesale interconnection processes.
• SCE says no Commission-mandated change to Screens Q or R is needed now and supports continuing its interim Screen Q methodology, which it says has reduced failure rates and avoided unnecessary cluster studies.
• SCE also maintains Screen R is reasonable as currently applied.
• Cal Advocates does not propose specific technical changes to Screens Q and R at this stage, but says any change should follow cost-causation principles so upgrade costs are not socialized across ratepayers.
• Pioneer supports reevaluating Screens Q and R and backs reforms that would reduce unnecessary failures and delays, including possible interim threshold adjustments.
• Ford takes no position on modifying Screens Q and R.
• From last week, SEIA continued to argue that Screen Q has become inconsistent across utilities and should be revised, while CalCCA supported raising the Screen Q exemption threshold and AEU supported streamlined treatment for non-export and other non-grid-parallel configurations.
• From last week, PG&E supported a narrower Screen Q refinement tied to both DFAX and flow-impact thresholds, and CESA supported an alternative cost-responsibility pathway for projects that fail Screen Q but do not individually trigger upgrades.

Interconnection timelines, benchmarks, and reporting

• SDG&E says the D.20-09-035 timelines are reasonable, but recommends retiring ongoing OP 22 and OP 28 reporting and shifting to issue-specific requests instead of recurring compliance reports.
• SDG&E opposes expanding timelines or eligibility categories and says additional reporting adds cost without clear benefit.
• SCE also finds the D.20-09-035 timelines reasonable, but asks for clarification of the 95% benchmark and recommends removing several low-value reporting metrics to simplify compliance reporting.
• SCE says the 95% benchmark should be understood as a population-level goal, not a per-milestone enforcement standard, and suggests workshops before any punitive framework is adopted.
• Pioneer argues that timelines are only part of the problem and wants enforceable compliance mechanisms, including financial penalties tied to IOU-caused delays and stronger protections for projects that risk losing program eligibility.
• Ford supports process improvements that reduce customer friction and suggests tracking additional metrics for site visits, customer time spent on applications, and application type.
• Cal Advocates supports improved timelines and transparency, but says any added requirements should not require incremental ratepayer funding outside the GRC process.
• From last week, SEIA, CalCCA, AEU, IREC, and CESA all continued to press for stronger accountability, with proposals ranging from refined 95% compliance standards to fines, citations, performance incentives, and real-time tracking.

Non-NEM / non-NBT interconnection fees

• SDG&E says the current $800 fee may not cover actual processing costs for many non-NEM projects, but it wants a data-driven review before proposing any fee changes.
• SCE similarly says the current fee structure should be studied through a recurring cost-reporting process, then updated through advice letter filings as needed.
• Cal Advocates says fees should reflect actual cost of service, be transparent and fair, and include an escalation mechanism so fees keep pace with inflation and changing costs.
• Ford argues the fee structure should distinguish between backup-only systems and bidirectional EV systems, and says backup-only notification should not carry a fee while bidirectional EV systems should face lower, cost-reflective charges than other DERs.
• Pioneer does not offer a cost estimate, but says it will only support fee differences if they are tied to the level of review required rather than the resource type alone.
• From last week, SEIA, CalCCA, and PG&E all supported revisiting non-NEM fees, while Tesla and VGIC argued the current flat fee is too high for smaller residential-scale or bidirectional charging projects.

Treatment of backup-only, bidirectional EV, and other emerging configurations

• Ford says Rule 21 and fee treatment should be clearer for backup power systems and bidirectional EV use cases, and points to recent Commission clarification that isolated, non-parallel operation should not be treated the same as momentary parallel operation.
• Ford also says confusion remains in utility practice and warns that backup-only customers should not be routed through interconnection processes intended for grid-parallel systems.
• Pioneer says reforms should not discriminate by resource type, but may reflect differences in review burden if screening changes actually streamline processing.
• From last week, VGIC and Tesla continued to call for more explicit tracking and more proportionate treatment of bidirectional charging, storage, and other newer DER configurations, while AEU supported clearer paths for non-export and other non-grid-parallel resources.

Cost allocation, ratepayer protection, and implementation approach

• SDG&E says its proposed screening consolidation should not materially raise costs and should reduce duplicate studies and unnecessary tariff transitions.
• SCE says existing cost-allocation mechanisms already align with cost causation and argues that removing electrically independent projects from cluster studies does not shift reliability upgrade costs to ratepayers.
• Cal Advocates emphasizes that cost-causation should govern across all Phase 1 issues and warns against reforms that could socialize costs to ratepayers.
• Pioneer wants IOU accountability measures to be funded by shareholders, not ratepayers, and argues compensation should go to applicants harmed by utility-caused delays.
• Ford says interconnection requirements should stay proportionate to actual utility effort and system impact.

Broader continuity from last week’s record

• Last week’s filings already showed a split between parties seeking more aggressive reforms to Screen Q, stronger enforcement of interconnection timelines, and lower or more tailored fees for smaller or emerging DERs.
• This week’s comments largely build on those same issues, with SDG&E and SCE focusing on how to simplify screening and reporting, Pioneer pressing for enforceable accountability, and Cal Advocates emphasizing ratepayer protection and cost-causation.
• The new filings also add more explicit discussion of bidirectional EVs and backup-only systems, which were a smaller part of last week’s record.

process reforms. Some parties favor more prescriptive statewide changes now, while others prefer a narrower approach focused on utility-specific performance, data maturity, and existing statutory frameworks.

Energization timeline compliance, remedial actions, and enforcement

• Southern California Edison Company says the Phase 1 energization targets were intended as planning goals, not rigid compliance deadlines, and urges the Commission to wait for additional biannual reporting before reassessing targets or ordering remedies. SCE recommends remedial actions only for persistent or material noncompliance and proposes an energization-specific enforcement policy layered onto Resolution M-4846 with progressive penalties tied to failure to comply with remedial actions.
• Pacific Gas and Electric Company 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. PG&E supports corrective action plans if an IOU is out of compliance, but says remedies should focus on root causes and that it is too early to prescribe new enforcement structures beyond clarifying how Resolution M-4846 applies to energization timelines.
• Local Government Sustainable Energy Coalition says the current average energization goal is too slow and should be replaced with faster, more protective standards for essential public projects. LGSEC supports automatic, non-discretionary remedial actions for missed deadlines and favors performance-based enforcement tools such as liquidated damages, shareholder-funded penalties, and utility performance-based incentives.
• San Francisco Bay Area Planning and Urban Research Association says Phase 2 should examine performance-based incentives and clearer enforcement tied to building electrification outcomes. SPUR supports an enforcement approach that holds utilities accountable for missed timelines and rewards better performance.
• Coalition of California Utility Employees says the Commission should require detailed staffing analyses and allow stakeholder review so utilities can be held accountable for supporting timely energization without sacrificing other work or safety.
• The Interstate Renewable Energy Council, Inc. says the current framework is not enough to show whether utilities are energizing projects at the pace and locations needed for state climate goals. 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, not planning exercises, 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.
• California Broadband & Video Association says current energization delays continue to harm broadband deployment and urges stronger monitoring and enforcement, including faster timelines and auditor oversight of delay-reported projects.
• Environmental Defense Fund 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.
• SOUTHERN CALIFORNIA TRIBAL CHAIRMAN ASSOCIATIONS (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.
• Natural Resources Defense Council 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)

• Southern California Edison Company says Section 935(a) should be implemented as an annual workforce report filed by March 31, with content limited to the statute’s text. SCE argues the report should not be expanded and says biannual workforce reporting would add burden without much added value.
• Pacific Gas and Electric Company 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 the Commission chooses to consider broader content through notice and comment.
• Coalition of California Utility Employees 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, with stakeholder review.
• Local Government Sustainable Energy Coalition says workforce reports should be geographically granular so local shortages are visible, and that the Commission should adopt a standardized Section 935(a) compliance template.
• Clean Coalition says the auditor and workforce reporting process should identify whether utilities have enough internal staffing, data systems, and analytical capability to manage energization timelines at lower long-term cost.
• Environmental Defense Fund says current workforce filings are insufficient and should explain how staffing forecasts align with energization targets and future electrification demand.
• Natural Resources Defense Council says utilities must show that staffing levels are adequate to meet both request volume and timeline targets in light of California’s decarbonization goals.
• SOUTHERN CALIFORNIA TRIBAL CHAIRMAN ASSOCIATIONS (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, cost recovery, and SB 254/SB 410 coordination

• Southern California Edison Company says Large IOUs should not be required to jointly retain one auditor and should instead use competitive procurement to select independent auditors under SB 254. SCE says audit costs are compliance costs and should be recoverable in rates.
• Pacific Gas and Electric Company 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.
• Local Government Sustainable Energy Coalition says independent audits should be funded by utilities, not ratepayers, and that the Commission should retain auditor selection authority. LGSEC also wants auditors to review cost-effectiveness of non-wires alternatives and DER options.
• Coalition of California Utility Employees says the current filings are incomplete on staffing and workforce topics, and its position supports stronger independent review of utility workforce sufficiency.
• The Interstate Renewable Energy Council, Inc. says SB 254 auditors should review report-based compliance and that the Commission should eventually use that audit framework to support a citation program. IREC also wants auditors to help track geographic deployment gaps.
• Clean Coalition says SB 254 auditor review should cover utility data systems, analytics, automation, and staffing capability, and should lead to corrective action plans where deficiencies are found.
• California Broadband & Video Association says SB 254 auditors should actively track and report on delay-reported projects and be physically present at key utility offices to identify bottlenecks.
• Environmental Defense Fund says utilities should avoid duplicative audits where SB 410 and SB 254 overlap, and recommends a single auditor per utility where cost recovery is allowed. EDF says audit recommendations should be specific and subject to stakeholder comment.
• SOUTHERN CALIFORNIA TRIBAL CHAIRMAN ASSOCIATIONS (SCTCA) says auditors should have Tribal competency, access to Tribal communications, and a role in verifying compliance with Tribal remedial actions. SCTCA also says utility-funded audits should not be recovered from ratepayers.

Standardization, reporting templates, and process improvements

• Southern California Edison Company says the Commission should not impose additional standardization beyond the existing eight-step energization process and instead should refine biannual reporting templates to better align with that framework.
• Pacific Gas and Electric Company 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.
• Local Government Sustainable Energy Coalition supports a statewide application portal, standardized performance metrics, and a binding shot-clock and transparent ticketing system with non-extendable deadlines for each energization step.
• San Francisco Bay Area Planning and Urban Research Association says the Commission should create a centralized, public-facing energization dashboard that aggregates utility data in a comparable format across IOUs.
• The Interstate Renewable Energy Council, Inc. 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 treat timelines as meaningful standards and pair them with reporting that shows root causes, staffing, process, and cost-control performance.
• California Broadband & Video Association 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.
• Environmental Defense Fund 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.
• SOUTHERN CALIFORNIA TRIBAL CHAIRMAN ASSOCIATIONS (SCTCA) says Tribal projects should have a standardized statewide application portal, a Tribal Energization Office at each IOU, and real-time monitoring tools that show where projects stand.
• Natural Resources Defense Council 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 geographic targeting

• Local Government Sustainable Energy Coalition says essential public projects, including clinics, shelters, affordable housing, and grant-driven projects, should receive expedited energization and, where needed, IOU-financed temporary clean DERs as a stopgap.
• San Francisco Bay Area Planning and Urban Research Association 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.
• The Interstate Renewable Energy Council, Inc. says the Commission should focus first on EV charging because the forecast and inventory data are more mature, and because geographic concentration of demand makes a pace-of-energization framework more actionable.
• California Broadband & Video Association 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.
• SOUTHERN CALIFORNIA TRIBAL CHAIRMAN ASSOCIATIONS (SCTCA) says Tribal projects, especially housing, health, and water, should be given priority processing and should receive alternative service options when traditional grid service cannot meet deadlines.
• Natural Resources Defense Council says upstream capacity constraints are a major factor in energization delays and should be addressed in any forward-looking timeline and remedial framework.