Simplifying Policy Management

Commission’s Energy Division, the California Energy Storage Alliance (CESA), Cal Advocates, Pacific Gas and Electric (PG&E), Southern California Edison (SCE), California Community Choice Association (CalCCA), central procurement entities (CPE), investor-owned utilities (IOUs), and load-serving entities (LSEs). The proceeding remains open for implementation details.

Adopted Numeric Requirements and Timing

• The Commission approves CAISO’s LCR study results as the existing capacity needed by local area: 23,618 MW for 2027, 24,545 MW for 2028, and 25,480 MW for 2029. (Order items 1–3)
• CAISO’s systemwide Flexible Capacity Requirements for 2027 are adopted. (Order item 4)
• The UCAP framework is adopted and will be effective for the 2028 RA compliance year. Several implementation items for UCAP remain to be resolved. (Order item 13)

Qualifying Capacity and Storage Treatment

• Storage QC methodology: Adopted formula defines QC as (MAX_CONT_ENERGY_LIMIT − MIN_CONT_ENERGY_LIMIT) / 4, constrained by Point of Interconnection (POI) limits. The QC value is the continuous output level for four or more hours without nonlinearity (foldback). Energy Division will incorporate a continuous energy value unaffected by foldback when available. (Order item 6)
• Master Resource Database (MRD) revisions: MRD fields will add a duration column and change the default “Maximum Continuous Energy” to the MAX−MIN difference from the CAISO Master File; Energy Division may adjust MRD field names for clarity. (Order item 7)
• Foldback and EFORd: Energy Division’s approach to reflect foldback in expected Equivalent Forced Outage Rate during Demand (EFORd) and UCAP values is adopted to more accurately capture storage behavior. (Findings 4, 16; Conclusions 14, 15)
• Co-located energy-only (EO) resources: Excess energy from a co-located EO resource may count toward off-site charging sufficiency in hours when storage is not shown, up to POI limits. Commission finds POI studies support this. (Findings 6; Conclusions 9; Order item 8)

Long-Duration Energy Storage

• LDES definition: Any storage resource capable of discharging continuously at maximum capacity for at least eight hours is defined as LDES. (Finding 7; Conclusion 6; Order item 9)
• Charging sufficiency multipliers: Beginning with the 2027 RA compliance year, LDES charging sufficiency may be shown across the full 24-hour Slice of Day using a Forward Charge Period multiplier that increases with duration:
  • ≥8–<12 h → ×2
  • ≥12–<16 h → ×3
  • ≥16–<20 h → ×4
  • ≥20–<24 h → ×5
  • ≥24–<48 h → ×6
  • ≥48–<72 h → ×7
  • ≥72+ → ×8
  (Order item 10)
• Closed-loop pumped storage hydropower (PSH) will be treated like LDES for charging sufficiency, effective 2027. (Order item 11)

Demand Response Slice-of-Day Valuation

• Energy Division’s Slice-of-Day (SOD) QC valuation for DR is adopted to avoid transactable capacity stranding identified for 2026–2027. The Commission will provide CAISO three values for DR visibility: maximum showing, peak showing, and the average of hourly MW within the Availability Assessment Hour window for event hours only, excluding any non-event hour. PG&E’s modification—to average event hours only when a non-event hour exists—is adopted. The Commission urges CAISO to develop a 24-hour SOD framework for a long-term solution. (Findings 10–11; Conclusion 10; Order item 12)

Unforced Capacity Framework and Related Decisions

• Energy Division’s UCAP principles are adopted. Unit-specific UCAP values begin in 2028 using Option 1 (class average EFORd for new units then transition to unit-specific historical EFORd when available). Forced outage is defined broadly to include equipment failure and other conditions preventing full Pmax. Energy Division may adjust Nature of Work (NOW) codes included or excluded in EFORd per UCAP principles. (Findings 12–18; Conclusions 12–17; Order item 13)
• Outstanding UCAP implementation issues to be resolved include incorporation into Slice of Day for storage, basis for must-offer obligations when UCAP replaces QC, CAISO tariff/BPM changes, EFORd rates for storage energy components, UCAP for hybrid storage, foldback during the 5th RA Measurement Hour, and UCAP interaction with flexible RA. These items remain open. (Order item 14)

Bidding, Revenue Allocation, and CAISO Products

• The Commission affirms that Reliability Capacity (RC), Residual Unit Commitment (RUC) components (RCU/RCD), and Imbalance Reserve (IR) products are part of CAISO’s RUC/RC/IR constructs and treats IR products as capacity products for RA purposes. D.05-10-042 bidding and revenue rules (zero-dollar capacity offers; resource owners not eligible for capacity payments) remain in force and apply to IR products. The Commission will monitor EDAM/CAISO market impacts on RC/IR pricing. (Findings 21–26; Conclusion 18; Order item 15)
• IOUs must begin providing detailed monthly IR and RC cost, price, revenue, and dispute data for bundled customers in Quarterly Compliance Reports and at Procurement Review Group meetings for at least three years beginning with Q3 2026 reporting. (Order item 16)

Load Forecasting, Reporting, and CPE Data

• “Changes to approved implementation plans” is clarified to include voluntary effective-date changes even if not resubmitted for approval. PG&E’s clarification is adopted. (Finding 29; Conclusion 21; Order item 17)
• Large-load reporting: IOUs must provide CCAs with expected customer interconnection information at or before the year-ahead forecast meet-and-confer process and include new or expanding large customers in year-ahead forecasts (Form 3). This interim requirement is effective for the 2028 RA year. (Findings 30–31; Conclusions 22–23; Order item 18)
• Energy Division’s formalized SOD load forecast summary (Appendix A) is adopted. (Findings 31; Conclusion 23; Order item 19)
• The Commission authorizes publishing the CPE data request file on the Commission’s RA website, per D.24-12-003. CPEs must use aggregated local RA data to assess whether contracted capacity (CPE + LSE contracts) meets local needs, including sub-LCA and storage charging limits. CPE procurement determinations and demonstration in Annual Compliance Reports are effective beginning in the 2027 CPE procurement cycle. (Findings 32–33; Conclusions 24–25; Order items 20–21)

RA Penalty Structure for Charging Sufficiency

• Energy Division’s modification converts an MWh charging sufficiency deficiency into a 24-hour flat-profile MW equivalent only at the deficiency-notice stage, preserving shown capacity and excess charging energy separately. The three-step process—calculate MWh shortfall, convert to 24-hour MW equivalent, and apply proportional adder across 24 hours with largest-hour basis for penalty—is effective for the 2027 RA year. (Findings 34; Conclusions 26; Order item 22)

Additional Adopted Rules and Effective Dates

• Extension of the off-peak import counting rule to future Q3 months beyond 2026 is adopted. (Finding 35; Conclusion 27; Order item 23)
• Energy Division will verify under-construction resources’ flex-eligibility via the MRD during year-ahead compliance; resources not in the year-ahead MRD will not count for flexible RA. This applies beginning with the 2027 RA year. (Findings 36; Conclusion 28; Order item 24)
• Most rules are effective immediately unless otherwise stated. The UCAP framework becomes effective for the 2028 compliance year; specific data reporting begins Q3 2026; several charging, LDES, and co-located resource rules take effect beginning in the 2027 compliance year.

Open Implementation Items

• UCAP operational details, including storage SOD treatment, must-offer obligations, storage energy component EFORd rates, hybrid storage UCAP, foldback in the 5th RA Measurement Hour, and UCAP interaction with flexible RA, remain under active consideration.
• CAISO’s development of a long-term DR SOD and 24-hour methodology remains open.
• Further monitoring of EDAM/CAISO impacts on RC/IR pricing will continue.
• The proceeding remains open to finalize these details.

2026; Mar. 23, 2026; May 12, 2026; May 22, 2026; and May 28, 2026. The Exhibit List Table formally marks exhibits from CalCCA, Joint IOUs (Pacific Gas and Electric Company, Southern California Edison Company, San Diego Gas & Electric Company), and Cal Advocates (examples include CCA-01 through CCA-22, JIOU-01 through JIOU-08, CalAdv-01/01C/02). Parties may raise corrections to the Exhibit List at the start of the hearing; ALJ will address needed corrections.

Cross-examination exhibit requirements

Each cross-examination exhibit must have a sponsoring witness identified before use, counsel may sponsor if able to attest to authenticity, or parties may stipulate on the record to authenticity prior to use. ALJ will request sponsoring witnesses or stipulations at the hearing outset.

Attestations and admission process

Attorneys and witnesses must make specified attestations on record (consent to Webex, oath procedures, prohibition on recordings/coaching, use only pre-marked and previously shared exhibits). Exhibit admission is intended to be resolved by paper motions after the hearing; may be addressed at the hearing end if time permits. The Docket Office will file the ruling.

revised Staff Proposal modifies the Integrated Calculation proposed for the 2026 ACC to address output issues identified with the previously proposed Integrated Calculation. It also revises the avoided transmission cost calculation for Southern California Edison to use only a Discounted Total Investment Method (DTIM) approach rather than the prior combined DTIM and Locational Net Benefits Analysis calculation.

Instructions and deadlines

Parties must file opening comments answering specified questions by June 19, 2026, and reply comments by June 26, 2026. The Ruling directs that responses be “as detailed and complete as possible.”

Questions for parties

• Do you support the proposed refinements to the Integrated Calculation model? Why or why not?
• Do you support the proposed refinement to the Avoided Transmission Cost Calculation? Why or why not?
• Do you have other recommendations for the Integrated Calculation model or the Avoided Transmission Cost Calculation?

Procedural context and disposition

Issued in Order Instituting Rulemaking to Consider Distributed Energy Resource Program Cost-Effectiveness Issues, Data Access and Use, and Equipment Performance Standards (R.22-11-013). IT IS RULED that opening comments are due June 19, 2026, and reply comments due June 26, 2026.

EIS Part 2 should be used in planning

• PG&E said EIS Part 2 should function as a directional, policy-level stress test and help inform least-regrets planning, but should not be used as a direct DPEP input until assumptions are validated.
• SCE said the study results are directional but not investment-grade, and should be used to improve planning methods rather than replace existing distribution planning processes.
• SDG&E said EIS Part 2 offers directional insight but should not supplant the existing Distribution Planning Process, which it said can incorporate new inputs over time.
• Cal Advocates said EIS Part 2 scenario outputs should not be used as direct planning inputs and recommended that DPEP not be changed directly because of the study.
• CalCCA said EIS Part 2 can be useful only after assumptions and methods are refined, and it should not affect the 2027-2028 DPEP cycle until then.
• EDF said the study should inform DPEP because it shows load flexibility can reduce peak load and defer upgrades in constrained areas, but it should not directly drive individual investment decisions.
• VGIC said the Commission should begin incorporating EIS Part 2 findings into yearly DPEP cycles now, especially for transportation electrification and flexible load management.
• SBUA supported using EIS Part 2 as a planning input, while emphasizing that forecasts should remain “no-regrets” and “least-regrets” oriented.
• Clean Coalition said the reports show flexibility has measurable value and should be treated as a locational, procured planning resource rather than as a generalized scenario assumption.

Reliability of demand flexibility assumptions and the role of new data

• PG&E said current demand flexibility assumptions are forward-looking and not yet reliable enough for planning use, and need better forecasting, verification, and orchestration frameworks.
• SCE said further modeling refinement is unlikely to resolve the core uncertainty because the study assumptions were simplified and were never intended to be investment-grade inputs; it said implementation pilots and real-world performance data are the better next step.
• SDG&E said demand flexibility assumptions are not yet sufficiently supported by current data for reliable planning or cost forecasting.
• Cal Advocates said the demand flexibility scenario is hypothetical and should not be incorporated into DPEP or given a validation timeline for planning use.
• CalCCA said demand flexibility assumptions must be refined and tested against evolving policy and program developments before they are used in DPEP.
• EDF said there is enough data for conservative assumptions, but the utility analyses need refinement and should explicitly include specific flexibility solutions such as flexible service connections.
• VGIC argued that demand flexibility should be incorporated into planning now, including managed charging and bidirectional EV capabilities, because the studies already show meaningful peak reductions and cost savings.
• SBUA supported further validation of orchestration strategies and said flexible load options should be pursued carefully to avoid unintended impacts.
• SCE said EV-enabled flexibility, including V2G and bidirectional charging, is still too nascent to be treated as a reliable planning assumption because large-scale Commission-approved programs do not yet exist.

Clean Coalition’s locational flexibility and “Energy Tetris” planning framework

• Clean Coalition said the EIS Part 2 results support its “Energy Tetris” framework, under which electrification load, DER deployment, distribution constraints, and infrastructure investments should be planned together.
• Clean Coalition said the Commission should require IOUs to create a locational flexibility planning case in the Distribution Planning Process, Grid Needs Assessment, and Distribution Deferral Opportunity Report.
• Clean Coalition said IOUs should evaluate local deferral value, model achievable flexibility instead of relying only on historical DR participation, and require DER portfolios to compete with wires solutions where they can meet the same need reliably and precisely.
• Clean Coalition said DER portfolios should be value-stacked across distribution deferral, resource adequacy, resilience, transmission avoidance, customer savings, and emissions reductions, rather than evaluated in narrow single-purpose program silos.
• Clean Coalition said the main planning reform needed is to map new loads to the circuits and substations where constraints will arise and then test whether flexibility, storage, managed charging, flexible interconnection, and DERMS dispatch can avoid or defer upgrades.

Treatment of DERs, storage, and other flexible resources

• PG&E said flexible grid asset modeling should advance through EPIC 4.08, with more work needed on performance assumptions, measurement and verification, and orchestration capabilities.
• SCE said distributed storage may be represented either in load forecasting or as a solution, but that validation, dispatchability, and enabling infrastructure remain key limitations.
• SDG&E said the IEPR already accounts for behind-the-meter storage as a load modifier, and that additional distributed storage would need clear program design and cost-effectiveness evidence before it could defer infrastructure.
• Cal Advocates said PG&E’s secondary-system findings should not be adopted for regulatory planning and raised concerns about PG&E’s modeling of service transformer overloads.
• CalCCA said the IOUs’ modeling approaches differ materially and should be reconciled before EIS Part 2 methods are used in DPEP.
• SBUA supported including distributed storage as a flexible grid asset, but said deployment timelines and usage patterns need more study before storage can be relied on as a firm planning resource.
• Clean Coalition said DERs should be treated as capital resources that can deliver stacked benefits, including local distribution deferral, resilience, transmission cost avoidance, and electrification enablement.

Requested next steps and implementation emphasis

• SCE said the better next step is to focus on implementation pilots and data collection to produce empirical foundations for future planning assumptions, rather than continued refinement of the study’s assumptions as the primary path forward.
• PG&E asked that EIS Part 2 continue to be used as a directional input while tools and data for incorporating flexibility into planning are further developed.
• SDG&E said additional demand response impacts should continue through the CEC IEPR pathway unless there is a separate programmatic basis for more direct planning treatment.
• CalCCA recommended updating assumptions and methods through workshops and stakeholder review before any EIS Part 2-derived changes affect DPEP.
• EDF urged the Commission to require more regular updates to conservative, evidence-based flexibility assumptions and to improve reporting on energization timelines.
• VGIC urged the Commission to treat EIS Part 2 as an actionable planning resource, particularly for transportation electrification and managed charging.

a customer reporting procedure for energization delays, and potential modification for utilities with 100,000 or fewer service connections. The proceeding was categorized as quasi-legislative under Pub. Util. Code Section 1701.5(a), with an initial statutory deadline of June 25, 2026.

Key Procedural Actions and Dates

• March 24, 2024: Scoping Memo and Ruling issued.
• October 4, 2024: PG&E filed motion to revise 2025–2026 energization cost caps.
• October 18, 2024: Amended Scoping Memo created a separate ratesetting track.
• February 7, 2025: ALJ ruling modified schedule; March 6, 2025 reply deadline.
• July 24, 2025: Decision 25-07-025 extended deadline to June 25, 2026.
• September 19, 2025: Governor signed SB 254, adding new requirements.
• March 19, 2026: Amended Phase 2 Scoping Memo issued; party comments due May 22, 2026.

Extension, Waiver, and Assignments

The Commission finds completion by June 25, 2026 impossible given the May 22, 2026 comment deadline and SB 254 requirements. Pursuant to Pub. Util. Code Section 1701.2(i), the deadline is extended to May 31, 2027. Under Rule 14.6(c)(4), the 30-day public review/comment period for such extensions is waived. Assigned Commissioner: John Reynolds; Assigned ALJ: Andrew Dugowson. The order is effective on the date signed in 2026 in Sacramento.

Last Week's New Comments +6

Overview

This is a sampling of parties’ positions in CPUC Rulemaking 24-01-018. This week’s filings continue last week’s discussion of whether the Commission should treat energization timelines as enforceable compliance obligations, how quickly remedial actions and penalties should be applied, what reporting and transparency requirements are appropriate, and how SB 254 auditor processes should be structured. The newer comments also add more detail on data standardization, pipeline triage, and how to handle process changes for upstream capacity, MPUs, and other project types.

This digest incorporates both last week’s and this week’s comments where relevant and reflects that the proceeding continues to focus on implementation of D.24-09-020 and SB 254-related enforcement, reporting, and audit issues.

Whether energization timelines are enforceable and when remedial action should begin

• CalCCA says the Phase 1 energization timelines are enforceable obligations, not aspirational goals, and the Commission should adopt an RA-like enforcement framework with meaningful penalties tied to customer harm.
• SEIA likewise argues the timelines in D.24-09-020 are mandatory compliance requirements and says remedial actions should be triggered promptly, without waiting for prolonged patterns of noncompliance.
• Cal Advocates says the Commission should use compliance tools to protect ratepayers and should not defer remedial action where IOU performance problems are already clear from the record.
• PG&E says the Phase 1 framework should remain centered on the existing maximum-target / 5% exceedance standard and that remedial action should follow project-level cause analysis rather than averages alone.
• SDG&E says Section 934(d) requires an evidence-based determination that remedial action is “necessary,” and it opposes automatic or near-automatic remedial triggers based on average timelines.
• IREC says the current average-target language should be clarified as a compliance obligation and that missing the average target in a reporting period should trigger formal compliance review and enforcement.
• TURN and EDF, as reflected in last week’s filings, support using reported performance shortfalls as triggers for corrective action and favor stronger accountability when delays persist.

How penalties and remedial costs should be assigned

• Cal Advocates says SB 254-related audits, remedial actions, and penalties should be funded by shareholders, not ratepayers, and it argues penalties cannot be recovered in rates under the Public Utilities Code.
• CalCCA supports shareholder-funded penalties and says customer harm should be part of the penalty calculation, not just utility economic benefit.
• SEIA also supports shareholder-funded penalties and urges the Commission to preserve strong enforcement if IOUs miss the adopted targets.
• SDG&E says prudently ordered remedial work should generally be ratepayer-funded if it is an incremental service or process improvement, while penalties for failing to implement ordered corrective actions may be shareholder-funded.
• PG&E opposes Cal Advocates’ proposed penalty formula and says any penalty structure should be tied to utility-controlled causes and not imposed mechanically from aggregate averages.
• SCE, as reflected in last week’s filings, supports progressive enforcement and argues penalties should come only after systems and data are sufficiently mature to support fair attribution.
• EDF, from last week’s filings, supports shareholder-funded remedial action and penalties for repeated or serious noncompliance.

Reporting, data quality, and transparency requirements

• Cal Advocates urges the Commission to keep biannual Energization Reports, preserve project-level and cost reporting, and reject IOU requests to reduce or remove reporting fields.
• IREC says the biannual reports are not yet comparable across IOUs because the utilities use different methodologies, and it asks the Commission to require one auditable standard for aggregate calculations and step attribution.
• CalCCA supports more frequent and more public reporting, including a statewide dashboard and fewer redactions, so stakeholders can better see where delays are occurring.
• SEIA supports robust reporting but says the Commission should weigh implementation burden and ratepayer cost, and it backs aggregating MPU financial reporting where project-level data are not practical.
• PG&E says reporting requirements should be limited to reasonably available and well-defined data, with phased implementation for new fields, and it opposes using unavailable data as the basis for penalties.
• SDG&E says annual reporting should focus on incremental updates and should not become a parallel workforce or process proceeding; it also says some current report fields cannot yet be fully populated without further system changes.
• TURN, from last week’s filings, supports standardized fields and a central dashboard to improve accountability and customer visibility.
• CalBroadband, from last week’s filings, supports start-to-end reporting so the reported timeline better reflects actual customer experience.

Energization report methodology, pipeline visibility, and delayed project triage

• IREC says the Commission should require a single methodology for calculating IOU-controlled, customer-controlled, and end-to-end timelines, and it recommends re-filing biannual reports using standardized formulas.
• IREC also argues the Commission should require utilities to report severely delayed in-progress projects, not just completed projects, so backlogs do not get hidden by favorable averages.
• PG&E rejects adding new average-based remedial triggers and says customer wait-time measures are more meaningful than upstream project construction timelines alone.
• SDG&E says the Commission should rely on system-level performance measures and should refine the 12-month compliance period before using current reports for major enforcement decisions.
• CalCCA supports public-facing monitoring tools and says the Commission should eliminate unnecessary redactions that limit identification of geographic bottlenecks.

SB 254 auditor independence, scope, and process

• Cal Advocates says SB 254 auditors should be insulated from IOU influence, with Energy Division review of contracts and no IOU review or editing of draft reports before publication.
• CalCCA agrees that auditor independence is important and supports Energy Division oversight, public transparency, and procedural safeguards that prevent utility control over audit findings.
• PG&E rejects the idea that SB 410 should become the template for SB 254 and says existing audit practices already allow Energy Division visibility without undermining independence.
• SDG&E says SB 254 auditor selection should remain utility-specific and opposes requiring the large IOUs to jointly retain a single auditor, though it supports allowing the same auditor to serve under both SB 254 and SB 410 if appropriate.
• SCE, from last week’s filings, said SB 254 audit costs should be recoverable in rates and opposed a single joint auditor across utilities.
• TURN, from last week’s filings, supported stronger auditor independence and a clearer pathway for audit findings to inform enforcement.

Process improvements, standardization, and customer-facing tools

• PG&E supports more online project-tracking tools, better intake guidance, and clearer process steps, but it opposes premature permitting or construction before financial commitment and safety milestones are complete.
• SDG&E supports process improvements but says many of the more prescriptive proposals are too rigid or would risk inefficiency, rework, or safety issues.
• SEIA supports standardizing MPU application processes across IOUs to remove administrative hurdles that slow the start of the clock.
• CalCCA supports public-facing monitoring and broader transparency, including a statewide dashboard, to make project status easier to track.
• SCTCA, from last week’s filings, supported automated ticketing and standardized portals so customers do not need to manage utility follow-up themselves.
• CALSTART, from last week’s filings, supported early access to limited load profile information and other tools that help customers plan projects before full application submission.

Workforce and staffing reporting

• SDG&E says staffing analysis belongs primarily in the GRC and that annual energization reports should not be expanded into a separate workforce proceeding.
• PG&E says workforce planning is important but detailed staffing mandates should be handled in the GRC where costs, labor mix, and funding can be evaluated in context.
• Cal Advocates supports a more public and transparent view of staffing and operational capability where it affects energization performance.
• CUE, from last week’s filings, supported more detailed staffing reports with historical, current, and forecasted workforce information.

Upstream capacity, planning, and sector-specific proposals

• PG&E says the Commission should preserve utility discretion on upstream capacity investments and should measure customer wait time rather than treating upstream construction duration as the sole metric.
• SDG&E similarly opposes broad prescriptive requirements for upstream capacity timing and says existing planning tools already support proactive load planning.
• IREC says pace-of-energization analysis should be used to connect energization performance to climate and decarbonization goals, including upstream constraints.
• CalBroadband, from last week’s filings, continued to support sector-specific energization timelines for broadband projects, while other parties cautioned against industry-specific treatment.
• SEIA supports standardized MPU-related process changes where they reduce delay, but it does not endorse broader reworking of utility planning processes beyond what is needed to support timely energization.

far to streamline smaller or non-export projects. This is a sampling of parties’ positions.

Screen Q and Screen R reforms

• PG&E supports a targeted statewide Screen Q refinement and, consistent with its earlier position, proposes a two-part test under which a project fails only if both DFAX exceeds 5% and flow impact exceeds 1% of facility capacity.
• SEIA supports adopting PG&E’s framework statewide, with modifications to use incremental power flow throughout, allow an aggregate-pass exception, improve short-circuit testing, and require more detailed failure output so applicants can correct issues without arbitrary withdrawal.
• SCE opposes raising the 1 MVA threshold to 5 MVA and favors retaining its current interim methodology as a reliable, standardized baseline, while keeping Screen R largely unchanged absent a more developed proposal.
• SDG&E argues for narrower changes and continues to prefer preserving the existing framework, including keeping projects that fail Screen Q out of Rule 21’s standard path and directing them to transmission-oriented processes.
• CESA supports reforming the Flow Impact Test so that DFAX alone does not drive failures and backs a uniform statewide methodology.
• Clean Coalition supports raising the Screen Q exemption threshold to 5 MVA and adopting SEIA’s package of Screen Q/R reforms to better reflect actual grid impacts.
• Pioneer Community Energy focuses less on the screening mechanics themselves and more on ensuring Rule 21 reforms enable timely interconnection for distributed resources that do not materially affect transmission.

What happens when a project fails Screen Q

• SEIA argues that Screen Q reform alone is not enough and urges a CPUC-jurisdictional affected-systems study path so projects that fail Screen Q are not forced into the CAISO cluster process.
• CESA similarly says the CAISO cluster process is not a viable path for most Rule 21 projects and supports an affected-system study pathway inside Rule 21.
• Clean Coalition also supports SEIA’s affected-system-study approach as part of a broader effort to keep smaller DER from being pushed into transmission studies designed for larger projects.
• SDG&E continues to prefer routes outside the standard Rule 21 path for projects that fail transmission-related screening.

Interconnection timelines, reporting, and compliance

• SEIA supports maintaining the current Rule 21 timelines and reporting requirements, but wants clearer tracking of distribution-group-study timelines and a more specific compliance standard tied to each individual timeline.
• SCE agrees timelines should be refined for clarity and transparency, but says changes should be prioritized around practical definitions, dependencies, and implementation feasibility rather than expanding into numerous new mandates.
• SDG&E says its own timeline performance is strong and argues against additional statewide penalty or reporting burdens, especially where it sees limited incremental value.
• Cal Advocates/R. Hill/CPUC opposes efforts by SCE and SDG&E to remove the reporting metrics adopted in D.20-09-035, saying those metrics are needed for transparency, benchmarking, and accountability.
• IREC argues that years of reporting have shown persistent utility misses and says the Commission should move toward a citation program with a January 1, 2027 target date.
• Pioneer Community Energy supports stronger compliance mechanisms, including per-project penalties or a comparable framework, and says clear enforcement is needed if timelines are to have meaning.
• Clean Coalition supports IREC’s proposed citation program and says reporting alone has not produced compliance.
• Electrify America opposes eliminating OP 22 reporting or the 95% benchmark and supports a workshop to clarify the benchmark and timeline definitions before any reporting rollback.

Non-NEM fees and cost data

• SEIA says the current $800 non-NEM application fee is unsupported by actual cost data and asks for near-term residential fee relief while IOUs provide detailed cost information.
• Tesla argues the $800 fee is too high for residential-scale non-NEM projects and recommends aligning it with the current NEM/NBT fee until better cost data are available.
• Ford Motor Company supports prompt fee alignment with NEM/NBT levels for small non-NEM systems and says any longer-term cost study should be handled without delaying near-term relief.
• VGIC also supports fee parity for small non-NEM bidirectional charging systems and recommends using a higher application-volume threshold before reevaluating fees.
• Electrify America supports a data-driven fee update through a Tier 2 advice-letter process and says fees for projects eligible for a notification-only path should be eliminated or capped at a low amount.
• SCE agrees the flat fee is outdated and supports cost-reflective reform, but wants standardized cost reporting before mandatory fee changes.
• SDG&E also says the fee should be revisited using more complete cost data before changes are made.

Notification-only and streamlined pathways for smaller or non-export projects

• Clean Coalition supports a streamlined pathway for residential-scale and low-impact non-NEM/NBT projects and backs Tesla’s proposal for a 30-business-day review for qualifying projects.
• Electrify America supports a notification-only path for qualifying non-export battery systems under Protection Option 8, with PTO tied to standard paperwork and permit release.
• Ford Motor Company supports notification-only treatment for less impactful projects and says non-grid-parallel systems should remain outside Rule 21 entirely.
• VGIC says certain load-only EV systems and break-before-make backup-only systems should be clearly excluded from Rule 21 application and fee requirements, and asks for clearer customer-facing process distinctions.
• SDG&E opposes notification-only treatment for non-export systems and argues that utility review remains necessary for safety, protection, and reliability reasons.
• Tesla says smaller residential non-NEM projects should benefit from simplified treatment and faster review where they resemble other low-impact residential systems.

Distribution Group Study windows and related process issues

• SEIA urges the Commission to direct SCE to resume biannual Distribution Group Study windows and to change the rules so that a sole-member DGS group moves into the standard independent detailed-study timeline.
• Clean Coalition supports reexamining Screen R and the DGS process, including the problem of “groups of one,” and also supports resuming biannual DGS windows.
• SCE says its current process improvements and planning conditions should be evaluated through a practical, data-driven lens rather than by imposing broad new procedural requirements.