Simplifying Policy Management

Commission (CEC), investor-owned utilities (IOUs) and load-serving entities (LSEs), Central Procurement Entities (CPEs), Community Choice Aggregators (CCAs/CalCCA), California Advocates (Cal Advocates), Clean Energy States Alliance (CESA), Pacific Gas and Electric (PG&E), and Southern California Edison (SCE). The proceeding remains open for outstanding implementation details.

Adopted Capacity Requirements and Flexible Capacity Requirements

• The Commission adopts CAISO’s recommended existing capacity needed (LCRs) as follows: 2027: 23,618 MW; 2028: 24,545 MW; 2029: 25,480 MW.
• The existing capacity needed values by local area, as provided by CAISO, are approved for each year.
• CAISO’s recommended systemwide Flexible Capacity Requirements for 2027 are adopted.
• CAISO’s recommended systemwide FCRs range seasonally from 25,060 MWs (December) to 30,378 MWs (March).

Storage, Qualifying Capacity, Charging Sufficiency, and LDES

• Storage QC methodology and related Master Resource Database (MRD) fields are revised, effective beginning with the 2027 RA compliance year.
• Storage QC calculation is clarified as (MAX_CONT_ENERGY_LIMIT − MIN_CONT_ENERGY_LIMIT) ÷ 4, constrained by the Point of Interconnection (POI).
• QC is defined as the output that a resource can discharge for four or more continuous hours without foldback (nonlinearity); once a continuous-energy value unaffected by foldback is available, it will be incorporated.
• MRD fields will add a duration column and change the default “Maximum Continuous Energy” to the CAISO file difference noted above; Energy Division may adjust MRD field names as needed.
• For co-located energy-only (EO) resources, effective 2027, energy produced by a co-located EO resource may count toward off-site charging sufficiency up to hourly POI limits.
• The adopted formula is: Energy Available for Charging Sufficiency = Total energy produced (subject to hourly POI limits) − On-site paired storage energy sufficiency need.
• LDES is defined as any storage resource that can discharge at maximum capacity continuously for at least eight hours.
• A Forward Charge Period (FCP) multiplier framework is adopted, effective 2027, to allow LDES to count across the 24-hour Slice of Day period up to capability.
• The adopted FCP multipliers are: ≥8 hours: multiplier 2; ≥12 hours: 3; ≥16 hours: 4; ≥20 hours: 5; ≥24 hours: 6; ≥48 hours: 7; ≥72 hours: 8.
• Closed-loop pumped storage hydropower (PSH) will be treated like LDES for charging sufficiency.
• The Commission adopts Energy Division’s proposal to convert an MWh charging deficiency into a 24-hour flat-profile MW-equivalent adder at the deficiency-notice stage, keeping shown capacity and excess charging energy distinct in compliance templates. This is effective for the 2027 RA year.

Unforced Capacity (UCAP) Framework and Related Changes

• The Commission adopts Energy Division’s UCAP framework, effective for the 2028 RA compliance year, with modifications and a staged implementation.
• Option 1 for UCAP valuation is adopted: unit-specific values beginning in 2028, using class-average EFORd for new units and then historical data.
• The definition of forced outage is adopted in modified form: an unplanned event requiring removal, derating, or outage due to equipment failure, risk of imminent equipment failure, or other factors preventing a unit from operating at full Pmax.
• Energy Division is authorized to select or adjust Nature of Work (NOW) codes included or excluded in EFORd calculations consistent with UCAP principles.
• Energy Division’s proposal to reflect foldback in expected EFORd and UCAP values is adopted.
• Outstanding implementation details to be resolved before or during UCAP rollout include integration of UCAP within Slice of Day templates for storage, must-offer obligation basis once UCAP replaces ICAP, EFORd for storage energy components, UCAP for hybrids, treatment of foldback during the fifth RA Measurement Hour, interactions between UCAP and flexible RA, and the application of the 4-hour discharge requirement for RA eligibility.

Demand Response and Transactability

• For DR resources, the Commission will send three monthly values to CAISO: maximum showing value, peak showing value, and average hourly MW values for hours within the Availability Assessment Hour (AAH) window when available.
• Energy Division’s SOD QC valuation for DR, including PG&E’s modification that the hourly average be limited to available AAH hours, is adopted as a near-term fix to misaligned participation windows.
• Energy Division is encouraged to coordinate with CAISO and CEC on a longer-term 24-hour SOD framework.
• The Commission credits Energy Division’s Transactability Report and finds no current transactability concerns under the SOD framework.
• The Commission declines to adopt an hourly load obligation trading mechanism at this time because of complexity and unresolved issues.

CAISO Market Products, Bidding, and Revenue Allocation

• Based on the CAISO tariff and Business Practice Manual, Reliability Capacity (RC) products (RCD/RCU) are components of the Residual Unit Commitment (RUC) process.
• Imbalance Reserve (IR) products are capacity products for RA program purposes, though IR compensation may include capacity-related and opportunity-cost components.
• The Commission maintains and affirms D.05-10-042 policy rules: zero-dollar bidding and the revenue-return requirement apply to RC products offered into CAISO markets.
• That policy is extended to IR capacity-related revenue: resource owners, other than the LSE that owns and uses the resource for RA compliance, are not eligible to keep RC or IR capacity-related revenues.
• LSE contracts executed after the decision’s effective date must reflect these requirements, and LSEs shall use CAISO Day-Ahead Market Enhancements Transitional Measures, or equivalent, to return revenues to the showing LSE.
• Existing contracts remain undisturbed, though LSEs should reasonably attempt to enforce contract provisions consistent with D.05-10-042.

Load Forecasting, Reporting, and CPE Data Transparency

• Clarifications adopted regarding “changes to approved implementation plans” provide that this phrase includes voluntary changes to the effective date of an approved implementation plan even if the new plan is not resubmitted for Commission approval.
• Energy Division’s proposals on large-load reporting are adopted on an interim basis.
• IOUs must provide CCAs with data on customers expected to interconnect in a CCA’s area for the following year at or prior to the year-ahead forecast meet-and-confer.
• All LSEs must report new or expanding customers they intend to serve.
• Required project data include identifier, address/contact, default LSE, requested capacity, energization date, ramp schedule, and application status.
• Details will be finalized with the CEC and included in annual CEC templates.
• This interim requirement begins for the 2028 RA year.
• Energy Division’s SOD load forecast summary/process (Appendix A) is adopted.
• Energy Division is authorized to publish the CPE data request file on the Commission’s RA website.
• The Commission clarifies how CPEs should use aggregated local RA data to assess total contracted capacity at LCA and sub-LCA levels and to exercise procurement authority under prior decisions.
• CPE procurement determinations must account for CAISO-identified storage charging limits.
• This procurement assessment requirement is effective starting the 2027 CPE procurement cycle.

Other Adopted Changes and Reporting

• The off-peak import counting rule adopted previously in D.25-06-048 is extended to third-quarter months beyond 2026.
• Energy Division may allow under-construction resources to be shown toward year-ahead flexible RA requirements if verified flex-eligible in the MRD during year-ahead compliance.
• Resources not in the year-ahead MRD will not count.
• This is effective for the 2027 RA year.
• IOUs must provide specified monthly reporting in Quarterly Compliance Reports and at Procurement Review Group meetings for at least three years beginning with the third quarter report in 2026.
• Required items include monthly gross costs and prices for Imbalance Reserve and Reliability Capacity, revenues, and amounts in dispute.

Procedural and Implementation Timing

• The UCAP framework is effective for the 2028 RA compliance year.
• Many other storage, charging, QC, and penalty changes are effective beginning with the 2027 RA compliance year.
• The decision lists specific outstanding UCAP implementation items that must be resolved.
• The rules adopted are effective immediately unless otherwise stated.
• The order is dated and effective July 2, 2026.

Open Items and Next Steps

• Implementation details for UCAP, including storage Slice of Day integration, must-offer obligations, hybrid treatment, foldback in the fifth RA Measurement Hour, and UCAP–flexible RA interactions, remain to be addressed.
• Energy Division and CAISO coordination is urged to develop a longer-term SOD, DR, and 24-hour framework.
• Energy Division is authorized to make administrative MRD adjustments and to manage NOW code inclusions and exclusions per UCAP principles.

This decision formalizes numerous technical changes to RA valuation, measurement, and enforcement, with immediate effect for many changes in 2027 and full UCAP implementation in 2028, while directing further work on detailed implementation issues.

guidance and sample forms were posted on www.selfgen.ca.com on June 8, 2026. The May 8, 2026 ACR instructed PAs to pay developers for completed projects that have approved Incentive Claim Forms, complete cost documentation, and a Supplemental Cost Verification Form per the March 13, 2026 ACR.

Developer requirements

Developers may submit existing TEPC documentation by TEPC cost categories together with a signed attestation (handwritten or electronic). The Ruling provides the exact attestation text, including a declaration under penalty of perjury.

PA obligations

PAs shall deem TEPC documentation accompanied by the signed attestation complete without further review. For previously received cost documentation, completeness is established once the attestation is submitted. PAs must post cost documentation and signed attestation information on www.selfgen.ca.com within 30 days of this ruling.

Questions and disposition

Parties must confirm collection, recording, posting methods, electronic signature intake formats/authentication, timelines for partial submissions, and identify obstacles. Disposition: developer-signed attestations suffice to deem TEPC complete. Ruling dated July 10, 2026, signed by Karen Douglas.

scope

• The CPUC opened this rulemaking on May 30, 2024 (Rulemaking 24-05-023) to reassess reporting on safety, reliability, and resiliency of electrical distribution systems in light of new risks, including climate change impacts, and to update long-standing authorities and decisions, including GO 95, D.96-09-045, GO 165, GO 166, and D.00-05-002.
• The proceeding concludes with the adoption of the Template & Customer Reliability Schema and the closure of Rulemaking 24-05-023.

Key requirements and schedule

• Appendix A, the Template & Customer Reliability Schema, is adopted and must be used by PG&E, SCE, and SDG&E to prepare their customer reliability reports.
• Beginning in 2027, and thereafter no later than 30 days after July 15 each year, each of the three utilities shall submit a fully completed customer reliability report to the CPUC’s Safety Policy Division.
• Every three years from the first submission, counting from July 15, 2027, beginning July 15, 2029, the three utilities must file an Advice Letter reporting whether the Commission should consider updates or narrow enhancements to the Template.
• These tri-annual assessments are to be narrowly focused on data relevance, reporting mechanisms, and potential sequencing or integration of existing reports.

Required content and data elements

The Template & Customer Reliability Schema requires a systemic, standardized set of narrative and tabular data to improve oversight and public understanding, including:

• Annual narrative on planned and unplanned outages and an annual summary of each utility’s Wildfire Mitigation Data Report.
• Detailed customer- and outage-level tables so data is not siloed.
• Overhead vs. underground distinctions: report whether outages affected overhead or underground circuits, the percentage breakdown, and conductor type (bare, covered, insulated) for each affected circuit or segment.
• Customer notification and communications: explain how customers are notified before, during, and after planned and unplanned outages; provide the notification data sent to customers; and detail outreach to public safety partners and customers with medical needs during all outages.
• Public safety partner definition: adopted definition includes first responders (local, state, federal), water and communications providers, community choice aggregators, affected publicly owned utilities/electrical cooperatives, the CPUC, California Office of Emergency Services, and California Department of Fire and Forestry Protection.
• Outage type distinctions: require separate identification and definition of public safety power outages and Fast-Trip events distinct from other outage types.
• Reliability metrics: report Customers Experiencing Multiple Interruptions (CEMI), Customers Experiencing Long Interruption Duration (CELID), SAIDI, SAIFI, CAIDI, and MAIFI both with and without the inclusion of Major Event Days, and reported across customers and communities.
• Vulnerable populations and critical customers: report access and functional needs, medical baseline, and essential customers for each recorded outage.

Findings and legal conclusions

• The CPUC finds it prudent to modernize outage reporting to address newly emergent risks and climate-exacerbated threats and to increase transparency.
• The utilities’ proposed Template & Customer Reliability Schema is adopted with modifications reflected in Appendix A.
• The CPUC concludes the specified reporting elements, including the overhead and underground breakdown, conductor types, communications and notification details, public safety partner definition, separate outage-type definitions, the set of reliability metrics, and customer and outage tables including vulnerable populations, are reasonable and should be required.

Procedural orders

• The Template & Customer Reliability Schema, Appendix A, is adopted as ordered.
• Utilities must file and serve their Annual Electric Reliability Report as part of the Template submission; no substantive changes may be made to the Annual Electric Reliability Reports themselves.
• The Advice Letter process for tri-annual review, starting July 15, 2029, will be resolved through a Resolution presented to the Commission for vote.
• All prior rulings by the Administrative Law Judge and assigned Commissioner in this proceeding are affirmed; remaining motions not yet ruled on are denied.
• Rulemaking 24-05-023 is closed and the order is effective as of the decision date.

Dates and parties specifically referenced

• CPUC initiated proceeding: May 30, 2024.
• Annual reporting requirement begins in 2027, with reports due no later than 30 days after July 15 each year.
• First tri-annual review due July 15, 2029, and every three years thereafter.
• Adopted reporting applies to Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company.

pre-application work, technical requirements, stakeholder engagement, and possible regulatory pathways.

Flexible Service Connections Ruling

The July 7 ruling asks parties to comment on the Assigned Commissioner’s Proposal on Flexible Service Connections and to respond to specific questions organized around implementation, coordination, and safety. The proposal emphasizes using flexible service connections to better utilize distribution capacity, accelerate energization options, and preserve reliability and affordability.

• All parties are asked to provide initial comments on the proposal and the questions in the ruling by July 21, 2026.
• Reply comments are due by July 28, 2026.
• Any motion objecting to official notice of listed documents must be filed within 10 days of issuance of the ruling.

The ruling also directs specific IOU filings. PG&E must provide materials and work products from its Grid Edge DERMS technology-provider workshops and collaboration efforts. SCE and SDG&E must file existing documents describing efforts to develop systems that use local measurement and computation with a power control system to address capacity constraints. PG&E’s response to the Section 3 questions is due July 14, 2026.

Topics raised for comment include the following:

• General support, concerns, and feedback on the proposal, with comments organized to mirror the proposal’s structure.
• Recommendations on the summary of actions proposed for Commission consideration, including implementation feasibility.
• Whether additional recommendations are needed to support the stated goal of reducing ratepayer spending on grid upgrades while maintaining safety and reliability.
• Suggestions for the design and consolidation of advice letters used for implementation.
• Metrics and reporting methods to track costs and benefits.
• Coordination with the California Energy Commission for forecasting and communication of bridging or non-bridging solutions.
• Implementation issues for SDG&E’s static flexible service connection offering.
• Safeguards to avoid proprietary restrictions on customer access to flexible connections.
• Safety issues that should be highlighted.

For cybersecurity, the ruling references the Smart Inverter Operationalization Cybersecurity Subgroup report and asks whether testing and certification programs should be considered if the Commission pursues Path H. It also takes official notice of a set of prior utility and research documents relevant to Track 3, including grid modernization reports, EPIC materials, filings in related proceedings, and other referenced technical resources.

DER Orchestration Workshop Record Entry

The July 9 ruling enters two Track 2 DER orchestration workshop reports into the record. The reports cover Commission-led workshops held on May 21, 2026 and June 5, 2026, the latter co-hosted with CAISO. The ruling summarizes the workshops and invites formal comments on the accuracy of the reports and on the issues raised during the sessions.

• Opening comments are due July 27, 2026.
• Reply comments are due July 31, 2026.

The workshop record focuses on IOU-operated DSO needs, gaps, and barriers for a high DER future. It builds on prior Track 2 guidance and the March 23, 2026 ruling that identified five priority areas: DER visibility to DSO, DER visibility to CAISO, DER dispatchability/control, open access to the distribution system, and reliability coordination at the transmission-distribution interface.

The ruling asks parties to address:

• Any factual inconsistencies or needed clarifications in the workshop reports.
• What additional development is needed before IOUs file DER orchestration framework applications.
• How to coordinate ongoing pilots with a formal application process.
• Which pre-application workshops or working groups should be convened and what they should cover.
• How to engage California Tribal Nations, environmental social justice communities, and other underrepresented stakeholders.
• Which initial use cases should be prioritized and how IOUs at different readiness levels should be coordinated.
• How Grid Edge DERMS and Enterprise DERMS compare for orchestration use cases.
• Which customer-owned DERs are best suited for near-term participation and what barriers remain.
• What requirements are needed for reliable integration, modeling, and planning.
• How cost reductions should be identified and tracked over time.

The ruling also asks parties to consider how learnings from PG&E’s EPIC 4.08 pilot, distribution planning processes, and existing DER orchestration work should inform future applications. The overall focus is on defining a framework that can support safe and reliable operations while improving flexibility, data visibility, and distribution system utilization.

and overarching recommendations

• CalCCA urges the Commission to adopt a broad Track 3 scope so parties can evaluate targeted recovery tools for uneconomic legacy resources, alternative allocation approaches for PCIA attributes, volatility-reduction mechanisms, and other structural frameworks that could better achieve indifference. CalCCA also asks for early resolution of data access and confidentiality issues, with substantial time after data production for analysis and proposal development.
• WestLight Energy recommends a broad review of the PCIA framework rather than minor adjustments, arguing that the current design does not achieve true statutory indifference and may shift costs onto departed customers.
• Cal Advocates supports including an allocation framework in Track 3, while also recommending targeted RPS MPB refinements if the Commission keeps the existing PCIA structure. It also urges a dedicated Track 3 effort on ERRA reforms.
• The Joint IOUs support a broader Track 3 process, but recommend splitting it into an expedited track for near-term MPB reforms and a longer track for more complex issues such as UOG re-vintaging and comprehensive MPB reform.
• CLECA supports a broad record that evaluates structural alternatives, not just benchmark refinements, while keeping the statutory indifference standard and rate stability at the center of the analysis.

Scope of Track 3 and structural reform options

• CalCCA supports considering a wide range of structural solutions, including securitization or other recovery tools for uneconomic legacy resources, mandatory allocation of certain attributes, and alternative frameworks outside the current PCIA paradigm.
• WestLight Energy argues Track 3 should allow fundamental reconsideration of the PCIA framework, including whether UOG should remain in PCIA cost recovery.
• Cal Advocates says allocation-based frameworks should be part of Track 3 because they could change the underlying rate design and reduce reliance on benchmark-based PCIA calculations.
• The Joint IOUs oppose revisiting mandatory allocation as a general solution, but support clarifying UOG re-vintaging guidelines and focusing near-term work on MPB reforms.
• CLECA supports examining targeted solutions for uneconomic legacy resources, allocation mechanisms, volatility-reduction measures, and other structural frameworks, and says these issues should be considered in parallel rather than treated as mutually exclusive.

PCIA methodology refinements and rate volatility

• CalCCA’s immediate refinement priorities are re-vintaging and modifying the RPS MPB only to align its calculation method with the RA MPB approach adopted in D.25-06-049; it also asks for an Energy Division staff report on longer averaging periods for the RPS MPB.
• Cal Advocates identifies targeted refinement of the RPS MPB as its highest-priority PCIA issue if the Commission retains the current framework, and specifically supports including long-term contracts in the RPS MPB to reduce volatility and improve accuracy.
• The Joint IOUs say interim reform of the RPS MPB and Energy Price Index MPB is the best near-term opportunity to reduce volatility, and recommend a bifurcated schedule to move those changes forward quickly.
• CLECA cautions against changes driven by short-term benchmark movements and says any MPB refinement must be justified by clear structural flaws and remain consistent with statutory indifference.

Allocation frameworks and indifference theory

• CalCCA supports revisiting allocation of PCIA attributes, particularly mandatory allocations with transactability for resources such as RA, RPS, and GHG-free attributes, and argues this could eliminate proxy MPB disputes.
• Cal Advocates favors exploring allocation as a structural alternative because it would assign resource costs and benefits directly to the customers for whom they were procured, reducing the need for MPB-based true-ups.
• CLECA supports studying allocation approaches, but only if they preserve symmetrical indifference between bundled and unbundled customers and do not create new cost shifts.
• The Joint IOUs oppose revisiting mandatory allocation, stating that the issue was already examined in prior proceedings and that a portfolio split could complicate procurement planning and create over-procurement risk.

Utility-owned generation, legacy resources, and re-vintaging

• CalCCA identifies re-vintaging as an immediate Track 3 priority and says the Commission should decide both the appropriate standard and the proper forum for resolving related allocation questions.
• WestLight Energy argues the Commission should reconsider whether UOG should remain in the PCIA at all, contending that UOG costs are not “unavoidable electricity purchase contract costs” and may no longer reflect stranded costs in today’s market.
• The Joint IOUs support issuing statewide guidance on UOG re-vintaging while keeping fact-specific determinations in utility-specific proceedings.
• CLECA supports targeted legacy-resource solutions such as asset disposition, contract renegotiation, and re-vintaging as alternatives to continued rate-based recovery.

Data access, confidentiality, and record development

• CalCCA says robust Track 3 analysis depends on timely public and confidential data access, a data access protocol consistent with its Data Matrix, and at least six months after data production for analysis and proposal development.
• CalCCA also asks for revised templates that show the relevant time period for each requested data item and whether each item is public or confidential, and seeks Reviewing Representative access under the standard Model NDA.
• The Joint IOUs support a structured data process and adding template columns identifying the requesting and providing party, while emphasizing relevance, burden, and confidentiality limits under Commission discovery rules.
• Cal Advocates says data-access issues would look different under an allocation framework because fewer confidential forecasts and valuation judgments would be needed from IOUs if attributes were allocated directly.
• CLECA supports a data-access framework that lets authorized representatives verify PCIA calculations and test proposals while protecting commercially sensitive information, and also supports more anonymized public data where feasible.

Schedule and process for next steps

• CalCCA asks for 60 days after the scoping ruling and memo for meet-and-confer efforts and a joint case management statement, but says substantive deadlines should not move ahead before data access is resolved.
• The Joint IOUs propose a bifurcated schedule, with an expedited Track 3A for interim MPB reforms and a longer Track 3B for UOG re-vintaging and comprehensive reform.
• CLECA asks for additional in-person technical workshops during proposal development to narrow disputes and strengthen the evidentiary record before hearings.
• Cal Advocates recommends a dedicated ERRA track within R.25-02-005 to address cost recovery and dispatch issues that require further record development.

should look like.

Data sufficiency, standardization, and report usability

• Environmental Defense Fund (EDF) said tracking alone is not enough and urged higher-quality, standardized, stakeholder-accessible reporting with clear metrics, consistent definitions, and remedial triggers when utilities miss targets repeatedly or by large margins.
• California Community Choice Association (CalCCA) said IOU energization data remain missing, inconsistent, and unreliable, and urged the Commission to adopt Guidehouse’s sufficiency thresholds, require formulas and calculations for reported metrics, and set a March 31, 2027 deadline for systems and process upgrades.
• Cal Advocates said the current reports do not provide reliable enough data to evaluate performance or ratepayer spending, and called for quantitative sufficiency tables, narrative explanations of gaps, and corrective action if thresholds are not met within one year.
• Southern California Edison (SCE) said the Commission should focus on data needed to evaluate utility-controlled timelines and avoid adding low-value contextual fields that increase burden without improving compliance assessment.
• San Diego Gas & Electric (SDG&E) supported the compliance/contextual data framework but cautioned against adopting numeric sufficiency thresholds too early, saying they should be treated as maturity indicators rather than immediate compliance triggers.
• The Interstate Renewable Energy Council (IREC) opposed using data sufficiency as a reason to delay compliance review and instead recommended provisional assessments using the best available data, with data gaps treated as separate compliance issues.

How to measure utility-controlled time and concurrent steps

• Cal Advocates said current IOU methods understate utility-controlled time and recommended a standardized method that sums the IOU-controlled steps while allowing concurrent IOU-controlled steps to be counted once, without shifting overlapping time to customers or agencies.
• California Community Choice Association (CalCCA) said the IOUs use different methodologies that are not comparable and asked the Commission to require full, auditable step-level reporting before adopting any concurrency treatment systemwide.
• Environmental Defense Fund (EDF) urged consistent end-to-end reporting from application to energization, with moving averages and median timelines, and called for standardized definitions and metrics across utilities.
• San Diego Gas & Electric (SDG&E) supported attributing overlapping IOU/customer durations to customer time and counting overlapping IOU-controlled steps only once.
• Southern California Edison (SCE) said utilities should be held accountable for IOU-controlled time within IOU-controlled steps and opposed more granular sub-step time attribution.
• Interstate Renewable Energy Council (IREC) argued that overlapping time adjustments should be limited to methods that are fully auditable from reported step data and said nondisclosed carve-outs should not be permitted.
• SCTCA urged a single time-attribution rule and said overlapping IOU-controlled and customer/AHJ activity should not be used to understate IOU delay.

Pre-Decision projects, in-progress projects, and outliers

• California Community Choice Association (CalCCA) said projects initiated before the energization decision should continue to be reported separately, and in-progress projects that have exceeded targets should be included so averages are not skewed downward.
• Cal Advocates said in-progress projects and pre-Decision projects should remain in the reporting framework, with separate handling where needed, because they affect the assessment of current performance.
• PG&E and San Diego Gas & Electric (SDG&E) both argued that pre-Decision projects should generally be excluded from performance calculations because they were initiated under different frameworks.
• PG&E and San Diego Gas & Electric (SDG&E) also said aggregate performance metrics should generally focus on completed projects, while supporting outlier identification and separate reporting of anomalous records.
• Southern California Edison (SCE) said pre-Decision projects should be excluded from cumulative compliance calculations and that in-progress projects should not be included in aggregate target calculations.
• Interstate Renewable Energy Council (IREC) said pre-Decision projects should still be counted because the targets were intended to apply now, and it opposed excluding long-running projects from evaluations.
• SCTCA said the current framework does not adequately capture delays affecting Tribal communities and asked for Tribal-specific reporting on unresolved projects and delay causes.

Upstream capacity tracking and cost reporting

• Environmental Defense Fund (EDF) said upstream upgrade delays should be tracked over the full customer timeline, not just the construction period, and that all projects waiting on upstream upgrades should be subject to timeline targets regardless of which customer triggered the upgrade.
• California Community Choice Association (CalCCA) and Cal Advocates both supported more detailed tracking of upstream capacity and related costs, with Cal Advocates recommending reconciled cost dates and timely cost reporting for oversight.
• PG&E, Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) each said cost reporting should generally rely on reconciled, post-completion data because interim cost figures are likely to change and can be difficult to attribute accurately at the project level.
• Southern California Edison (SCE) said upstream upgrade tracking is improving, but it is too early to mandate additional methodology changes given recent system enhancements.
• San Diego Gas & Electric (SDG&E) said upstream capacity requests are already tracked manually in some cases and noted that additional IT improvements are underway.
• Interstate Renewable Energy Council (IREC) said upstream capacity fields should be treated as compliance data points because they affect how time is counted while upgrades are pending.
• SCTCA urged separate reporting for upstream capacity constraints affecting Tribal and rural areas, including resolution timelines and whether bridging DER solutions were offered.

Workforce reporting under Public Utilities Code section 935

• Environmental Defense Fund (EDF), Cal Advocates, and California Community Choice Association (CalCCA) each argued that workforce reporting should be more closely linked to energization targets and long-term decarbonization planning, with forecasts extending beyond the current GRC cycle.
• Cal Advocates recommended more detailed historical and forecasted workforce reporting, including internal and external labor hours, apprenticeship information, and explanations for staffing changes over time.
• Environmental Defense Fund (EDF) said Section 935 reports should connect staffing levels to energization targets and broader state goals, and should include long-term projections through 2045.
• California Community Choice Association (CalCCA) said Section 935 reports should explicitly link staffing levels to energization targets and show whether workforce levels are sufficient to meet demand.
• PG&E, Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E) each said Section 935 reports should remain tied closely to the statute and GRC process, and they opposed adding a new prescriptive statewide template or extensive historical reporting requirements.
• San Diego Gas & Electric (SDG&E) said the existing statutory framework is decision-useful and supports reporting tied to the GRC cycle, while Southern California Edison (SCE) said added workforce fields are unnecessary absent a demonstrated link to energization delays.

Customer engagement, outreach, and complaint handling

• California Community Choice Association (CalCCA) supported adding narrative updates on customer engagement tools, implementation status, and effectiveness metrics in future biannual reports.
• PG&E and San Diego Gas & Electric (SDG&E) both said they can include customer engagement updates in their narrative reporting, although San Diego Gas & Electric (SDG&E) said annual rather than biannual updates may be sufficient.
• Southern California Edison (SCE) said it already provides public customer resources and questioned whether additional engagement metrics would materially improve timeline compliance.
• SCTCA said complaint volume alone does not show good performance and urged more accessible, multilingual, and real-time customer-facing reporting for Tribes and communities facing delays.

ESJ, Tribal, and broadband-related reporting

• California Community Choice Association (CalCCA) supported separating community-type fields into distinct yes/no indicators for disadvantaged, underserved, and Tribal communities.
• San Diego Gas & Electric (SDG&E) supported using CPUC ESJ definitions and disaggregating community-type fields into separate indicators.
• Southern California Edison (SCE) recommended using updated CalEPA and tribal definitions rather than the ESJ Action Plan framework.
• SCTCA urged the Commission to require Tribal-specific reporting each cycle, including step-level timelines, upstream capacity issues, and reasons for delay.
• CalBroadband asked for a separate broadband deployment project category and for comprehensive start-to-end energization data, including in-progress projects that have exceeded targets.

Next procedural focus

• The comments set up the next phase of the proceeding around whether the Commission should adopt formal sufficiency thresholds, standardize time-attribution and outlier rules, require more detailed cost and workforce reporting, and define how in-progress, pre-Decision, Tribal, and broadband-related projects should be reflected in future biannual reports.