Simplifying Policy Management

2026, if responses filed July 28). Contact: Caitlin Pollock, Energy Division (caitlin.pollock@cpuc.ca.gov).

Purpose and context

The Ruling seeks IOU data to inform Phase 1 consideration of whether the flat $800 non-NBT/NEM interconnection application fee should be adjusted to reflect cost causation and application complexity, including possible scaling by project size, technology, export status, and engineering complexity.

Directives and format

IOUs must respond to detailed prompts within two weeks, using the Appendix A template where possible, combining data for 2024 and 2025. Energy Division may amend the data request.

Core information requested

Six topic groups require:

• Staff hours and costs per application
• Representativeness of $800, including per-application and aggregate over/under-collection
• Feasibility and criteria for scaling fees by complexity, size, and technology
• Residential vs. non-residential segmentation and timelines
• Local grid factors and standard engineering hourly rates
• Completion of Appendix A with methodologies and limitations

Appendix A and procedural closing

Appendix A must be populated for 2024–2025 combined, including project size, technology, tariff, export status, application counts, staff hours, costs, and MW. The Ruling is signed July 14, 2026, in San Francisco by ALJ Andrew Dugowson (“IT IS SO RULED”).

siting critical facilities, prioritizing undergrounding and resiliency investments, and oversight.

Primary recommendations and timing

LGSEC supports the standardized report template but requests two key modifications before the PD is placed on the Commission’s voting meeting agenda on August 13, 2026: require semi-annual, rather than annual-only, filing and adopt clarifications on granularity, definitions, coordination, and public access. LGSEC proposes the first-half report (Jan. 1–Jun. 30) be due no later than 60 days after period close; the second-half report would follow the annual deadline in D.16-01-008.

Rationale for semi-annual reporting

Annual-only cadence can create an effective public reporting lag of up to 18 months; semi-annual reporting would cut the maximum lag roughly in half, to about nine months, without requiring new data infrastructure. Timely data are needed by local governments to prioritize interventions, coordinate emergency and PSPS planning, evaluate capital and resiliency investments in GRCs and WMPs, and respond to oversight and constituent inquiries. Semi-annual reporting also aligns better with existing regimes, including WMP quarterly and annual reporting and S&O metrics that have been moved to semi-annual reporting.

Requested clarifications

• Jurisdiction-level SAIDI, SAIFI, and CAIDI metrics, or circuit-level metrics with a jurisdiction-mapping key or GIS-compatible identifiers.
• Explicit incorporation of IEEE 1366 definitions and Energy Division confirmation that they are applied consistently across PG&E, SCE, and SDG&E.
• Alignment of filing dates with WMP and GRC schedules where feasible.
• Machine-readable public filings posted to a stable Commission location.

assigned administrative law judges granted Green Power Institute’s request for additional time to file comments on the proposed decision served on July 8, 2026. The request was made for good cause shown under Rule 11.6.

• The comments deadline was moved to August 18, 2026.
• Green Power Institute must state in the opening paragraph of its comments that the assigned ALJs granted the extension by ruling on July 13, 2026.
• The ruling directs the Docket Office to formally file it.

Background for that request

Green Power Institute asked for the extension after multiple proposed decisions were served on July 8, 2026. In its request, the organization said the added time would allow for more complete comments on several pending matters. The service email for the proposed decision in this proceeding also noted that the item was placed on the Commission’s August 13, 2026 meeting agenda.

Partial extension granted on comments for the June 23 ruling

In a separate ruling filed the same day, the assigned administrative law judges partially granted the Joint IOUs’ Rule 11.6 request to extend the comment schedule for the June 23, 2026 ruling on an additional proposal for a reliable and clean power procurement program.

• Opening comments are now due August 14, 2026.
• Reply comments are now due September 2, 2026.
• The Docket Office is directed to formally file the ruling.

Reason for the partial grant

The ruling states that the full extension was not granted because of overlapping activities and time-sensitive deadlines in other Commission proceedings, including integrated resource planning and transmission planning-related work. The ruling notes that extending the schedule further could affect parties’ ability to participate in those other processes.

Party positions and scheduling context

The Joint IOUs had requested later dates than those adopted, while AReM circulated an even later alternative schedule. The ruling also references other nearby deadlines, including IRP filings due August 10, 2026, informal comments due July 14, 2026 on separate staff proposal workshop questions, and a workshop scheduled for July 23, 2026.

refinements, how quickly changes should be made, and what data should be available to support analysis.

Track 3 scope and sequencing

• CalCCA continues to press for a broad Track 3 scope that includes structural reforms to the indifference framework, including allocation-based approaches, along with targeted PCIA refinements and re-vintaging. It rejects the Joint IOUs’ proposed split-track approach as too limiting and too slow.
• CLECA supports keeping structural alternatives on the table in Track 3 and says allocation, benchmark refinement, and re-vintaging should be considered together because they may affect one another. CLECA also favors a balanced statewide approach that preserves symmetric indifference and rate stability.
• AReM/DACC support a more sequenced approach, with immediate focus on a few high-priority issues such as PCIA sunsetting, MPB refinements, volatility reduction, and vintaging fixes, while broader structural reforms are deferred to a later track.
• The Joint IOUs support near-term Track 3 work on MPB refinements and UOG re-vintaging, but oppose folding broader structural changes such as mandatory allocation or PCIA sunset proposals into the initial, focused scope.

Structural reforms, allocation, and PCIA sunset

• CalCCA supports considering allocation frameworks within Track 3, including mandatory allocation with transactability, and argues that material market and policy changes since the earlier PCIA proceeding justify renewed review.
• CLECA also supports evaluating allocation as a possible alternative indifference structure, but only if it preserves symmetry between bundled and departing-load customers and provides transparency about the attributes being assigned.
• Cal Advocates supports allocation-based approaches and says they could reduce volatility and lessen reliance on proxy benchmark valuation, while also improving alignment between costs and benefits.
• AReM/DACC are more cautious on mandatory allocation and recommend that broader structural concepts be considered later, after higher-priority PCIA and ERRA issues are addressed.
• The Joint IOUs oppose replacing the current framework with mandatory allocation, arguing that it would require a much more comprehensive record and could complicate procurement, operations, and cost allocation.
• The Joint IOUs also reject proposals to sunset the PCIA, saying existing statutory language ties cost responsibility to the end of utility purchase contracts and that a sunset would shift costs to bundled customers.
• AReM/DACC prioritize the question of a PCIA sunset date and say the issue needs legal analysis and stakeholder work because some customers may otherwise face very long PCIA obligations.

Market price benchmark refinements and rate volatility

• CalCCA supports limited early consideration of RPS MPB changes, specifically whether the Track 1 RA MPB methodology should be mirrored, but wants broader RPS MPB ideas deferred until a fuller record is developed.
• Cal Advocates continues to favor targeted RPS MPB refinement if the existing PCIA structure remains in place, including consideration of long-term contracts to improve accuracy and reduce volatility.
• The Joint IOUs say near-term reform of the RPS and Energy Price Index MPBs is the best opportunity to reduce volatility and support a faster Track 3A timetable.
• AReM/DACC identify MPB refinements as a top priority and say Track 3 should fast-track changes to existing benchmarks, including possible consideration of a GHG-free index, for use in 2028 PCIAs if feasible.
• CLECA supports benchmark work only to the extent it is tied to a clear structural need and consistent with statutory indifference, and cautions against changes driven mainly by short-term benchmark movement.

Volatility mitigation and ERRA/PABA recovery timing

• AReM/DACC support mechanisms to reduce volatility and stabilize rates, including possible refinements to the ERRA Trigger process or longer recovery and refund periods for severely over- or under-collected ERRA and PABA accounts.
• The Joint IOUs say longer recovery periods may treat symptoms rather than root causes and should not substitute for fixing benchmark methodology.
• CLECA continues to support volatility-reduction tools, but only if they do not create new cost shifts or undermine the symmetry of indifference.

Utility-owned generation re-vintaging and related process questions

• CalCCA says re-vintaging should be addressed early and that Track 3 should decide both the governing standard and the proper forum for applying it, including discovery and review of related cost-allocation questions.
• CLECA supports a transparent statewide re-vintaging standard and says Track 3 should consider how the standard is applied, including whether a resource’s operational or economic character has changed materially.
• The Joint IOUs support clarifying statewide UOG re-vintaging guidance through legal briefing, while reserving resource-specific determinations for later proceedings.
• AReM/DACC also support addressing re-vintaging, but favor handling it in parallel with MPB reform rather than after it, to avoid delay.

Vintaging corrections and refund limits for DA customers

• AReM/DACC raise concerns about incorrect vintaging after meter changeouts, mistaken transfers to CCAs, and loss of vintage when customers move between CCA and DA service. They seek clearer statewide rules and would eliminate the current three-year limit on PCIA overcharge refunds.
• The Joint IOUs say vintaging rules are already clear for customers who switch between DA and CCA without returning to bundled service, and they oppose removing the three-year refund limitation.
• CalCCA supports addressing re-vintaging early and links vintaging clarity to broader PCIA rate stability and cost-allocation issues.

Data access and scheduling

• CalCCA continues to seek full data access early in Track 3 and opposes a phased data-access process that would delay party analysis and proposal development.
• The Joint IOUs support a more structured and limited data process, with some issues handled in an expedited phase and broader data access reserved for later if needed.
• CLECA supports data access that allows verification of PCIA calculations while protecting confidential information, and favors additional technical workshops where they can improve the record.
• AReM/DACC do not take a position on the Part 2 data access template or related scheduling questions in these comments.

to Commission action

• PG&E said the Commission should not move directly to broad new mandates without first identifying specific data gaps, evaluating existing mechanisms, and weighing privacy, cybersecurity, legal, and cost issues. PG&E also emphasized that some proposed platforms or registries may duplicate existing tools or belong in other proceedings.
• SCE said any statewide platform or other new system should follow a staged process that starts with a clearly defined business case and accepted functions, followed by cost estimates and a formal cost-benefit analysis. SCE opposed an initial RFI before those thresholds are met.
• SDG&E/SoCalGas said new data access mandates should be grounded in a robust record demonstrating need, measurable benefit, feasibility, privacy and cybersecurity protections, and appropriate cost allocation to beneficiaries.
• Cal Advocates supported near-term governance reforms and targeted improvements to existing systems, with use-case-specific showings before broader changes are approved.
• UCAN said the Commission should take near-term action where the record already shows capability and need, including a statewide implementation process for data access reforms, a 24-hour interval-data requirement for CCAs and authorized third parties, and further work on a DER registry and platform architecture.
• Advanced Energy United said the Commission should evaluate a statewide data access platform on a portfolio basis rather than requiring each use case to independently justify the full cost of shared infrastructure.
• Clean Coalition said the DWG Report should be used as the basis for timely, substantive reform rather than treated as only a preliminary discussion document.

Near-term interval data access and utility system performance

• UCAN said the record supports requiring all three electric utilities to provide complete AMI interval usage data to CCAs and authorized third parties on a lag of no more than 24 hours, and also supported Green Button certification and enforceable performance standards for existing customer-data platforms.
• PG&E said its Share My Data platform complies with the relevant Commission decision for customer-authorized access, and that longer delays for some CCA or utility-to-CCA transfers may fall under different rules.
• SCE said its own systems provide low-latency access and cautioned that proposed performance metrics should reflect system differences and customer cost impacts.
• SDG&E/SoCalGas said UCAN’s non-compliance claims conflate different legal frameworks for customer-authorized third-party access and utility-to-CCA data sharing.
• CalCCA supported better access to timely, accurate interval data and said delays in some utility territories impair CCA planning, forecasting, procurement, and load-management work.
• Advanced Energy United said interval data is increasingly important for load flexibility and time-of-use participation and should be evaluated as part of a broader shared infrastructure solution.
• SBUA supported considering AMI-based customer-authorized data access, including a statewide platform or a unified Green Button Connect approach, and said utilities should disclose current system costs before new options are compared.

Statewide data platform, cost disclosure, and implementation process

• Advanced Energy United said a statewide platform should be evaluated as shared infrastructure, with aggregate benefits across multiple use cases compared to the incremental cost of maintaining separate utility systems. It also proposed a time-limited implementation working group and RFI process with a path to RFP if cost-effective.
• UCAN supported AEU’s implementation-working-group concept and added that an independent system integrator should help define performance metrics and scope utility-side changes, along with comprehensive utility cost disclosure.
• SBUA supported a statewide customer-authorized data access platform or a unified Green Button Connect option, but said the Commission should first compare net benefits across existing IOU systems and alternatives, including a centralized platform.
• SCE opposed an RFI as the first step, arguing that platform design and business-case definition must come first so that vendor responses can be meaningfully compared and paired with utility upgrade costs.
• PG&E said a statewide platform, if considered, should be evaluated against existing and already-authorized utility systems and against the specific use cases the record supports.
• SDG&E/SoCalGas said any new platform should be supported by a thorough record and costs should be allocated to beneficiaries, not broadly shifted to all ratepayers by default.

Aggregation rules and privacy

• Clean Coalition said the current 15/15/100 aggregation framework is too restrictive and should be replaced or modernized through a time-limited process, with privacy safeguards and disclosure of how utilities apply the rule in practice.
• UCAN focused more on getting usable data access in the near term than on changing the aggregation threshold immediately, but supported moving forward with the DWG Report’s privacy-protective access reforms.
• PG&E, SCE, and SDG&E/SoCalGas all said the record does not yet justify a universal change to aggregation thresholds and that privacy and re-identification risks need further analysis.
• Cal Advocates said aggregation should be evaluated on a data-product-specific basis rather than through a single universal threshold.
• SBUA supported a more permissive aggregation approach, including the 4/50 concept, and said current rules can limit access for underserved communities and local governments.
• SoCalREN did not propose a specific threshold but supported periodic review of aggregation rules and consideration of standardized geographic units if they improve usability while preserving privacy.

DER registry, premises-to-circuit mapping, and data gap assessment

• UCAN supported a statewide DER registry for static DER attributes and said dynamic or market-facing elements should be phased in later through a separate proceeding.
• CalCCA supported prioritizing DER registry concepts when tied to market or orchestration needs, and said registry decisions should be coordinated with the High DER proceeding.
• Cal Advocates said the Commission should first complete a DER data gap assessment before deciding whether a registry is needed.
• SBUA supported a DER registry but also urged a data gap assessment and independent technical assistance before implementation, especially to avoid building a registry around incomplete data.
• PG&E and SCE said registry design should be addressed only after the Commission clarifies the underlying data needs, governance, and other proceeding-specific issues.
• SDG&E/SoCalGas said a registry should not be adopted absent demonstrated need, feasible governance, and proper privacy and cybersecurity protections.
• UCAN, CalCCA, and other commenters supported improved premises-to-circuit mapping or constrained-circuit data access for DER siting and grid planning, while utilities said those issues require careful privacy and proceeding coordination.

EDRP, local and Tribal government access, and program enrollment sharing

• SoCalREN supported practical improvements to the Energy Data Request Program, including standardizing agreements, improving consistency and timeliness, and expanding access for local and Tribal governments for climate planning, electrification, reporting, and program evaluation.
• PG&E supported, to varying degrees, improving EDRP so local governments and Tribal governments can use aggregated data for public-interest purposes while preserving privacy protections. SCE, Cal Advocates, CalCCA, SDG&E/SoCalGas, and SBUA also supported improving EDRP in similar ways.
• UCAN supported improved enrollment-data exchange among utilities, CCAs, and third-party administrators, and said a single common interface should be used rather than three separate utility-specific systems.
• SBUA also supported standardized permissions and API-based access to interval usage, rate, billing, and account data, and emphasized that underserved, hard-to-reach, DAC, and small and diverse business customers should not be left behind.
• CalCCA supported better CCA access to enrollment and interval data and said better sharing is important for billing, forecasting, procurement, and load-flexibility program management.

Cost allocation, ratepayer value, and proceeding coordination

• PG&E said ratepayers should not fund new or modified data systems unless the record shows clear need and benefit, and it cautioned against assuming user-fee revenue or third-party uptake will fully cover costs.
• SCE said costs should be allocated under Commission-approved cost-effectiveness methods and should not be justified by benefits that do not reduce bills for all customers.
• SDG&E/SoCalGas said cost recovery should be tied to demonstrated need and beneficiary-pays principles, with a detailed record before any recovery is approved.
• Cal Advocates said ratepayers should not be the default funding source and supported beneficiary-pays principles.
• SBUA said cost recovery should reflect who benefits and suggested that ability-to-pay should be considered in allocation decisions.
• Advanced Energy United said a tiered user-fee structure could help offset platform costs if a statewide platform is pursued, but detailed fee design should be addressed later.
• UCAN said cost allocation principles should be set now, but fee design and detailed recovery questions should be handled in a later phase or successor proceeding.
• SoCalREN said the Commission should require utilities to identify the specific requirement, expected benefits, implementation costs, alternatives, and privacy/security impacts before authorizing ratepayer recovery.