Simplifying Policy Management

set in the Ruling Directing Utilities to Produce Rule 21 Interconnection Application Data (filed July 14, 2026). Multiple parties supported the request, no parties opposed, and the ALJ found good cause and granted the extension. The ruling states “IT IS SO RULED.”

Revised Schedule

• IOU Responses to the July 14 Ruling: original due July 28, 2026; new due August 11, 2026.
• Party Reply Comments: original due August 4, 2026; new due August 28, 2026.

Instructions and Actions

Extensions apply only to deadlines derived from the July 14, 2026 Ruling. IOUs (SCE, SDG&E, PG&E) must file required responses by August 11, 2026. Other parties must file reply comments addressing those responses and the produced data by August 28, 2026. The Docket Office is directed to formally file the ruling.

Rulemaking 22-11-013 remains open.

Key adopted changes

• Use a single electricity-based greenhouse gas (GHG) value for both electricity and natural gas GHG reductions in the ACC and remove the prior GHG “rebalancing” component. This aligns ACC GHG values with the IRP “shadow price” and addresses the absence of a cross-sector, sector-specific marginal abatement cost for natural gas beyond the current interim (based on a 2021 CEC report).
• Implement a simplified Integrated Calculation for generation capacity and GHG costs (a hybrid energy resource using the IRP GHG shadow price) to reduce sensitivity and improve transparency relative to interactions between RESOLVE and SERVM.
• Replace expected unserved energy (EUE) with loss of load hours (LOLH) for ACC capacity allocation factors so allocation reflects the frequency (not magnitude) of loss-of-load events.
• Allocate generation capacity value to days using energy prices rather than temperature, because prices better indicate when supply–demand constraints occur.
• Differentiate reliability risk by weekday versus weekend when allocating days with non-zero reliability risk, since modeling shows weekdays typically have higher risk.
• Update peak capacity allocation factors (PCAF) for transmission avoided costs to use the Integrated Energy Policy Report (IEPR) load forecast for future years (the same forecast used in SERVM energy avoided-cost modeling) instead of relying on historical loads.
• Adopt the Discounted Total Investment Method (DTIM) as the sole approach to calculate marginal transmission costs for all electric utilities to improve consistency and reduce volatility tied to individual large projects.
• Continue using the current methodology and the most recent transmission and distribution cost data to calculate avoided transmission and distribution costs in the ACC, and apply the methodologies approved in the 2024 ACC Decision except where this decision explicitly modifies them.

Findings of fact

Highlights

• California lacks a cross-sector basis for valuing GHG reductions and has not developed a sector-specific marginal abatement cost model for natural gas beyond the 2021 CEC interim value.
• The electric-sector GHG value is updated more frequently and, when used uniformly in the ACC, aligns with IRP marginal GHG values and avoids potential overvaluation of GHG reduction measures (protecting ratepayer interests).
• The GHG rebalancing component was intended to address reallocation of allowable emissions between sectors; removing it aligns ACC and IRP GHG valuation.
• Small and large reductions during an hour yield the same reliability benefit when a loss of load occurs, supporting the use of LOLH to measure capacity allocation.
• Increasing winter loads (from building electrification) plus high renewable penetration are shifting reliability risk from summer into winter; energy prices capture timing of constrained hours better than temperature.
• Weekdays present higher reliability risk than weekends; differentiating them yields capacity allocations more consistent with reliability modeling.
• IEPR load forecasts indicate future changes in hours of constrained transmission capacity due to EVs, building electrification, and behind-the-meter generation; using IEPR forecasts for PCAF aligns transmission value hours with generation capacity and energy avoided-cost modeling.
• A DTIM-only approach reduces volatility in transmission values linked to individual large projects and improves consistency across utilities.

Conclusions of law

• The ACC shall apply a single electricity-based GHG value for both electricity and natural gas and shall remove the GHG rebalancing component.
• The ACC shall not cap the GHG value to the high Societal Cost of Carbon used in the Societal Cost Test.
• The ACC shall use the simplified Integrated Calculation, LOLH for capacity allocation, energy prices to allocate high generation capacity values, and weekday/weekend differentiation for reliability risk allocation.
• The ACC shall use IEPR future load forecasts for PCAF in transmission avoided-cost calculations and a DTIM-only method for marginal transmission costs.
• It is reasonable to continue other ACC methodologies from the 2024 ACC Decision unless explicitly changed here, and to affirm rulings by the assigned Administrative Law Judge (ALJ) or Commissioner concerning issues in this decision.

Order

• The CPUC adopts the updates described in the Conclusions of Law.
• All related ALJ/Commissioner rulings are affirmed; motions not ruled on are denied.
• Rulemaking 22-11-013 remains open.
• The order states it is effective “today” and is dated at Sacramento, California (date line left blank in the text).

Parties, models, and documents referenced

• California Public Utilities Commission (CPU C)
• Integrated Resource Plan (IRP)
• Strategic Energy & Risk Valuation Model (SERVM)
• RESOLVE model
• Integrated Energy Policy Report (IEPR)
• 2021 California Energy Commission (CEC) report on GHG abatement costs in buildings
• Assigned ALJ and assigned Commissioner (rulings affirmed)

This decision applies beginning with the 2026 ACC cycle and aligns ACC methodologies more closely with IRP and SERVM outputs to reflect evolving load and resource conditions from electrification and renewables. The proceeding remains open for any follow-up actions.

repowered and modernized brownfield assets as eligible, recognizing incremental hourly performance gains from dynamic tracking and DC-coupled battery storage. Permit LSEs to satisfy attribute allocations via verified incremental hourly shape enhancements from existing modernized facilities.

Opposition to Marginal ELCC (Response to Question 13)

Strongly oppose marginal ELCC accreditation as a moving target that risks collapsing toward zero and undermining long-term contracting. Recommend replacing it with 24-hour Slice-of-Day (SOD) certification aligned with RA methodology to avoid dual counting, provide stable price signals for smart technologies, and ensure accreditation reflects physical hourly deliverability for IRP-to-RA alignment.

Repowering and Brownfield Integration Urgency (Response to Question 21)

Reject deferral of repowering rules. With many PPAs expiring after 2033 and 26 GWdc 10+ years old in 2026 (rising to 127 GWdc by 2033), include repowering in 2028 base case plans and resource-to-busbar mapping. Excluding repowered resources risks selecting costlier greenfield builds and unnecessary transmission. Require 2028 TPP portfolios to reflect capacity achievable via tracking and DC-coupled battery additions.

Conclusion

Adopt attribute-based 24-hour profiles, replace marginal ELCC with SOD accreditation, and immediately incorporate repowering/brownfield optimization into 2028 planning to ensure affordability, reliability, and efficient grid use.

• Motion filed: July 24, 2026 (SCE Motion for Relief).
• Governing rule: Article 11.1(e).
• Shortened response period: 4 days.
• Response due date: July 31, 2026.
• Statutory deadline for the proceeding: September 30, 2026.
• Ruling issued and emailed: July 27, 2026; signed by Hazlyn C. Fortune.

Required Party Action and Guidance

Parties in R2005012 must file and serve comments addressing SCE’s July 24, 2026 Motion for Relief by July 31, 2026 so the comments can be addressed in the decision closing the proceeding. Parties should follow Article 11.1(e) as the baseline but adhere to the ALJ-ordered shortened timeline, confirm docketing with the Docket Office, and ensure service per the email distribution list.

Questions and Contact

If additional time is needed, parties must state the basis and whether expedited consideration is required given the September 30, 2026 deadline. Contact: Hazlyn C. Fortune, Administrative Law Judge, hazlyn.fortune@cpuc.ca.gov, 415-703-2317.

on broader reliability issues beyond the template itself.

Scope of the proceeding and whether the docket should remain open

• CforAT supports adoption of the reporting template, but says the rulemaking should remain open, or be replaced by a successor docket, so the Commission can continue addressing outage transparency, remediation, cost allocation, PSPS/EPSS/Fast-Trip issues, and broader reliability challenges.
• Marin Clean Energy, together with the Joint Local Governments and Pioneer Community Energy, opposes closing the proceeding after Track 1 and urges the Commission to keep R.24-05-023 open to address unresolved Track 2 issues. They also request an interim utility report by no later than December 2026.
• SBUA focuses on improving the template and does not oppose the PD’s overall direction, but requests additional process and customer-accessibility changes before implementation.
• RCRC supports the reporting framework but emphasizes that it should better support accountability for reliability outcomes and wildfire-mitigation-related investments.
• The Joint IOUs support adoption of the template and related schema, but do not address proceeding closure in the same way as the other commenters in their summary.

Reporting frequency, timing, and interim review

• CforAT argues that reliability reporting should be filed at least twice a year rather than annually, to reduce lag between outage events and reporting and better capture seasonal differences.
• Marin Clean Energy and the Joint Local Governments/CCAs ask for an interim report by December 2026 so the Commission can evaluate the reporting framework before later advice-letter review cycles begin.
• RCRC argues the current annual approach may be too slow for operational transparency and says more frequent reporting would better reflect current reliability conditions, especially for PG&E’s fast-trip/EPSS-related impacts.
• The Joint IOUs support annual reporting and say it balances usefulness and burden, while also asking for a post-initial review opportunity and more frequent feedback on the template than a three-year cadence alone.

Customer accessibility, narrative content, and template usability

• SBUA supports the template but asks the Commission to clarify that the Customer Reliability Report and schema should be usable by customers as well as the Commission. SBUA also wants a stakeholder workshop at least 60 days before the first annual filing.
• CforAT supports narrative reporting on outage communications but warns the narrative sections should not become boilerplate. It also asks for a mechanism allowing non-IOU parties to seek template updates if problems arise.
• The Joint IOUs support narrative summaries for notification efforts and say this approach provides context without duplicating data tables.
• RCRC supports more transparency in the template, including reporting that helps connect outage trends with utility operational changes and investment decisions.

Definitions and classification of outage types

• CforAT asks the Commission to define “customer with medical needs” more clearly and to distinguish planned maintenance outages from PSPS, Fast-Trip, and EPSS events. CforAT also supports treating PSPS and Fast-Trip as distinct from planned maintenance outages in the template.
• The Joint IOUs ask that PSPS, Fast-Trip, and EPSS remain classified as unplanned outages for reliability metric purposes, saying that reclassifying them would create inconsistencies with existing reporting and understate reliability impacts.
• RCRC requests clearer terminology around EPSS/PEDS and related fast-trip settings so the reporting better reflects operational changes affecting outage trends.

Repetitive outages, corrective actions, and reliability trend analysis

• RCRC wants utilities to identify circuits or geographic areas with repetitive outages and provide causes, planned corrective actions, implementation schedules, expected reliability improvements, and funding sources. RCRC also asks for a longer lookback period and year-over-year trend emphasis.
• Marin Clean Energy and the Joint Local Governments/CCAs stress that reporting alone will not fix reliability degradation and point to persistent fast-trip outage impacts as evidence that broader remedial action is needed.
• CforAT supports reporting that helps characterize outage patterns over time, including seasonal and customer-specific impacts, but argues the proceeding should continue so the Commission can act on reliability problems beyond the template.

Implementation burden, data limitations, and reporting governance

• The Joint IOUs say the customer-level outage reporting requirements are feasible only with substantial improvements in data quality, system capabilities, and internal processes, which may take multiple years and could require added costs or reprioritization of other work.
• The Joint IOUs also support standardized definitions and ask for clear authority to refine the template over time, while noting the need for realistic timelines and recognition of data limitations.
• CforAT asks that non-IOU parties also be allowed to request template changes, not just utilities, so the reporting framework can be corrected if it becomes less useful over time.

remains open.

ICA Workshops

The Commission adopts a biannual ICA workshop cadence beginning Q1 2027 and cancels the Q4 2026 ICA workshop required by Resolution E-5440. IOUs may file Tier 2 advice letters to propose further cadence modifications if they demonstrate either (1) hosting workshops is overly burdensome given current workload, or (2) ICA status/implementation schedules make biannual updates unsuitable.

Grid Modernization Progress Reports

IOUs must file biennial Grid Modernization Progress Reports in the fall of even-numbered years, due Oct. 1, starting in 2026, using Appendix A as the reporting template and pursuant to Pub. Util. Code § 913.6. Reports must:

• Explain past two years’ tool usage, benefits, and use cases
• Provide forward-looking plans for tools not yet implemented
• Note modifications to prior plans
• Include costs and timelines as specified in Appendix A

Energy Division and IOUs will jointly review Appendix A four months before submissions; Energy Division may adjust content/format and will circulate a revised Appendix A at least 30 days before IOU submissions.

Administrative

The decision affirms prior rulings, deems unresolved motions denied, and takes effect upon issuance.

Last Week's New Comments +56

R.21-06-017 Filing Update

This is a sampling of parties’ positions in the recent filings on the CPUC’s flexible service connections and DER orchestration issues. Across the submissions, parties generally support using flexible service connections to speed energization, improve utilization of existing distribution capacity, and reduce or defer upgrades, while differing on how prescriptive the Commission should be, how quickly to scale advanced technologies, and whether participation in real-time pricing should be voluntary or default.

Overall Direction: Flexible Service Connections and DER Orchestration

• Cal Advocates/M.Miley/CPUC supports flexible service connections as an affordability tool, but says the Commission should prioritize lower-cost options, require clear cost/benefit reporting, and defer broader deployment of technology-intensive approaches until pilots show net ratepayer value.
• PG&E supports continued development of DER orchestration and flexible service connections, but says implementation should be iterative, targeted to specific grid needs, and backed by reporting and governance standards before broad mandates.
• SCE supports the Commission’s goals and favors a two-part approach: near-term development programs to generate operational evidence, followed later by an end-state framework for scale.
• SDG&E supports the goals in principle but says the record is not yet sufficient for broad mandates in its territory; it urges sequencing and more utility-specific analysis before required offerings.
• CalCCA supports flexible service connections and DER orchestration, but says the Commission should resolve governance, market access, data, and compensation issues first and should also evaluate marketplace models alongside utility-led approaches.
• CALSSA, CALSTART, Tesla, Terawatt, Voltera, and Critical Loop generally support flexible service connections as a way to accelerate energization and reduce upgrade costs, while emphasizing the need for customer choice and practical implementation.

Operating Envelopes, Limited Power, and Static Service

• Cal Advocates/M.Miley/CPUC supports lower-cost options such as Limited Power and static operating envelopes as near-term, implementable solutions and says they should be used before more complex utility-controlled technologies.
• PG&E supports Limited Power and static offerings as options, but opposes making them a default mitigation or a permanent firm-capacity class.
• SCE supports exploring Limited Power and static operating envelopes, but says they should remain optional and should not be made default for all constrained projects.
• SDG&E supports Static/Limited Power as the most practical near-term option, but opposes making it a default requirement and says availability should depend on territory-specific feasibility.
• CALSTART, Terawatt, Tesla, and Mainspring support static or limited-power service as workable near-term tools, but they oppose mandatory UL 3141 certification as an across-the-board requirement.
• UCAN supports making Limited Power the default mitigation for transformer and secondary conductor constraints and wants static options to be available broadly.
• PACT supports evaluating Limited Power and Static Operating Envelope options whenever an upgrade would otherwise be triggered, but says customer participation must remain voluntary.
• Critical Loop supports a protected static floor for every Variable/Dynamic or durable non-bridging FSC, with add-on flexibility above that floor rather than replacing it.

Bridging vs. Non-Bridging Service and Customer Choice

• Cal Advocates/M.Miley/CPUC supports durable non-bridging pathways but says they should be developed carefully, with stronger evaluation and reporting and clearer treatment of the obligation to serve.
• PG&E says bridging solutions should be prioritized first; it argues that non-bridging arrangements are more complex and need a fuller record before broad deployment.
• SCE says bridging and non-bridging arrangements serve different purposes and that durable non-bridging offerings require additional policy work on compensation, permanence, and exit rules.
• Critical Loop strongly supports durable non-bridging service, but says it must be bankable, include a protected firm floor, and come with clear commercial terms.
• Terawatt, Voltera, Tesla, CALSTART, and PACT all support bridging solutions as a way to speed energization, while saying customers should retain an informed path to firm service.
• UCAN supports durable non-bridging service, including a long-term Standard Offer, and argues for a compensation and shared-savings framework.
• VGIC says non-bridging options should be prioritized because they can permanently defer upgrades, but they should be paired with incentives or shared savings to encourage uptake.

UL 3141, Certification, and Technical Safeguards

• Cal Advocates/M.Miley/CPUC supports customer-side certification and baseline cybersecurity requirements, but does not call for a universal UL 3141 mandate.
• PG&E says UL 3141 can be an acceptable option, but should not be the only allowed pathway because of cost, maturity, and scalability concerns.
• SDG&E supports UL 3141 as a safety baseline for certain offerings, but says certification and inspection requirements must be matched to the offering type and territory.
• SCE supports risk-based cybersecurity and certification-based approaches, while warning against rules that would be too rigid for immature technologies.
• CALSTART, Terawatt, Tesla, and Mainspring all oppose making UL 3141 a universal prerequisite for Limited Power or static service, arguing it is still too costly, scarce, or not yet mature.
• Critical Loop supports a certification-based approach for static service, but says communications-heavy requirements should not be imposed on non-communicating or local-only systems.

Variable/Dynamic Operating Envelopes and Grid Edge DERMS

• Cal Advocates/M.Miley/CPUC says variable and dynamic operating envelope solutions should be limited to use cases where their benefits clearly exceed costs, and it opposes directing utilities to scale Grid Edge DERMS technologies before pilots show value.
• PG&E supports Grid Edge DERMS pilots and scaling pathways, but says the Commission should use stage-gates and avoid premature mandates.
• SCE says Variable, Dynamic, and Grid Edge DERMS offerings are still emerging and should be validated through pilots and workshops before broad deployment.
• SDG&E says its current systems are not ready for a rapid rollout of Variable or Grid Edge DERMS offerings and argues those deployments should wait for utility-specific capability development.
• WeaveGrid supports Grid Edge DERMS as a practical implementation tool and says the Commission should allow phased deployment using commercially available technologies.
• Advanced Energy United supports Grid Edge DERMS and cloud-based aggregator architectures, but wants open-access, interoperable, and non-discriminatory rules in place first.
• CALSSA and CalCCA both support using marketplaces and aggregators to provide scalable alternatives to utility-built Grid Edge DERMS-only models.

Real-Time Pricing and Dynamic Rates

• Cal Advocates/M.Miley/CPUC urges stronger data tracking for any RTP-related offering and does not recommend default enrollment without a clearer evidentiary basis.
• PG&E opposes default enrollment of FSC customers onto RTP and says RTP should be presented as an option.
• SCE says RTP should remain opt-in until pilots show it is workable and valuable for customers.
• SDG&E says default RTP is premature in its territory because it does not yet have an RTP/DF rate in effect.
• CALSTART, Terawatt, Tesla, PACT, and TMH all say RTP should be voluntary or opt-in, especially for fleet customers with fixed duty cycles and limited flexibility.
• UCAN wants RTP to be opt-in, with shadow billing, bill protection, and a clear right of return.
• VGIC also says RTP and dynamic rates should be opt-in and requests clearer treatment of exports and bidirectional charging.
• EDF is the main commenter in this group supporting default RTP for flexible service connections.

Market Access, Interoperability, and Competition

• Cal Advocates/M.Miley/CPUC supports interoperability and customer choice, but says baseline rules and reporting should be in place before broader technology scaling.
• PG&E supports interoperability and open access, but prefers utility-led implementation flexibility and workshops over immediate prescriptive rules.
• SDG&E supports an interoperability workshop and says vendor lock-in and OEM fee structures should be addressed before deployment mandates.
• CalCCA, Advanced Energy United, and the Center for Biological Diversity all call for stronger open-access or competitive market frameworks, including independent monitoring and non-discriminatory participation rules.
• WeaveGrid supports allowing grid-edge platforms to work with utility systems and says procurement should remain flexible.
• Universal Devices argues for an open, plugin-based device-execution layer to avoid vendor lock-in.
• CALSSA, Terawatt, and PACT also stress vendor neutrality and non-exclusive access to utility program interfaces and data.

Valuation, Cost Recovery, and Reporting

• Cal Advocates/M.Miley/CPUC says the Commission should require a common cost-benefit framework that compares flexible solutions against the traditional wires baseline and tracks avoided, deferred, resized, or built upgrades.
• PG&E says affordability claims should be supported by verifiable net ratepayer benefit and full cost accounting, and it wants common affordability metrics.
• SCE says early programs may need funding for learning and development, but that scalable deployment should be based on operational evidence.
• EDF says cost allocation and recovery should be developed before large-scale deployment and that GRCs are the right venue for many recovery issues.
• CalCCA asks for a cost-benefit framework that includes societal and environmental benefits and that can support marketplace evaluation.
• Critical Loop, VGIC, and UCAN all argue that compensation or shared-savings mechanisms are necessary to unlock durable non-bridging adoption.
• PG&E and SDG&E both caution against using the proceeding as a broad funding vehicle for unproven technologies and say some costs belong in other proceedings or GRCs.

Workshops, Working Groups, and Sequencing

• Cal Advocates/M.Miley/CPUC recommends a Commission-led Track 2 working group to produce a common framework before any IOU applications.
• SDG&E also wants standards developed first, with implementation later through staged filings and workshops.
• CalCCA supports multiple working groups on visibility/data, TSO-DSO coordination, and market design/governance.
• Advanced Energy United wants a short, focused working group to set statewide open-access and interoperability guardrails before applications.
• CAISO supports recurring workshops on transmission-distribution coordination and wants clear prioritization rules before IOU filings.
• EDF supports a pre-application working group that defines implementation, cost-allocation, and evaluation frameworks.
• PG&E, SCE, and WeaveGrid all support workshops and phased implementation, with PG&E and SCE emphasizing that pilot learnings should feed the framework.
• CALSSA supports two shorter working groups rather than a single long one, with the first focused on basic structure and the second on program details.

Utility-Specific Positions on Scope and Readiness

• SDG&E says many of the Proposal’s requirements are not yet feasible in its territory and wants demand-tracking, not immediate statewide mandates, unless the record shows a need.
• SCE says its system topology and technology roadmap require a phased approach and that development should proceed in parallel with policy refinement.
• PG&E says it already has some program experience and supports staged scaling based on demonstrated benefits.
• WeaveGrid says utilities should be allowed to progress at different speeds while still moving toward common functional outcomes.