Simplifying Policy Management

suitable now. They stipulate to admit evidence proffered to date in Track Two and propose filing a joint motion to admit that evidence on June 4, 2026.

Disputed Issues

All scoping issues in the Amended Scoping Memo (Feb. 3, 2026) remain disputed. CalCCA, Joint IOUs, DACC/AREm, and Cal Advocates list extensive factual and legal disputes focused on valuation, allocation, and legal consistency of Pre-2019 Banked RECs and related PCIA/indifference issues.

Staff Proposal and Hearings

Parties disagree on whether the March 27, 2026 Staff Proposal should be addressed via comments or testimony. Cal Advocates, CalCCA, and DACC/AREm favor comments and removal/rescheduling of the April 28, 2026 evidentiary hearing (Cal Advocates tentatively proposed May 28, 2026 and May 15, 2026 deadline for hearing requests). Joint IOUs support testimony on the Staff Proposal.

Alternative Schedule and Request

Parties propose an alternative schedule (details filed with JCMS) omitting evidentiary hearings and enabling a final decision by September 17, 2026 so IOUs can reflect outcomes in October 2026 2027 ERRA Forecast Updates. They request the Commission adopt the alternative schedule and decide whether to allow comments or testimony on the Staff Proposal.

load-based allocation. One filing did not take a position on the merits but asked the Commission to resolve the matter quickly to reduce procurement uncertainty.

Background and procedural posture

• Multiple parties filed comments responding to the rehearing request directed at Decision 26-02-057 in R.25-06-019.
• Hydrostor did not address the merits of the rehearing request and instead focused on timing, urging prompt Commission action to reduce uncertainty in procurement planning.

Whether the Commission lawfully allocated the new procurement obligation to ESPs

• WPTF and 3PR support rehearing and argue that allocating part of the 6,000 MW procurement obligation to ESPs is unlawful because the Direct Access cap prevents ESPs from serving the new load that drives the need for additional resources.
• WPTF argues the allocation is unsupported because the decision does not show that ESPs can actually serve the forecast new load, and says the Commission should assign ESPs only the portion of procurement reasonably tied to loads eligible for Direct Access service.
• 3PR similarly argues that the decision lacks a sufficient causal link between current ESP load shares and the reliability need, and says procurement should be reassigned so ESPs are responsible only for load they can reasonably serve.
• EDF agrees there is a legitimate concern about requiring Direct Access ESPs to procure resources for load they are barred from serving, but says the rehearing request has not shown that the 6 GW order benefits only new load. EDF would support a narrower, evidence-based adjustment if a method is developed to isolate the portion of procurement tied solely to new load that ESPs cannot serve.
• SCE, CalCCA, and SDG&E oppose the rehearing request and defend the decision’s load-based allocation as lawful, reasonable, and consistent with Section 397 and prior Commission practice.
• SCE says the Commission properly used managed peak share as a proxy for each LSE’s contribution to system reliability needs and argues the decision is supported by substantial evidence.
• CalCCA says the Commission acted within its authority to assign procurement responsibilities to all LSEs, including ESPs, based on system reliability needs and a load-share methodology.
• SDG&E says the decision’s findings that all customers contribute to and benefit from reliability are sufficient to support the allocation and that the rehearing request largely repeats arguments the Commission already considered and rejected.

Direct Access cap and cost-shifting concerns

• WPTF and 3PR argue the Direct Access cap is central to the rehearing request because it limits ESPs’ ability to serve the incremental load that is driving the need for new procurement, making the allocation to ESPs improper and potentially cost shifting.
• EDF says the Commission should be careful to limit any adjustment to Direct Access ESPs and to base it on the statutory prohibition on serving new load, rather than broadening the issue to other LSE categories.
• SCE argues the cap does not eliminate ESP customers’ contribution to peak demand or their benefit from system reliability, and says exempting ESPs would create cost shifting to bundled and CCA customers.
• SDG&E likewise argues that the cost-shift theory is flawed because the Commission found all customers contribute to the need and because the request would improperly relitigate issues already decided.
• CalCCA contends any broader reallocation should be developed holistically because current load-share methods may be imperfect, but it does not agree that the rehearing request itself establishes unlawful cost shifting.

Requested remedy and scope of rehearing

• WPTF and 3PR urge the Commission to grant rehearing and revise the allocation methodology so ESP obligations reflect only load they can reasonably serve.
• EDF says a narrower amendment may be appropriate only if supported by a robust evidence-based allocation method, and suggests that any fix be limited in scope to avoid unintended effects on other LSEs.
• SCE, CalCCA, and SDG&E argue the rehearing request is an improper vehicle for revisiting Direct Access policy or reopening D.21-06-033, which they say belongs in a different proceeding or through a petition for modification in the original docket.
• CalCCA adds that if the Commission does revisit allocation methodology, it should do so in a broader procurement framework rather than through rehearing of this decision.
• Hydrostor does not address the remedy on the merits but urges the Commission to act quickly and within the rehearing’s narrow scope to avoid creating additional uncertainty.

Timing and procurement certainty

• Hydrostor says prompt resolution is important because uncertainty around ELCC values and the procurement obligation could increase risk premiums and slow contracting for long-lead-time resources such as storage.
• Hydrostor asks the Commission to issue a decision as soon as practicable, and no later than the first revised ELCC date of July 31, 2026.

assumptions, calibration, and modeling transparency

• California Community Choice Association (CalCCA) said the draft LOLE inputs should be refined through additional workshops and more validation, including on the link between LOLE results and PRM outcomes. CalCCA also urged closer review of demand modeling, BTM PV treatment, hydro assumptions, and load forecast error assumptions.
• Middle River Power LLC (MRP) supported additional technical clarity in the final inputs and assumptions, including using newly in-development resources where feasible, providing both UCAP- and Pmax-based PRMs, and separating LOLE studies from PRM proposals to improve transparency.
• Southern California Edison (SCE) supported analytically grounded LOLE studies but cautioned against assumptions that it said could force higher PRMs, including uniform monthly import constraints and overly conservative uncertainty treatments.
• Alliance for Retail Energy Markets (AReM) supported a 0.1 annual LOLE calibration approach and asked Energy Division to continue using a transparent calibration process, with additional sensitivity analysis where helpful.

Imports, external-region reliability, and out-of-state resource assumptions

• Western Power Trading Forum (WPTF) said Energy Division should update external-region assumptions to better reflect near-term reliability risks in the Pacific Northwest and should include a sensitivity case with lower external surplus capacity or higher external LOLE.
• California Community Choice Association (CalCCA) opposed a zero-import assumption for RA/PRM modeling and pointed to recent historical import showings and existing out-of-state procurement as reasons to retain more realistic import assumptions.
• American Clean Power - California (ACP-California) said the draft study overstates the availability of uncontracted imports and should be refreshed to better reflect tightening regional markets and changing resource balances across the West.
• Southern California Edison (SCE) argued against uniformly applying a 4,000 MW simultaneous import constraint in every month and said any reduction below that level should be justified by physical evidence rather than by desired LOLE outcomes.

Storage, local capacity, and the role of local procurement

• CEJA and Sierra Club, in comments on CAISO’s Draft 2027 Local Capacity Technical Report, said local capacity needs are rising and that the Commission should take proactive steps on local procurement rather than simply accept CAISO’s values. They urged a public local procurement tracker and coordination with the IRP.
• CEJA and Sierra Club also argued that storage can displace gas capacity only up to local charging limits, so the Commission should understand where storage is most effective and where local generation will still be needed.
• NextEra Energy Resources, LLC said storage modeling assumptions should better reflect modern battery operations, including the assumed discharge range, round-trip efficiency assumptions across different technologies, and asymmetric charging/discharging configurations.
• California Community Choice Association (CalCCA) said the study should better account for BTM PV, hydro flexibility, and more realistic load modifier behavior, all of which affect how much local and system-wide capacity is actually needed.

Affordability, resource counting, and market-design issues

• CEJA and Sierra Club said PRM and LOLE decisions should account for affordability, public health, and emissions impacts, and should avoid overreliance on fossil generation where cleaner local options are available.
• California Community Choice Association (CalCCA) said the Commission should consider affordability in how it translates LOLE into PRM and should make sure the modeling reflects actual load shapes, customer behavior, and recent forecast experience.
• American Clean Power - California (ACP-California) supported clearer treatment of Unforced Capacity and asked for better coordination between RA and IRP so physical capacity additions can be fully recognized.
• California Community Choice Association (CalCCA), in a separate filing on load obligation trading, urged adoption of a voluntary bilateral trading mechanism to reduce excess procurement costs and improve RA efficiency, while addressing broader implementation issues in the appropriate proceedings.

Procedural and record-building requests

• California Community Choice Association (CalCCA) and Middle River Power LLC (MRP) both called for a stronger evidentiary record, with more transparent assumptions and clearer separation between study results and policy proposals.
• Alliance for Retail Energy Markets (AReM) asked for additional sensitivity testing of different calibration methods so stakeholders can better compare results.
• Western Power Trading Forum (WPTF) asked Energy Division to publish external-region LOLE or EUE metrics used in the study so stakeholders can evaluate import assumptions more directly.

improvements to Distribution Planning and Execution, Distribution Resource Planning Data Portals, and ICA Maps; continue DPAG meetings/reporting to improve transparency of DUPR and related annual reports. Follow Resolution E-5414 Scenario Planning and Decision Logic Framework obligations.

Submissions, Decision Logic, and deadlines

Joint Utility IEPR scenarios: May 9, 2025 (earlier) and May 8, 2026 for 2026-2027. Present IEPR/Scenario Planning at 2026 DFWG workshop. Joint Utilities to present proposed Decision Logic Frameworks in Fall 2026 for 2026-2027 GNA/DUPR (to be published Aug 2027). SDG&E to provide engineering explanations instead of a DLF; PG&E and SCE to update DLFs for 2025-2026. Energy Division decisions: June 12, 2026 (PG&E/SCE DLFs and SDG&E explanations); Aug 1, 2025 and July 31, 2026 (IEPR/Scenario approvals); Oct 23, 2026 (2026-2027 DLFs).

GNA/DUPR, IPE filings and schedule

Utilities file 2025-26 GNA/DUPR with Final IPE Plan by Aug 17, 2026; 2026-27 by Aug 16, 2027. DRP Portal updates: Aug 28, 2026 and Aug 27, 2027. IPE Preliminary Analysis: Sep 4, 2026 and Sep 3, 2027. IPE DPAG Report: Nov 6, 2026 and Nov 5, 2027. Joint IPE Post-DPAG Report: Mar 15, 2027 and Mar 13, 2028.

Workshops, DPAG, and stakeholder process

2026 DFWG workshop week of May 18, 2026; 2027 week of May 17, 2027. DPAG meetings week of Sep 14, 2026 and Sep 13, 2027; agendas due 10 days prior. Joint Utilities coordinate follow-up with Energy Division week of Oct 12, 2026 and Oct 11, 2027.

Questions, responses, and other requirements

Stakeholder questions/comments due to service list by Sep 25, 2026 (and Sep 24, 2027). Utilities respond by Oct 5, 2026 (and Oct 4, 2027). Joint Utilities to propose hot spot calculation at DFWG. Optional line-section data supplements allowed for 2025-26 GNA/DUPR. The schedule implements D.24-10-030 and Resolution E-5414 and is binding.

Last Week's New Comments +16

Overview

This week’s filings are a continuation of last week’s discussion in R.21-06-017, and this digest incorporates both last week’s and this week’s comments. The record continues to focus on how to structure IOU-led DER orchestration, with recurring themes around whether the Commission should set a statewide framework first, how much discretion IOUs should have, how to value distribution-level flexibility, and what roles aggregators, CCAs, CAISO, and customer-side technologies should play. A sampling of parties’ positions shows broad agreement that orchestration can reduce costs and improve reliability, but significant disagreement over framework design, market access, technology standards, cost recovery, and whether to move directly to IOU application filings.

Overall framework and procedural path

• Pacific Gas and Electric Company supports a phased, evidence-based, implementation-focused approach and says the Commission should allow IOUs to propose frameworks and pilots that can later scale.
• San Diego Gas & Electric Company similarly favors a “framework-first” approach that separates approval of a durable orchestration framework from approval of specific programs or pilots.
• Southern California Edison Company supports DER orchestration but wants implementation tailored by utility and informed by readiness, rather than a one-size-fits-all mandate.
• Cal Advocates/M.Miley/CPUC argues that moving immediately to IOU applications is premature and says Track 2 framework issues should be completed first through a working-group process.
• Advanced Energy United also objects to separate IOU application proceedings and urges the Commission to establish core, statewide framework elements before any utility-specific filings.
• Clean Coalition says the record is not yet developed enough for a durable framework and recommends additional workshops, minimum guardrails, and a pilot-first approach.
• California Community Choice Association urges the Commission to evaluate alternative DSO models, not just an IOU-led model, before deciding on the framework.

Primary objectives and use cases

• Pacific Gas and Electric Company emphasizes affordability, reliability, faster energization, grid deferral, and operational cost reduction, with a strong focus on downward rate pressure.
• San Diego Gas & Electric Company identifies reliability, DSO visibility, workable participation pathways, and cost-effective distribution services as its main objectives.
• Southern California Edison Company focuses on affordability, speed-to-power, targeted distribution benefits, and safe, reliable grid operation.
• Utility Consumers’ Action Network says the main objective should be minimizing total system costs by avoiding or deferring capital-intensive distribution upgrades.
• California Solar & Storage Association argues the primary objective should be energy affordability through cost-effective load shifting and capacity-style DER participation.
• 350 Bay Area similarly frames the objective as ratepayer savings and emissions reduction through better use of distribution-level resources.
• Environmental Defense Fund recommends affordability, reliability, and sustainability as the core objectives.
• Nexamp, Inc. focuses on expanding hosting capacity, speeding energization, and enabling transparent compensation for distribution-level services.
• California Community Choice Association emphasizes verifiable net benefits, optimized distribution capacity, faster energization, and open access for customer-, CCA-, and third-party-managed DERs.

Valuation, avoided costs, and shared savings

• Pacific Gas and Electric Company wants affordability and downward rate pressure to be central to valuation and says orchestration costs must be lower than alternatives.
• San Diego Gas & Electric Company recommends using the California Standard Practice Manual as the core valuation framework, while capturing locational and operational value.
• Southern California Edison Company says valuation should include avoided or deferred distribution upgrades, energization benefits, operational savings, and reliability value.
• Cal Advocates/M.Miley/CPUC says valuation must be use-case-, location-, and time-specific, include full incremental costs, and distinguish deferral from true avoidance.
• Utility Consumers’ Action Network recommends the Avoided Cost Calculator and a robust locational net benefits analysis, while warning against premature shared savings incentives.
• Environmental Defense Fund supports starting with existing avoided-cost and cost-effectiveness tools but says the methodology should evolve to capture distribution congestion and broader social benefits.
• California Efficiency + Demand Management Council supports avoided-cost-based valuation and says compensation should be transparent, location-specific, and non-discriminatory.
• California Solar & Storage Association favors capacity payments and says distribution-triggered DER dispatch should be treated as a way to provide distribution capacity.
• Nexamp, Inc. supports locational, performance-based net benefits and conditionally supports a shared savings mechanism only for verified net savings.
• PG&E supports a shared savings mechanism if it is transparent, simple, and tied to durable ratepayer benefits; SDG&E says utilities may propose one; SCE says SSM should not be included here; Cal Advocates opposes SSM at this stage; EDF opposes SSM for orchestration itself; 350 Bay Area is skeptical of SSMs and suggests possible downside mechanisms if savings are not delivered.

Guiding principles and market access

• Pacific Gas and Electric Company supports the proposed principles but wants precise definitions and phased implementation, with strong protections against double compensation and double counting.
• San Diego Gas & Electric Company supports the principles and adds “safe and reliable grid operation” as a fundamental principle.
• Southern California Edison Company supports the principles but says the Commission should prioritize them rather than treat them as equally weighted in all cases.
• Cal Advocates/M.Miley/CPUC supports the core principles and emphasizes ratepayer protection, locational value, and incremental implementation.
• California Community Choice Association supports the proposed principles but adds nondiscriminatory access, independent oversight, competitive neutrality, fair compensation, and timely access to data.
• Utility Consumers’ Action Network adds fostering third-party competition and protocol neutrality/scalability.
• Environmental Defense Fund adds cost-reflective, bidirectional price signals and explicit data privacy/customer-consent protections.
• California Efficiency + Demand Management Council emphasizes open-platform design, transparent valuation, wholesale integration, and centralized visibility to prevent double compensation and utility self-preferencing.
• 350 Bay Area asks for clearer treatment of customer versus ratepayer impacts and wants “accessible” participation pathways.
• Advanced Energy United emphasizes statewide consistency, open access, and competition across IOUs and third parties.

Interoperability, communications, and technology standards

• Pacific Gas and Electric Company proposes standardized protocols such as IEEE 2030.5 and wants interoperability strategies presented in utility applications.
• San Diego Gas & Electric Company says interoperability strategies should address vendor and signaling constraints and notes it will address communication protocols in its Grid Modernization Plan.
• Southern California Edison Company supports IEEE 2030.5/CSIP as a key scaling tool and wants further interoperability discussion in a later track.
• Utility Consumers’ Action Network warns against mandating a single proprietary protocol and says secure, scalable alternatives such as OpenADR can work.
• California Efficiency + Demand Management Council calls for harmonized standards, standard aggregator-to-DSO interfaces, and backward-compatible certification/testing.
• Environmental Defense Fund supports IEEE 2030.5 and OpenADR as core components and warns against proprietary lock-in.
• EnergyHub says protocol-neutral and API-based integrations can scale quickly and that the framework should not be tied to one communications standard.
• Advanced Energy United stresses statewide “plug-and-play” interoperability so the system does not become balkanized across IOUs.
• California Solar & Storage Association says IEEE 2030.5 is a useful near-term basis, but utilities should not mandate a single standard.
• Clean Coalition says the record needs more clarity on how utility DERMS and third-party systems will interact.

Readiness, phasing, pilots, and use of EIS Part 2

• Pacific Gas and Electric Company supports sandboxing, pilots, and phased scale-up after demonstrated readiness, with EIS Part 2 informing planning beginning in the 2027–2028 cycle.
• San Diego Gas & Electric Company says EIS Part 2 should not be used to pick pilot geographies.
• Southern California Edison Company also opposes using EIS Part 2 scenario results to determine phasing or pilot locations.
• Cal Advocates/M.Miley/CPUC says EIS Part 2 is too granularly limited for siting pilots and should not drive deployment decisions.
• Environmental Defense Fund says EIS Part 2 can help identify candidate pilot areas, but IOUs should prioritize locations with meaningful DER deployments and diverse constraint types.
• Nexamp, Inc. wants EIS Part 2 used to target areas with high electrification growth and limited capacity.
• California Community Choice Association says EIS Part 2 should guide pilot identification and phased deployment, especially for equity-focused locations.
• California Solar & Storage Association interprets EIS Part 2 as showing major savings potential and wants initial programs aimed at high-upgrade-cost geographies.
• 350 Bay Area says EIS Part 2 should help identify pilot areas with meaningful DER deployments and grid constraints.
• Small Business Utility Advocates supports phased implementation but stresses that readiness documentation should reflect small commercial customer needs as well.

Aggregators, CCAs, customer-side devices, and participation rules

• Pacific Gas and Electric Company says aggregators should have clearly defined roles, performance standards, and accountability within an IOU-led framework.
• San Diego Gas & Electric Company says aggregator roles should be formalized through contracts and tariffs, with responsibilities and remedies clearly defined.
• Southern California Edison Company says third-party aggregators will likely be necessary at the grid edge initially but should not be prescriptively elevated in the framework.
• Utility Consumers’ Action Network says aggregators should be co-equal participants and that utilities should not dictate internal device protocols when edge performance standards are met.
• California Efficiency + Demand Management Council says aggregators should be primary interfaces and that the framework must preserve customer choice and wholesale participation where feasible.
• California Community Choice Association says the framework must be open to customer-, CCA-, and third-party-managed DERs and should not assume an IOU monopoly on orchestration.
• California Solar & Storage Association says aggregators should operate fleets and should interface with DSOs through dispatch and performance reporting.
• EnergyHub says aggregators are important but not the only viable ecosystem participant; OEMs, TPOs, and Edge DERMS can also play roles.
• Clean Coalition and Advanced Energy United both stress that third-party and hybrid models should remain available, not displaced by IOU-only structures.

Technology ownership, cost recovery, and utility investments

• Pacific Gas and Electric Company favors IOU ownership of DERMS-related orchestration capabilities and says cost estimates should focus on utility-owned systems.
• San Diego Gas & Electric Company says utility-side technologies should generally be utility-owned and customer-side technologies customer-owned, with communications responsibilities handled by contract.
• Southern California Edison Company says technology investment requests are better addressed through GRC filings and that ownership models should be disclosed transparently when requested.
• Cal Advocates/M.Miley/CPUC says ADMS/DERMS investments should not be used as a separate vehicle to authorize broad new spending outside the GRC.
• Utility Consumers’ Action Network urges an alternatives analysis and total resource cost test before approving utility-owned IT or communications investments.
• Environmental Defense Fund wants IOUs to identify specific technologies, costs, and ownership models, and prefers customer ownership of behind-the-meter devices with IOU-defined interface standards.
• California Community Choice Association says core utility platform functions may be utility-based, but default ownership should remain with customers unless a utility can justify otherwise.
• California Solar & Storage Association says DERMS are utility infrastructure, while device-level controls should generally be customer- or third-party-owned.
• 350 Bay Area urges low-cost solutions first and warns against high-cost communications or device investments that may not pay off.
• EnergyHub emphasizes software-based Edge-DERMS as a practical way to scale capability without heavy new infrastructure.

TSO-DSO coordination, CAISO visibility, and wholesale market interaction

• Pacific Gas and Electric Company wants the TSO-DSO workshop to focus on specific data gaps, aggregation levels, and roles, and supports joint PG&E-CAISO work on distribution-to-transmission data sharing.
• San Diego Gas & Electric Company wants coordination to support forecasting and reliability, with wholesale participation treated as optional rather than foundational.
• Southern California Edison Company says the workshop should determine how much visibility CAISO needs without requiring device-level granularity.
• CAISO supports a holistic framework, multi-directional data exchange, and workshop work on operational coordination, and says reliability should be explicitly recognized as a guiding principle.
• California Community Choice Association says TSO-DSO coordination should focus on minimum viable data exchange, registration, telemetry, and avoiding double compensation while preserving market participation pathways.
• California Efficiency + Demand Management Council says the workshop should define minimum viable data, latency, privacy, governance, and standardized registration requirements.
• Environmental Defense Fund says the workshop should establish the minimum viable data set CAISO needs and how IOUs can provide it.
• Utility Consumers’ Action Network says the workshop should focus on what CAISO needs for forecasting and reliability, with wholesale market issues addressed only at a high level.
• California Solar & Storage Association says latency, DERMS vendors, and integration requirements should be discussed, but distribution-triggered participation should not require wholesale participation.
• California Community Choice Association and California Efficiency + Demand Management Council both stress that aggregators need clear protections against conflicting DSO and CAISO signals.

ICA workshops and grid modernization reporting

• Pacific Gas and Electric Company, San Diego Gas & Electric Company, Southern California Edison Company, Environmental Defense Fund, and California Efficiency + Demand Management Council support moving ICA workshops to a biannual cadence tied to biannual ICA reports.
• Cal Advocates/M.Miley/CPUC and 350 Bay Area oppose reducing ICA workshop frequency and want quarterly workshops to continue.
• Pacific Gas and Electric Company and Southern California Edison Company support some form of advice-letter process for workshop frequency changes, while SDG&E and others favor flexibility in how modifications are made.
• California Solar & Storage Association wants more detailed grid modernization reporting, including real-world use cases and timelines.
• Environmental Defense Fund supports Appendix A-style reporting with stronger quantitative detail and generally supports Energy Division authority to direct changes.
• Pacific Gas and Electric Company wants costs removed from the grid modernization report and prefers GRCs as the source of record for cost information.
• Southern California Edison Company also wants cost reporting scoped away from the biennial report and located in GRC filings.
• San Diego Gas & Electric Company opposes codifying Appendix A as a mandatory format.
• Cal Advocates/M.Miley/CPUC supports adopting Appendix A and adding deployment-status and next-phase-dependency fields.

Real-time pricing and flexibility programs

• Pacific Gas and Electric Company says real-time pricing is complementary but distinct from orchestration and is better suited to non-firm uses.
• Utility Consumers’ Action Network says customers should not be forced onto dynamic or real-time rates as a condition of orchestration participation.
• Environmental Defense Fund says price signals and dispatch signals should be coordinated and that price-based approaches can complement orchestration.
• EnergyHub says Edge-DERMS can co-optimize customer bills and utility grid needs using real-time pricing signals.
• 350 Bay Area says orchestration should be compatible with real-time pricing where possible, but the signals must not conflict with participants’ financial interests.

Sampling note

This is a sampling of the parties’ positions reflected in the April 20, 2026 filings. The overall pattern is that most parties agree DER orchestration can provide meaningful distribution and customer benefits, but they differ sharply on whether the Commission should first establish a statewide framework, how much control IOUs should have, how to structure competition and interoperability, and how to measure and recover costs.