Simplifying Policy Management

April 15, 2026 Cal Advocates, CalCCA, AReM, DACC, PG&E, SDG&E, and SCE jointly requested canceling April 28, allowing testimony, and holding hearings in early June (proposed June 4–5) with a September 17, 2026 final decision to inform October 2026 ERRA Forecast Updates. The ALJ on April 16 denied June 4–5 due to resource limits, invited alternate schedules, and required settlements be filed at least 105 days before a target voting meeting. Parties filed a Joint Case Management Statement on April 21, 2026.

Key Deadlines

• Opening testimony: May 12, 2026
• Rebuttal testimony: May 22, 2026
• Settlement or motion requesting hearings: May 26, 2026
• ALJ ruling on need for hearings: May 27, 2026
• Evidentiary hearing (remote), if needed: June 2, 2026
• Opening briefs: June 16, 2026
• Reply briefs: June 25, 2026
• Proposed Decision issued: August 17, 2026
• Commission Decision (voting meeting): September 17, 2026

Actions for parties: serve testimony by the May dates, present settlement or file a hearing motion by May 26, comply with the 105-day settlement timing for a September 17 vote, and be prepared for a June 2 remote hearing if ordered. The April 8, 2026 directions related to the April 28 hearing and Rule 13.9 Joint Case Management Statement are cancelled.

maturity, and existing statutory frameworks.

Energization timeline compliance, remedial actions, and enforcement

• SEIA says the Commission should use the biannual utility reports to determine whether each IOU meets the 30-day average and 45-day maximum MPU targets, and should order remedial action when an IOU is more than five percentage points below the 95% compliance threshold. SEIA also urges a citation-based penalty framework for failures to comply with remedial actions by the January 1, 2027 enforcement deadline.
• SDG&E says remedial actions should be utility-specific, evidence-based, and tied to persistent material underperformance. It argues penalties should be reserved for severe, repeated, or willful noncompliance with ordered remedial actions, and that the Commission should use a progressive enforcement approach with an opportunity to cure in most cases.

Reporting, staffing, and data limitations

• SEIA says the current biannual reports show uneven utility compliance with required data fields and do not yet provide a clear plan for reaching the energization targets. It also notes Section 935(a) staffing reporting is already underway, but further staffing action may be needed depending on utility-specific circumstances.
• CALSTART supports rigorous utility workforce analysis and sufficient staffing approvals, and says utility staffing is a primary constraint on faster energization timelines.
• SDG&E says it has already complied with Section 935(a) staffing reporting and recommends that the Commission rely on the statutory reporting cadence and GRC process rather than layering on additional staffing-reporting requirements.

Audit requirements and auditor selection

• SEIA says SB 410 and SB 254 audits should not be funded by ratepayers and supports audit oversight as part of accountability for energization performance.
• SDG&E opposes a single joint auditor for the Large IOUs under SB 254, arguing that utility-specific retention is preferable and that existing SB 410 audit arrangements should be leveraged where possible. It also says SB 254 audit costs should be recoverable under ordinary ratemaking principles, subject to reasonableness review.
• CalSSA’s filing in the docket appears to be a non-substantive entry with no visible comment content in the provided materials.

Standardization of energization processes

• CALSTART supports further standardization and process reform, including standardized service-level agreements, expanded project management portals, and clearer utility-controlled sub-steps so timeline targets translate into shorter real-world project duration.
• SEIA recommends that the Commission prioritize utility compliance with existing energization targets and reporting requirements before pursuing broader cross-utility standardization.
• SDG&E says additional prescriptive standardization is premature at this stage and recommends limiting any future action, if needed, to reporting consistency rather than operational standardization.

Pre-intake, intake, and early-stage process reforms

• CALSTART recommends greater upfront transparency for Unit Cost Guides and Rule 15/16 allowance assumptions, more defined SLAs, earlier and more complete pre-application information, faster application completeness review, and better project-management tools to reduce delays before and during intake.
• CALSTART also supports making power reservation and early large-load screening tools more predictable, and says pre-application load-limit and large-load study steps should be faster and more transparent.

Post-intake workflow, sequencing, and upstream coordination

• CALSTART urges more parallel processing of utility activities after intake, including permitting, easements, outage scheduling, and construction preparation, rather than the sequential approach it says is still causing avoidable delay.
• CALSTART also argues utilities should not reset timelines for previously scoped work when incremental project changes occur, and should allow qualified third-party engineers and construction providers to help expand capacity.
• SDG&E emphasizes that existing data systems still limit precise step-by-step accountability, and says remedial actions and monitoring should account for those limitations and the maturity of utility systems.

Main panel upgrades and utility performance

• SEIA focuses heavily on main panel upgrades, arguing that the utilities’ reports should be used to measure compliance with the D.24-09-020 targets and to determine whether remedial actions are needed.
• SEIA says PG&E appears closest to the compliance threshold, while SDG&E and SCE do not yet appear to meet the standard based on the available reporting.

Green Access Programs and reporting requirements.

CREP viability, funding, and the basic program design

• Dimension Energy, LLC says the PD does not resolve key implementation issues and would not produce a viable, statutory-compliant CREP because it leaves the bill-credit design unresolved and relies on ReMAT without sufficient modification.
• SEIA and CCSA argue the PD effectively leaves CREP without workable economics because the anticipated outside funding is no longer available and the remaining ReMAT-based compensation is unlikely to attract development.
• The Clean Coalition says the PD should be revised to recognize that CREP cannot be implemented as viable under current funding conditions unless supplemental funding or a financeable compensation framework is identified.
• PG&E supports the PD’s overall objective and supports using ReMAT as a foundation, but asks for targeted refinements so the tariff can be implemented in practice.
• SCE supports the PD’s pragmatic approach, while requesting clarifications and limited modifications to make the program workable.
• SDG&E supports the PD’s pricing objective, but argues the Commission should first make a utility-specific determination on whether CRE should apply in SDG&E’s territory.
• The Joint CCAs and the City and County of San Francisco say the PD needs revisions to clarify how the customer bill discount will be funded and recovered now that anticipated state and federal funding sources are unavailable.

Bill credits, low-income requirements, and statutory compliance

• Dimension Energy, LLC says the PD does not adequately implement Public Utilities Code section 769.3 because it leaves unresolved how bill credits will be set, how low-income participation will be assured, and whether credits will reflect avoided costs.
• SEIA and CCSA say the PD fails to address the unresolved implementation issues identified earlier in the proceeding, including how to calculate low-income revenue shares, how bill credits should be applied, and how enrollment should work.
• The Joint CCAs and the City and County of San Francisco say the PD does not explain how the CRE customer bill discount will be funded or recovered without the revoked public funding sources, and they ask the Commission to clarify the calculation methodology.
• SCE seeks clarification on account-authority and cost-recovery mechanisms so the utilities can implement the CRE program without unfunded mandates.

ReMAT, technology eligibility, and pricing mechanics

• Dimension Energy, LLC says the current ReMAT structure is not a viable underlying tariff for CREP and would not incent solar-plus-storage development or meaningful participation.
• SEIA and CCSA say ReMAT-level compensation, when combined with low-income bill-credit obligations, is not financeable and will not attract developers under current conditions.
• The Joint CCAs and the City and County of San Francisco ask the Commission to update the ReMAT framework so it can accommodate all CRE-eligible technologies and to develop standard offer pricing for battery storage resources.
• The Clean Coalition says the PD should not proceed unchanged because it preserves ReMAT-level compensation without a clear mechanism to value avoided transmission, distribution, generation capacity, and resilience benefits.

Advice letters, implementation timing, and Commission process

• Dimension Energy, LLC argues that unresolved policy issues are too substantive and controversial to be handled through advice letters and should instead be resolved in a formal proceeding with a fuller record.
• PG&E requests more time than the PD provides, asking for 120 days to file the CRE tariff and implementation plan and separate timing for the marketing plan.
• SCE asks for a 90-day deadline for both CRE and MGT implementation filings so the IOUs can coordinate and develop consistent tariff designs.
• SDG&E asks for 60-day tariff filings for CRE, plus a sunset option if the tariff does not attract participation.
• The Joint CCAs and the City and County of San Francisco say CCAs should be able to file implementation plans within 180 days and should be allowed to begin or end participation by notifying the Commission.

Cost tracking, balancing accounts, and recovery proposals

• PG&E requests authorization to open a CRE subaccount to track implementation, administration, marketing, education, and outreach costs, and to recover those costs through the Public Purpose Program charge.
• SCE says the PD should authorize advice letters to establish balancing accounts or subaccounts for CRE and MGT costs, including a CREPBA subaccount for incremental CRE costs and an MGT balancing account for MGT-related costs.
• SDG&E also asks for a mechanism to record and recover CRE marketing, implementation, and ongoing administrative costs, along with an annual budget review process.
• PG&E and SCE both seek explicit authority to establish accounting mechanisms so costs can be tracked before recovery is sought.

Program sunset and participation limits

• PG&E proposes a sunset mechanism that would allow the program to close if no developer executes a ReMAT power purchase agreement for a CRE project over a three-year period.
• SDG&E proposes a shorter sunset trigger for its service territory, arguing CRE is unlikely to be viable there and should be allowed to end if no projects move forward within 12 months after the tariff is approved.

Utility-specific treatment and SDG&E’s exemption request

• SDG&E argues the Commission should make a utility-specific finding under section 769.3(b)(2)(A) and exempt SDG&E from CRE because it says local market conditions make the program unlikely to be viable in its territory.
• SDG&E cites siting constraints, coastal climate effects, land costs, and its small bundled customer base as reasons CRE would be difficult to implement locally.

DG Stats reporting and cost allocation

• PG&E supports moving reporting to the DG Stats platform but wants the timing tied to vendor readiness rather than a fixed deadline.
• SCE asks the Commission to clarify which reporting and expenditure issues for DAC-GT belong in the ERRA Forecast proceeding versus the ERRA Compliance Review.
• SDG&E objects to an even split of DG Stats transition costs and proposes allocating them based on participation and activity levels.
• The Joint CCAs and the City and County of San Francisco want CSGT expressly included in the DG Stats transition and related co-funding arrangements.

Related Green Access Program issues, including MGT and CSGT

• PG&E and SCE both ask for explicit cost-tracking authority for the Modified Green Tariff so the utilities can recover incremental administration and resource costs.
• The Joint CCAs and the City and County of San Francisco ask that CSGT be expressly addressed in the PD, including funding, evaluation, and data-reporting provisions.
• SDG&E also proposes a balancing-account framework for Modified GT and annual budget filings for ongoing administration.

such as vehicle-to-grid, bidirectional charging, storage, and other distributed energy resources.

Screen Q / Screen R and access to transmission studies

• SEIA says the removal of CAISO’s EIT created a gap in Rule 21 Screen Q and argues the current Screen Q / Screen R framework is inconsistent across utilities and increasingly leads to project failures, withdrawals, and long delays.
• SEIA proposes revising the flow-impact test, using more current base cases, and creating an affected-system or parallel study pathway so projects that fail Screen Q do not have to withdraw and re-enter the queue through WDAT cluster studies.
• CalCCA supports raising the Screen Q exemption threshold from 1 MVA to 5 MVA as a near-term way to reduce the number of projects pushed into CAISO cluster studies.
• PG&E supports a targeted Screen Q refinement that would make the EIT fail only when both DFAX and flow-impact thresholds are exceeded, and says this would reduce unnecessary studies for projects with de minimis transmission impacts.
• CESA says Screen Q has become a near-automatic barrier for many DERs above 1 MW and supports an alternative cost-responsibility pathway for projects that fail Screen Q but do not individually trigger network upgrades.

Interconnection timelines, enforcement, and reporting

• SEIA supports stronger timeline accountability and says the existing reporting framework should be refined so each IOU must meet each applicable deadline for 95% of relevant projects.
• CalCCA urges the Commission to adopt tiered quarterly fines for IOU non-compliance, with additional daily fines for persistent project-level delays.
• Advanced Energy United supports enforceable timeline compliance measures and says the Commission should adopt penalties if utilities continue missing Rule 21 deadlines.
• IREC argues that reporting without enforcement has not worked and proposes an interconnection timeline citation program with aggregate and project-level penalties.
• CESA supports meaningful compliance mechanisms, including performance incentives, financial penalties, staffing requirements, and real-time applicant-accessible tracking.
• PG&E says the D.20-09-035 timeline framework remains useful but should be refined to exclude delays outside utility control and to better distinguish utility-controlled delays from customer or permitting delays.
• Mainspring Energy asks the Commission to add a specific metric for Pre-Parallel Inspection timelines and to set firm turnaround times for the PPI process.
• VGIC asks for more granular timeline reporting so bidirectional charging systems can be tracked separately from general battery storage and other technologies.

Non-NEM / non-export fees and cost responsibility

• Tesla says the $800 non-NEM application fee is outdated and should be reduced for residential-scale non-NEM/NBT projects to align with NEM/NBT fees.
• SEIA says the current flat fee is not cost-justified for modern DERs and should be recalibrated using more detailed cost data by project size and technology.
• VGIC says the $800 fee is especially burdensome for small bidirectional charging systems and recommends an interim fee equal to the small-NEM fee while cost data are gathered.
• CalCCA supports revisiting non-NEM interconnection fees as part of the broader Phase 1 proceeding.
• PG&E supports reevaluating the fee structure through a workshop process so fees better reflect actual processing costs and project complexity.
• SEIA and Tesla both argue that residential-scale non-NEM projects should face less burdensome insurance and administrative requirements than they do today.

Portal, process, and inspection reforms

• Tesla calls for real-time milestone visibility in utility portals, auto-populated data fields, advance notice of portal changes, and clearer terminology for non-export and export-capable applications.
• SEIA similarly asks for better portal tracking, auto-population of utility-held information, and advance notice of portal changes.
• Advanced Energy United asks the Commission to clarify when Pre-Parallel Inspections are required and to set defined timelines for that process.
• Mainspring Energy says PPI and witness-testing requirements should have published deadlines and should be streamlined, including through a professional-engineer documentation pathway where appropriate.
• IREC supports adding standardized reporting templates and tracking additional process steps, including DGSP timelines and pre-application reports.

Special treatment for emerging DER and vehicle-grid integration use cases

• VGIC asks for separate timeline reporting fields for DC and AC bidirectional charging systems, including systems paired with solar or storage, and wants clarity that NEM-MT projects are included in reporting where applicable.
• Tesla argues residential-scale non-NEM/NBT projects such as V2G, standalone storage, and non-exporting solar-plus-storage should be treated more like NEM/NBT projects because their grid impacts are similar.
• Advanced Energy United supports a notification-only pathway or otherwise clarified timelines for non-export and other non-grid-parallel configurations.
• CESA says the Commission should develop a future Phase 2 around front-of-meter DER interconnection pathways, including dispatchable local export projects.

platforms should play. Several parties also raised new emphasis this week on the need for a distinct behind-the-meter execution layer, statewide minimum functional specifications, and whether the Commission should allow IOU applications at this stage or wait until more foundational issues are resolved.

This is a sampling of the parties’ positions.

Procedural path: framework first, applications later, or move ahead now

• Cal Advocates/M.Miley/CPUC says it is premature to require IOU applications now and urges the Commission to first develop a statewide DER Orchestration Framework, including metrics, evaluation standards, and oversight through a Track 2 working group.
• Advanced Energy United says separate IOU applications should not be required yet and recommends using Track 2 to define core framework elements before any utility-specific filing.
• Environmental Defense Fund says the Commission should establish an IOU-wide framework before accepting applications, with a phased approach that reflects differences in IOU readiness.
• San Diego Gas & Electric Company says the Commission should adopt a standalone framework first, then allow optional utility program applications that are evaluated against that framework.
• Pacific Gas and Electric Company says the Commission should proceed with a framework-first, operationally grounded approach that preserves IOU responsibilities and allows phased implementation.
• Southern California Edison Company says the DSO-conflict issue raised by CalCCA is outside the current scope and should not block continued progress on Track 2 implementation issues.
• Clean Coalition says the record is still not developed enough to solicit only IOU proposals and supports continued record-building rather than immediate IOU-only application filings.
• Weave Grid, Inc. says the existing record is sufficient to move to utility-specific applications and phased implementation proposals.

Framework design, governance, and statewide consistency

• Advanced Energy United says the Commission should define a statewide DER orchestration framework before IOUs file applications, to avoid incompatible utility-by-utility systems.
• Cal Advocates/M.Miley/CPUC says a common statewide framework is preferable to IOU-specific frameworks because it supports comparability, oversight, and ratepayer protection.
• San Diego Gas & Electric Company says the framework should be a durable, Commission-approved document developed on its own record, separate from later program filings.
• Clean Coalition says the Commission should continue developing a universal solution across the IOUs rather than defaulting to IOU-specific models.
• Weave Grid, Inc. says the framework should center affordability and reliability, capture localized distribution value, and support a phased implementation process.
• EnergyHub says the framework should support incremental, phased implementation and favor centralized orchestration using edge DERMS capabilities.
• Pacific Gas and Electric Company says the framework must include objectives, operational requirements, valuation principles, and accountability standards before incentive mechanisms are considered.

Protocol neutrality, interoperability, and communications standards

• Universal Devices says the Commission should require protocol neutrality at the DSO interface and explicitly support both OpenADR and IEEE 2030.5, rather than mandating a single protocol.
• Utility Consumers’ Action Network says OpenADR and other open standards should remain available alongside IEEE 2030.5, and the Commission should resolve protocol neutrality before authorizing IOU applications.
• Environmental Defense Fund says IEEE 2030.5 is a valid pathway but should not be the only pathway, and the Commission should avoid proprietary lock-in.
• Advanced Energy United says the framework should be open and interoperable statewide so the system does not become balkanized across IOUs.
• Clean Coalition says the Commission should allow stakeholders to compare common components across proposals rather than selecting a single communications model by default.
• Weave Grid, Inc. says IEEE 2030.5 is useful for utility-facing DERMS integration, but providers should retain flexibility for downstream secure integrations with devices and platforms.
• EnergyHub says interoperability is a long-term goal, but it should not be treated as the immediate gating issue for deployment.
• Pacific Gas and Electric Company says standardized protocols such as IEEE 2030.5 should be part of utility application design.
• Southern California Edison Company says IEEE 2030.5/CSIP is an important scaling tool, with further interoperability discussion potentially handled later.

Behind-the-meter execution, device access, and participation pathways

• Universal Devices says the record is missing a distinct behind-the-meter execution layer that translates fleet-level dispatch into device-level commands across heterogeneous residential assets, and it proposes NuCore as a reference implementation.
• Universal Devices says aggregators remain important, but they need a BTM execution layer to reach a broader set of residential devices across protocols and platforms.
• Utility Consumers’ Action Network says aggregators should be co-equal participants, not subordinate to utility-controlled systems, and that device-level protocol requirements should not be imposed if performance standards can be met another way.
• EnergyHub says utilities should be able to use Edge DERMS and competitive solicitations to select provider models that can manage device-level flexibility at scale.
• Weave Grid, Inc. says centralized orchestration should still allow flexible downstream integrations that securely connect vehicles, chargers, batteries, and other DERs.
• Pacific Gas and Electric Company says third-party participation is important, but it must operate within a DSO-led framework with clear accountability and operational requirements.
• San Diego Gas & Electric Company says open access should be preserved, but third parties must meet defined performance and data-sharing requirements so the DSO retains situational awareness.

Cost-effectiveness, valuation, and avoided-cost analysis

• Advanced Energy United says cost-effectiveness methodology should be settled before IOU applications and should account for interactions and system-wide value streams.
• Environmental Defense Fund says benefit-cost analysis should use granular inputs for timing, location, and duration, but assess net cost-effectiveness at a program level.
• Clean Coalition says evaluation should better recognize avoided costs and value stacking, including multiple grid services from the same DERs.
• Weave Grid, Inc. says BCA methods should explicitly capture asset-level distribution deferral value, including localized secondary and transformer-level impacts.
• Utility Consumers’ Action Network says the Commission should require a Mandatory Alternatives Analysis before funding utility-owned IT or communications investments.
• Small Business Utility Advocates says temporal and locational costs are essential, supports rigorous cost-benefit evaluation, and favors phased deployment of use cases to limit ratepayer risk.
• San Diego Gas & Electric Company says valuation should be tied to identified distribution needs and known upgrade deferrals, rather than broad payments for undefined future pressure.
• Pacific Gas and Electric Company says orchestration costs must be compared against alternatives and evaluated against affordability and downward rate pressure.

Cost recovery, ownership, and incentive mechanisms

• Cal Advocates/M.Miley/CPUC says additional cost recovery should not be approved until measurable ratepayer value is demonstrated from existing investments, and it opposes separate sandbox or pilot cost-recovery paths.
• Small Business Utility Advocates says cost recovery should be resolved in the GRC and warns against duplicative recovery of grid modernization costs.
• San Diego Gas & Electric Company says Commission-directed orchestration work needs a dedicated funding mechanism if existing funding is insufficient.
• Pacific Gas and Electric Company says a shared savings mechanism should only be considered after the framework’s core elements are defined.
• Utility Consumers’ Action Network says a shared-loss mechanism is preferable to a conventional shared savings model because IOUs should bear downside risk if projected benefits do not materialize.
• Small Business Utility Advocates says shared savings mechanisms should be limited to cases where utilities take on meaningful cost risk.
• San Diego Gas & Electric Company says compensation should be narrowly tied to actual distribution deferral or avoidance of identified upgrades, not broad payments for speculative need.
• Pacific Gas and Electric Company says technology investment costs are better addressed in GRC filings than through broad separate recovery mechanisms.

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

• Weave Grid, Inc. says localized distribution constraints should be a priority, and that targeted orchestration can create significant value at the transformer and feeder level.
• Utility Consumers’ Action Network says EIS Part 2 can help identify the highest-value initial deployment locations, especially where electrification growth and limited capacity overlap.
• Environmental Defense Fund says EIS Part 2 may help identify candidate pilot areas, but the Commission should still consider broader deployment characteristics and constraint types.
• Clean Coalition says DSOs should be used to serve new or growing loads locally and avoid unnecessary transmission demand or premature upgrades.
• San Diego Gas & Electric Company says pilots remain necessary before broad rollout and that they reveal operational issues that modeling alone cannot.
• Pacific Gas and Electric Company says sandboxing, pilots, and phased scale-up are appropriate once readiness is demonstrated.
• Southern California Edison Company says implementation should remain phased and utility-specific, with alternatives such as advice letters used for some implementation items after the framework is established.
• Cal Advocates/M.Miley/CPUC says EIS Part 2 is too limited to drive pilot siting on its own and should not substitute for a broader framework process.

Data exchange, CAISO/TSO-DSO coordination, and workshop cadence

• Utility Consumers’ Action Network says the Commission should resolve who controls multi-directional data exchange and should ensure any central platform is operated by a neutral third party rather than by an IOU or CAISO.
• Environmental Defense Fund says the TSO-DSO workshop should define the minimum viable data set CAISO needs and how IOUs can provide it.
• Pacific Gas and Electric Company says the TSO-DSO workshop should focus on specific data gaps and operating roles, and it supports joint work with CAISO on data sharing.
• San Diego Gas & Electric Company says wholesale participation should be optional, while coordination should support forecasting and reliability.
• Cal Advocates/M.Miley/CPUC says ICA workshops should continue quarterly and opposes reducing their frequency.
• Pacific Gas and 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 supports more detailed grid modernization reporting, including appendix-style fields and deployment-status information.
• Pacific Gas and Electric Company and Southern California Edison Company prefer cost information to be handled in GRC filings rather than in the grid modernization report.

Aggregators, customer choice, and market access

• Advanced Energy United says the framework should preserve open access, competition, and statewide consistency for aggregators and third parties.
• Utility Consumers’ Action Network says aggregators should be treated as co-equal market participants and should not be forced into utility-defined device protocols when open standards are available.
• California Community Choice Association says the framework should support customer-owned, CCA-managed, and third-party-managed DERs, not assume an IOU monopoly on orchestration.
• Clean Coalition says the Commission should allow stakeholder proposals alongside IOU proposals so the market is not constrained to utility-preferred models.
• EnergyHub says aggregators matter, but other provider types, including OEMs, TPOs, and Edge DERMS platforms, can also play important roles.
• Pacific Gas and Electric Company and San Diego Gas & Electric Company both say third-party participation is valuable, but it must operate inside clear utility-led operational rules.

Guiding principles and customer or ratepayer protections

• Small Business Utility Advocates says minimizing total system costs should be a primary objective, and it supports adding a guiding principle for fostering third-party competition and market access.
• Small Business Utility Advocates says equity should be clarified to cover both access to orchestration and access to its benefits.
• Environmental Defense Fund supports affordability, reliability, and sustainability as core objectives and emphasizes open access and interoperability.
• California Community Choice Association says the framework should include nondiscriminatory access, competitive neutrality, and timely access to data.
• Utility Consumers’ Action Network says protocol neutrality and scalability should be explicit guiding principles, along with ratepayer affordability.
• Pacific Gas and Electric Company says the guiding principles should be precisely defined and implemented in phases to avoid double compensation or double counting.
• San Diego Gas & Electric Company says safe and reliable grid operation should be treated as a foundational principle.