November 4, 2026

Regulatory Update for November 4, 2026

(Covering October 28, 2026 - November 3, 2026)

Our energy regulatory team has compiled a list of state and federal energy regulatory developments to keep you up to speed on key energy regulatory matters from across the United States. Stoel’s energy regulatory team is always available to answer questions about any of these developments. Click here to meet the energy regulatory team.

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State Regulatory Agencies

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State Regulatory Agencies

CALIFORNIA PUBLIC UTILITIES COMMISSION (CPUC or COMMISSION)[1]

Proposed Decisions and Resolutions

Application (A.) 22-05-015 (Application of Southern California Gas Company for Authority, Among Other Things, to Update its Gas Revenue Requirement and Base Rates Effective on January 1, 2025)

This decision denies the December 17, 2025 petition to modify Decision (D.) 24-12-074, Decision Addressing the 2024 Test Year General Rate Cases of Southern California Gas Company and San Diego Gas & Electric Company, filed by San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas) (collectively, the Sempra Companies).  The Sempra Companies’ requested modification of D.24-12-074 to change the one-part post-test year mechanism adopted therein on the grounds that the Sempra Companies are being deprived of the ability to recover capital-related costs authorized in the decision.  The decision denies Sempra Companies’ request on the ground that the petition does not present new or changed facts and attempts to re-litigate issues decided by the Commission in D.24-12-074.

Rulemaking (R.) 19-01-011 (Order Instituting Rulemaking Regarding Building Decarbonization)

This decision modifies D.23-12-037 to address issues related to electric line extension subsidies for mixed-fuel new construction projects located on Tribal lands.  This decision establishes an exemption from the elimination of subsidies for electric line extensions in mixed-fuel new construction on Tribal lands where the Tribe certifies that such structures serve residents residing on Tribal lands.  This exemption also applies to structures that support essential Tribal governmental, public safety, emergency management, health, elder, education, cultural, housing, water, wastewater, or other community-facing functions located on Tribal lands. 

Resolution G-3624

This resolution approves in part and modifies in part SoCalGas’s Advice Letters (AL) 6495-G-A, 6496-G-A, 6645-G, and 6646-G with proposed Gas Research, Development, and Demonstration (RD&D) Investment Plans (Gas RD&D Plans or Plans) for 2024, 2025, 2026, and 2027, respectively.  SoCalGas’s Gas RD&D Program was established pursuant to the general rate case (GRC) D.19-09-051 as upheld in D.24-12-074, requiring SoCalGas to submit, and the Commission to approve, an annual Tier 3 AL describing SoCalGas’s proposed Gas RD&D Investment Plan prior to utilizing authorized funds.  Based on Commission review of requirements, the Commission approves in part and modifies in part SoCalGas’s Gas RD&D Plans with proposed budgets of $17,853,000 for 2024; $18,389,000 for 2025; $18,940,000 for 2026; and $19,508,100 for 2027, totaling $74,690,100. These budgets include proposed administrative budgets of 10% for total administrative costs, amounting to $1,785,300 for 2024; $1,838,900 for 2025; $1,894,000 for 2026; and $1,950,800 for 2027.  The Commission directs SoCalGas to submit revised Gas RD&D Investment Plans via Tier 2 ALs within 60 days with modifications described in this resolution.  This resolution establishes an Annual Report deadline of March 1 of each year.

A.26-03-031 (Application of Pacific Gas and Electric Company to Recover in Customer Rates the Costs to Support Extended Operation of Diablo Canyon Power Plant from January 1 through December 31, 2027, and for Approval of Planned Expenditure of 2027 Volumetric Performance Fees)

This decision approves Pacific Gas and Electric Company’s (PG&E’) 2027 Diablo Canyon Power Plant extended operations revenue requirement of $933.799 million.  The revenue requirement is allocated to PG&E, Southern California Edison Company (SCE), and SDG&E using the allocation factors 45.22%, 45.22%, and 9.56%, respectively.

A.22-05-001 (Application of Southern California Gas Company for Approval of the Branch Offices Closure Proposal)

This decision identifies branch offices SoCalGas must continue to operate and defines how ratepayer-funded customer services shall be provided throughout the utility’s service area where branch offices are authorized to close.  It also directs SoCalGas to track and report any ratepayer savings related to the branch office closures authorized in this decision.  The decision authorizes SoCalGas to close 22 of its existing branch offices.  These offices have lower transaction volumes and authorized payment location coverage nearby.  The decision further directs SoCalGas to retain existing operations at 20 branch offices.  These include the eight branch offices the utility identifies as serving a high concentration of customers enrolled in the California Alternative Rates for Energy Program, and the 12 branch offices that reflect the highest volume of transactions, based on data the utility provided.

Voting Meeting

The CPUC held a voting meeting on October 29, 2026 in San Francisco, California, at 11:00 a.m. PT.  The energy-related results are below:

Item 2. Resolution E-5455

This resolution approves, with modifications, PG&E AL 7785-E, filed on December 18, 2025, requesting Commission approval of an exceptional case agreement between PG&E and Google LLC (Google) to support the energization of a new 250-megawatt (MW) transmission-level retail electric load at 230 kilovolts (kV) in San Jose, California.  The Commission approves the AL with modifications, requiring additional ratepayer protections.  Specifically, the Commission requires (1) an additional capital advance from the customer of $600,000 per MW to better reflect the costs of energization, including broader transmission network upgrades, and (2) modifications to the proposed refund methodology to limit annual refunds to 100% of annual net revenues received from the customer.  PG&E may modify the advance requirement to match the outcome in the Rule 30 Proceeding, A.24-11-007, if warranted.  The standard Base Annual Revenue Calculation (BARC) refund approach used under Electric Rule 15 may result in rapid refunds for large transmission-level customers well before sufficient net revenues have been received to offset the costs and associated risks of energizing large loads.  According to the resolution, because the applicant-proposed process does not adequately account for the energization costs associated with broader transmission network upgrades, the Commission finds that an additional capital advance and an annual 100% net revenue refund limit are reasonable and necessary to protect ratepayers while still allowing the customer to receive a full refund over time.  The resolution also addresses a proposed binding cost cap for the applicant-build portion of the project.  The Commission clarifies that the binding cost estimate should apply to refundable costs (Standard Facilities) separately from non-refundable costs (Special Facilities), and that the binding cost cap for refundable costs should not include costs overlapping with the costs of PG&E’s own work on the project.  The Commission further requires PG&E to submit an information-only Tier 1 AL when the binding cost estimate is finalized, with attachments describing the binding estimate and how it was calculated.  Held to November 19.

Item 4. A.24-01-020, et al.  (In the Matter of the Application of SFPP, L.P. for Authority to Increase Rates for Transportation of Refined Petroleum Products)

In its consolidated applications, SFPP, L.P. (SFPP) seeks to increase its existing rates and charges for intrastate transportation of refined petroleum products for the period covering 2021–2024.  This decision finds that SFPP’s connected terminals are pipeline system jurisdictional assets per Public Utilities Code section 227.  Because SFPP’s rate increase applications and evidence do not include the revenue and cost information associated with these jurisdictional terminal assets, this decision finds that SFPP’s applications do not comply with all applicable sections of the Public Utilities Code.  Held to November 19.

Item 6. Resolution G-3622

This resolution approves in part and modifies in part the California Energy Commission’s (CEC) ALs 12-G and 10-G-A, filed on August 8, 2025 and October 3, 2025, respectively.  These ALs contain proposed Gas RD&D Plans for Fiscal Years 2024–2025 (the 2024 Plan) and 2025–2026 (the 2025 Plan).  This resolution approves in part the CEC’s Gas RD&D Plans with proposed budgets of $24 million each for its 2024 Plan and its 2025 Plan, totaling $48 million.  This resolution reviews the CEC’s 2024 Plan and 2025 Plan against a list of consolidated requirements from prior decisions and resolutions.  This resolution finds that CEC Plan omissions can be remedied with additional information and directs the CEC to submit its revised 2024 and 2025 Gas RD&D Plans via Tier 2 ALs within 90 days.  Held to November 19.

Item 7. A.25-04-020 (Application of Southern California Gas Company to Recover Costs Recorded in the Transmission Integrity Management Program Balancing Account from January 1, 2019 to December 31, 2023)

This decision grants ’SoCalGas’s request for cost recovery in the amount of $81.3048 million as part of its Transmission Integrity Management Program Balancing Account.  The Commission disallows $92.4952 million from the original requested amount. 

Rev. 1: On October 27, the Commission issued Revision (Rev.) 1 to the Proposed Decision (PD) which materially revises the cost recovery.  The revised decision denies $20,152,686 in capital costs and $42,603,474 in Operations & Maintenance (O&M) costs.  The reductions reflect a disallowance in both capital and O&M for incremental straight-time labor costs and associated vacation and sick leave costs (approximately $37 million), incremental Vendor #11900 costs (approximately $0.693 million), and a $24,464,160 disallowance for the 8% of projects SoCalGas did not support with workpapers.  Within 30 days of the adoption of this decision, SoCalGas is directed to file a Tier 2 AL to calculate the final revenue requirement in light of the reductions to capital and O&M described above and may include a proposed alternative breakdown of the $24,464,160 disallowance between capital and O&M by providing an allocation that is based on the information in this proceeding.  This decision directs SoCalGas to utilize the cost allocation mechanism adopted by the Commission in D.24-07-009, until such time as a new cost allocation mechanism is adopted.  Furthermore, SoCalGas is directed to amortize the amounts authorized for recovery in this decision over a 12-month amortization period.  Signed, D.26-10-049.

Item 8. R.25-08-013 (Order Instituting Rulemaking to Establish Policies, Processes, and Rules Regarding Autonomous Vehicle Passenger Transportation Service)

This decision resolves the Track One issues that have been categorized as Autonomous Vehicle Program Requirements and Administration.  In a subsequent decision, the Commission will resolve the remaining Track One issue that deals with the requirements for the Autonomous Vehicle transport of unaccompanied minors.  Held to November 19.

Item 10. Resolution E-5474

This resolution approves updates to the Database for Energy-Efficient Resources (DEER) for program year (PY) 2028 and a revised version of DEER for PY2026 and PY2027, in compliance with D.15-10-028 and D.21-05-031, and Resolutions E-4818, E-5152, E-5221, and E-5350.  This update also directs forward-looking research and addresses significant transitions for the DEER and measure package system maintenance and operation.  All updated DEER assumptions, methods, values, and supporting documentation are available on the DEER Module on the California Energy Data and Reporting System.  Held to November 19.

Item 15. A.25-07-001 (Application of Southern California Gas Company on Behalf of its Customers, for Approval of Gas Line Extension Allowances)

This decision grants in part and denies in part the application of SoCalGas, on behalf of its customers, for approval of gas line extension allowances.  This decision also approves SoCalGas’s request to revise Tariff Rule Nos. 20 and 21, SoCalGas’s update to the non-residential gas line extension allowance multiplier of 3.1, and SoCalGas’s request to establish a two-way balancing account to track costs associated with approved gas line extension allowances.  Finally, this decision approves the calculation of SoCalGas’s forecasted revenue requirement but directs SoCalGas to update its revenue requirement calculations to account for the fact that only four of the original nine projects are approved by this decision.  Signed, D.26-10-050.

Item 19. A.22-05-015/16 (Application of Southern California Gas Company/San Diego Gas & Electric Company for Authority, Among Other Things, to Update its Gas Revenue Requirement and Base Rates Effective on January 1, 2025)

This decision denies the November 25, 2025 petition to modify D.24-12-074, Decision Addressing the 2024 Test Year General Rate Cases of Southern California Gas Company and San Diego Gas & Electric Company (the Decision), filed by the Natural Resources Defense Council, CALSTART, Inc., Powering America’s Commercial Transportation, Advanced Energy United, Tesla, Inc., Walmart Inc., the City of San Diego, Electrify America, LLC, EVgo Services, LLC, and the Electric Vehicle Charging Association (Joint Petitioners).  Joint Petitioners request modification of the Decision to remove the funding cap for the Electric Rule 45 Electric Vehicle Infrastructure Memorandum Account and ensure that Rule 45 remains open to all eligible applications through at least the current rate case cycle, as required by Public Utilities Code section 740.19.  Joint Petitioners’ request is denied because the Commission does not find that Joint Petitioners presented any new or changed facts within the meaning of Rule 16.4(b).  This decision also finds that the Joint Petitioners used the petition for modification improperly to allege legal errors outside the 30-day window for an application for rehearing.  Signed, D.26-10-051.

Item 20. Resolution E-5484

This resolution approves PG&E’s request in AL 7936-E to enter into a Special Facilities Agreement (“Agreement)” to provide redundant distribution-level electric service to the ’customer’s existing facilities in Cupertino, California.  This Agreement makes certain exceptions to Electric Rule 2 to allow PG&E to design and install the Special Facilities and to make upgrades at Stelling Substation and additional distribution upgrades on an actual cost basis.  Due to the project’s substantial scope, the Agreement will protect existing ratepayers by ensuring that costs associated with the project reflect the actual work performed, as it may be challenging to accurately estimate costs for this scope of work.  Additionally, the customer is not entitled to refunds for the Special Facilities that have been requested and will pay monthly cost-of-ownership charges for Special Facilities or an agreed-upon Equivalent One-Time Payment.  PG&E requests approval under General Order 96-B, Energy Industry Rule 5.3.  Approved.

Item 21. A.26-05-002 (Application of Southern California Gas Company (U904G) and San Diego Gas & Electric Company for Authorization to Implement Revenue Requirement to Enable SAP Migration Program)

This decision authorizes SoCalGas and SDG&E (the Sempra Utilities) to establish the Systems Applications Products (SAP) Migration Memorandum Account, effective May 1, 2026, to track costs stemming from implementation of the SAP Migration Program Phase 1B, up to a cap of $13.7 million.  This decision does not authorize the Sempra Utilities to recover costs recorded in the SAP Migration Memorandum Account.  Whether, how, and to what extent the Sempra Utilities may recover costs tracked in this memorandum account will be determined in a future Commission decision.  Signed, D.26-10-052.

Item 22. A.25-09-004 (Order Instituting Rulemaking to Enhance Demand Response in California)

This decision authorizes bridge funding for the 2028–2029 demand response (DR) programs operated by PG&E, SDG&E, and SCE (collectively, the Investor-Owned Utilities (IOUs)), to ensure program continuity while the Commission considers DR reforms in this rulemaking.  In addition, the decision modifies the November 1, 2026 filing deadline for the next IOU DR applications to November 1, 2028, to align the applications with the policy updates expected in this rulemaking.  The next applications will cover program years 2030–2034.  For the Emergency Load Reduction Program pilot, the decision limits pilot sub-groups and reduces the minimum dispatch hours to ensure the pilot’s availability through the bridge-year period, retain continuity for participants, and increase value for ratepayers.  Also, the decision exempts the 2028–2029 DR bridge portfolios from the Societal Cost Test requirement while directing the IOUs to implement Societal Cost Test capability in their DR Cost-Effectiveness Reporting Tools by April 1, 2028, in time for the 2030–2034 program cycle.  Signed, D.26-10-053.

Item 23. R.21-06-017 (Order Instituting Rulemaking to Modernize the Electric Grid for a High Distributed Energy Resources Future)

This decision orders the IOUs to retain a consultant to lead a series of working group meetings to vet proposals for a common Distributed Energy Resources (DER) orchestration framework and prepare a report with recommendations based on the stakeholder feedback from the workshops.  The report will be included as an attachment to the Joint IOU Application to be filed within 12 months of the issuance of this decision.  The Joint Application will include a proposal for a common DER orchestration framework using the report as support for such a proposal, and proposals from each of the IOUs as to how each one will utilize the common DER orchestration framework given its current circumstances.  Signed, D.26-10-054.

Item 24. R.18-04-019 (Order Instituting Rulemaking to Consider Strategies and Guidance for Climate Change Adaptation)

This decision declines to adopt modifications to existing General Orders or adopt a new General Order to address climate adaptation.  Rather, the decision adopts the framework proposed by the Safety Policy Division, with modifications.  Upon issuance of this decision, this framework will apply to new applications filed by any IOU that is required to file both climate adaptation Vulnerability Assessments and Risk Assessment Mitigation Phase applications.  This currently includes PG&E, SCE, SoCalGas, and SDG&E.  As such, all future applications filed by PG&E, SCE, SoCalGas, and SDG&E will be screened through questions related to the five policy areas of Repetitive Loss and Failure, Site Selection, Design and Engineering, Equipment Tolerance, and Climate Risk Modeling to determine if the climate adaptation considerations apply to them.  The outcome of this screening will be an annual joint IOU workshop, starting in 2028, to summarize the integration of climate adaptation across the five policy areas into applications filed with the Commission.  PG&E, SCE, SoCalGas, and SDG&E are additionally required to file a joint annual report by May 1 of each year with specific information to aid tracking and monitoring of climate adaptation activities, aiding the Commission, its staff, and intervenors in evaluating the efficacy of climate adaptation policy to inform IOU filings.  Signed, D.26-10-055.

Item 25. Resolution O-0102

This resolution approves Zenith Energy West Coast Terminals LLC’s (Zenith Terminals) request for authorization to discontinue service at the Alamitos Terminal in accordance with the provisions of General Order 96-B, Energy Industry Rule 5.3.6.  This resolution also grants Zenith Terminals authority to file a Tier 1 AL following discontinuance of service at the Alamitos Terminal to remove references to the Alamitos Terminal from its tariff.  Approved.

Item 47. A.25-06-017 (Application of Liberty Utilities (CalPeco Electric) LLC (Liberty) for Authority to Recover Costs Related to the 2020 Mountain View Fire Recorded in the Wildfire Memorandum Account)

This decision authorizes Liberty to recover approximately $58.05 million in costs related to the 2020 Mountain View Fire recorded in Liberty’s Wildfire Expense Memorandum Account, plus up to an additional $3.375 million in financing costs related to the five-year recovery period, along with 75% of the five unresolved claims.  Liberty shall use a Tier 2 AL process for approval of the Wildfire Expense Memorandum Account costs related to the unresolved Mountain View Fire claims paid after January 23, 2026.  A five-year amortization period will be used by Liberty to recover the authorized Wildfire Expense Memorandum Account costs through a volumetric surcharge on customer bills.  Held to November 19.

Item 48. R.22-12-011 (Order Instituting Rulemaking to Address Biomethane Procurement Cost Allocation)

This decision finds that all investor-owned gas utility customers should pay a share of the above-market costs of the Renewable Gas Standard (RGS) program.  However, the allocation of costs is not extended to non-core customers at this time, pending further assessment of whether an exemption (either in whole or in part) should apply to non-core customers.  An additional process on this matter is needed to identify whether and how to implement cost allocation in a way that avoids emissions leakage and encourages industry to stay in California.  This decision orders the joint gas utilities to lead a workshop process and subsequently file an application that considers recommendations coming out of the workshop as to whether and how these issues should be addressed.  Held to November 19.

Item 48A. R.22-12-011 (Order Instituting Rulemaking to Address Biomethane Procurement Cost Allocation)

This Alternate Proposed Decision (APD) finds that all investor-owned gas utility customers should pay a share of the above-market costs of the RGS program and allocates costs to both core and non-core customers.  The APD similarly directs the utilities to lead a workshop process and subsequently file an application.  Held to November 19.

Item 49. A.25-05-009 (Application of Pacific Gas and Electric Company for Authority, Among Other Things, to Increase Rates and Charges for Electric and Gas Service Effective on January 1, 2027)

The decision authorizes PG&E to recover, on an interim rate basis, no more than $456 million in revenue requirement, beginning January 1, 2027, to remain in effect until implementation of a final decision.  Held to November 19.

Item 50. A.22-05-015 (Application of Southern California Gas Company for Authority, Among Other Things, to Update its Gas Revenue Requirement and Base Rates Effective on January 1, 2024)

This decision evaluates SDG&E’s costs recorded in its wildfire mitigation plan memorandum account for 2023 and SDG&E’s drone program costs from 2019 to 2023.  This decision also addresses SoCalGas’s and SDG&E’s Pipeline Safety Enhancement Plan costs carried over from Track 1 of this proceeding, D.24-12-074.  For Pipeline Safety Enhancement Program (PSEP) work conducted from August 2014 to July 2019, SDG&E requests $239.196 million in capital expenditures and $1.213 million in O&M costs.  The Commission finds $26.159 million of SDG&E’s requested capital expenditures to be unreasonable and therefore approves $213.037 million in capital costs.  The Commission’s disallowances also have the effect of denying SDG&E’s certain requested recovery of O&M costs.  After accounting for the Interim Rate Recovery SDG&E already collected for the PSEP Balancing Account, as well as the disallowances noted above, the Commission authorizes SDG&E to recover the remaining undercollected revenue requirement through 2026 of $17.3 million via its next scheduled rate change.  The 2027 revenue requirement associated with PSEP costs shall be implemented in rates on January 1, 2027, or with the next scheduled rate change for that year, through a Tier 1 AL.  For PSEP work conducted from December 2015 to December 2020, SoCalGas requests $453.861 million in capital expenditures and $45.243 million in O&M costs.  The Commission finds $98.021 million of SoCalGas’s requested capital expenditures to be unreasonable and therefore approves $355.838 million in capital costs.  The Commission also finds $7.883 million of SoCalGas’s requested O&M costs to be unreasonable and therefore approves $37.359 million in O&M costs.  After accounting for the Interim Rate Recovery SoCalGas already collected for the PSEP Balancing Account, as well as the disallowances noted above, the Commission authorizes SoCalGas to recover the remaining undercollected revenue requirement through 2026 of $19.812 million via its next scheduled rate change.  The 2027 revenue requirement associated with PSEP costs shall be implemented in rates on January 1, 2027, or with the next scheduled rate change for that year, through a Tier 1 AL.  To reduce the rate impact and to support rate stability, the Commission authorizes SDG&E and SoCalGas to amortize the balance of the undercollected revenue requirement owed for PSEP costs through 2026 over a period of 12 months.  Held to November 19.

Item 51. A.25-04-006 (Application of Southern California Gas Company for Adoption of a Microgrid Optional Tariff)

The decision denies, without prejudice, SoCalGas’s request for authorization to offer the Microgrid Optional Tariff (MOT), primarily because SoCalGas has failed to meet its burden of demonstrating that the proposed tariff is reasonable and in the public interest.  The purpose of the MOT was to enable the utility to design, build, own, operate, and maintain behind-the-meter and off-grid microgrid facilities within SoCalGas’s service territory.  Because the Commission denies SoCalGas’s request, the decision does not determine the program-design requirements that would apply if the MOT were approved.  Signed, D.26-10-077.

Events

Interconnection Forum for Project Developers

SCE will host the transmission interconnection forum for developers seeking interconnection.  The forum will focus on policy, process, and implementation topics affecting transmission interconnection.  The forum will take place virtually on November 17, 2026.

Interconnection Discussion Forum

Energy Division staff hosted the November Interconnection Discussion Forum (IDF) on Tuesday, November 3, 2026 from 1:00 p.m. to 4:00 p.m. PT.  The IDF provides an informal venue for utilities, developers, and other stakeholders to explore a variety of issues related to interconnection practices and policies.  It is generally scheduled quarterly.  The November IDF meeting focused on interconnection issues relating to community solar, under both the Wholesale Distribution Access Tariff and Electric Rule 21.  Additional details are available on the Rule 21 website, here.

CALIFORNIA ENERGY COMMISSION (CEC)

2026 Integrated Energy Policy Report (IEPR) Update

The CEC has set the following preliminary schedule for the 2026 IEPR.  The schedule is available on the 2026 IEPR Update page.

Task/Event Date
• Final 2026 IEPR Update Scoping Order released April 2026
• Adopt order instituting informational proceeding May 2026
• Public workshops on specific topics May–December 2026
• Release draft 2026 IEPR Update October 2026
• Release proposed 2026 IEPR Update January 2027
• Adopt 2026 IEPR Forecast January 2027
• Adopt 2026 IEPR Update February 2027

The CEC’s 2026 IEPR Update workshop schedule (which remains subject to change) is set forth below.  According to the workshop schedule, all workshops will be held via Zoom and the remaining workshops through December 2026 will run as follows:

November 12, 2026: Commissioner Workshop on Load Modifier Draft Results, 10:00 a.m. – 5:00 p.m. PT.

December 14, 2026: Commissioner Workshop on Overall Forecast Results, 10:00 a.m. – 5:00 p.m. PT.

Written comments for the November 12 Workshop on Load Modifier Draft Results are due to the docket unit by 5:00 p.m. PT on November 30, 2026.

Demand Analysis Working Group (DAWG)

On October 29, 2026, the CEC circulated a “save the date” notice for a November 17, 2026 DAWG meeting to discuss potential enhancements to the California Energy Demand Forecast to reconcile differences with utility distribution planning forecasts.  The meeting will be held via Zoom and will begin at 1:00 p.m. PT.  Additional information, including access instructions, is available here.

Distributed Electricity Backup Assets (DEBA) Grant Funding Opportunity

On October 23, 2026, the CEC announced the availability of up to $46 million in grant funding for a competitive grant solicitation through the DEBA Program.  The intent of this solicitation is to support the deployment of new DERs that can increase supply or reduce (or shift) load to improve the reliability of the state’s electrical grid and help avoid blackouts during extreme events.  CEC staff will host one Pre-Application Workshop, on November 5, 2026 from 1:00 p.m. to 4:00 p.m. PT, to discuss this solicitation with potential applicants.  Event access details are available here.

Webinar on Enabling Bidirectional Electric Vehicle (EV) Charging at Home (V2H)

The CEC will host a webinar on November 10, 2026, from 10:00 a.m. to 2:30 p.m. PT, to present and discuss commercially available and upcoming V2H solutions.  The webinar will feature presentations from several automakers and charging equipment providers.  The goal is to share and discuss the current state of V2H deployments in California and to gather broad stakeholder input as the CEC considers next steps and policies to facilitate access to bidirectional charging benefits for California EV drivers.  Meeting details, including an agenda and presentation slides, will be posted prior to the webinar in Docket 22‑EVI‑06.

Opt-In Certification Program: Emergency Rulemaking

On November 2, 2026, the CEC held a public workshop regarding proposed emergency regulations for the Opt-In Certification Program that will be set forth in Title 20, California Code of Regulations, sections 1875–1882, and Appendix B.  According to the revised workshop notice, the proposed regulatory changes include, among other things:

  • incorporation of the statutory presumption of net economic benefits;
  • incorporation of new statutory requirements for applicants to provide evidence of property rights to the proposed location and consultation with the fire suppression authority; and
  • clarification of the procedures for suspension and early termination of a project application, restructure local agency reimbursement, refine the community benefits agreement process, address post-certification change in project ownership or operational control, and update the Appendix B information requirements applicable to the Opt-In Certification Program.

The CEC also extended the deadline to provide written comments on the proposed emergency regulations.  Comments are now due to the docket unit by 5:00 p.m. PT on November 10, 2026.

Wave and Tidal Energy

The CEC released the Draft Senate Bill 605 Wave and Tidal Energy Report to the Governor and Legislature and held a remote-access workshop on September 30, 2026 to present and gather feedback on the draft report.  The meeting schedule for the workshop is available here.  Written comments on the draft report were due to the docket unit by 5:00 p.m. PT on November 3, 2026.

Gas Reliability Workshop

The CEC will host a staff workshop on November 24, 2026, from 1:00 p.m. to 3:00 p.m. PT, to present California’s natural gas reliability outlook for the winter months of 2026–2027.  A workshop agenda, access details, and related documentation are available here.

Workshop on Senate Bill (SB) 767 Implementation

The CEC hosted a workshop on October 28, 2026, from 2:00 p.m. to 3:00 p.m. PT, to begin implementation of SB 767 (Richardson, 2025), which establishes new reporting requirements for crude oil pipelines that supply California refineries.  SB 767 was enacted in 2025 to help maintain the reliability of California’s crude oil supply by preventing shutdowns of low‑flow crude oil pipelines.  It directs the CEC to work with stakeholders to identify reportable pipelines – pipelines that deliver domestic crude oil to in‑state refineries and whose closure could significantly reduce refinery processing capability.  Beginning March 30, 2027, operators of reportable pipelines must submit monthly operating data, including minimum and maximum operating volumes, daily crude delivery volumes, operating hours, nameplate capacity, and available capacity.

During the workshop, CEC staff presented and received input on draft SB 767 “reportable pipelines” regulations and proposed implementation plan with a focus on the data requirements.  The workshop included a public comment period.  Additional information can be found in Docket No. 26-OIR-02.

Workshop on Refinery Resupply

The CEC will host a workshop on November 9, 2026, from 1:00 p.m. to 3:30 p.m. PT, to discuss resupply rulemaking pursuant to Assembly Bill (AB) X2-1 (Stats. 2024, 2d Ex. Sess. 2023–2024, Ch. 1) and SB X1-2 (Stats. 2023, 1st Ex. Sess. 2023–2024, Ch. 1).

SB X1-2 and AB X2-1 require the CEC to assess transportation fuel prices, supply conditions, and reliability in California.  AB X2-1 further requires the CEC to consider the effects of refiners’ inventories of fuel, feedstock, and blending components on transportation fuel prices, and authorizes the CEC to consider ways to minimize the impacts of maintenance-related production losses on fuel prices while protecting the health and safety of workers, local communities, and the public.

A link to the workshop agenda and access details is available here.

Lithium Valley Informational Proceeding

The CEC will host a hybrid workshop on November 6, 2026, from 10:00 a.m. to 4:00 p.m. PT, to discuss Lithium Valley development as well as the policies and programs that are in place or that will continue to evolve in order to measure and regulate the lithium industry.  The workshop will be available by Zoom or in person at San Diego State University, Imperial Valley, Rodney Auditorium in Calexico, California.  Additional details are available here.  Written comments are due to the docket unit (Docket No. 24-OIIP-02) by 5:00 p.m. PT on November 30, 2026.

CEC Business Meetings

The next CEC business meeting will be held on November 18, 2026.  An agenda and supporting materials should be available here at least 10 days prior to the meeting.

MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC)

At its November 5, 2026 weekly agenda meeting, the MPUC will consider: (1) issuing a pipeline route permit to Magellan Pipeline Co., L.P., for the Pipestone Reroute Project (Docket No. IP7109/PPL-23-109); and (2) granting a route permit and adopting the proposed Findings of Fact and Conclusions, as amended, regarding Xcel Energy and Echo Zone LLC’s North Rochester to Skyway High Voltage Transmission Line Project (Docket No. E002/TL-26-135).

Additionally, at its October 29, 2026 weekly agenda meeting, the MPUC approved Xcel’s Lake Wilson battery energy storage agreement with Invenergy.  The MPUC also approved recovery of the Minnesota-jurisdictional energy costs through the Fuel Clause Rider and recovery of capacity payments through base rates and the capacity tracker.

Also, at its November 2, 2026 external planning meeting on affordability, the MPUC heard presentations and a panel discussion featuring Commission staff and representatives from the Regulatory Assistance Project, the Minnesota Department of Commerce, the Citizens Utility Board of Wisconsin, Allete/Minnesota Power, the Office of the Minnesota Attorney General, and Fresh Energy.  As part of the MPUC’s investigation into electric and natural gas utility service affordability, the workshop addressed how costs are added to customer bills, including potential changes to interim rates, the fuel clause, return on equity, capital structure, riders, and rate design (Docket No. E,G999/CI-26-341).

PACIFIC NORTHWEST (OPUC, WUTC, BPA)

Oregon Public Utility Commission (OPUC)

On October 27, 2026, the OPUC adopted a staff recommendation in Docket No. AR 682 to open a formal, narrowly-scoped rulemaking to amend its Resource Adequacy rules under OAR Chapter 860, Division 95, focused on whether utilities withdrawing from the Western Resource Adequacy Program must still submit forward showings to Oregon’s State Program and on the State Program’s non-compliance penalty. See the OPUC Order and attached Staff Recommendation here.

On October 29, 2026, the OPUC held a Special Public Meeting to review a Final Draft Executive Order Work Plan in Docket No. UM 2417, which sets goals, strategic priorities, and metrics for the agency’s implementation of Executive Orders 25-25 and 25-29 on clean energy development, with staff set to finalize the plan for Commission approval and submission to the Governor at the December 8, 2026 Public Meeting.  More information including Staff Memo and Slide Presentation available here.

Washington Utilities and Transportation Commission (WUTC)

On October 29, 2026, Kitsap County voters decided on Proposition 1, which would authorize Kitsap Public Utility District to study taking over electric service from Puget Sound Energy for roughly 130,000 customers.  Also on October 29, 2026, at an open meeting, the WUTC considered Avista Corporation’s Climate Commitment Act tariff revision, Docket No. UG-260728, decreasing company revenues by $32.0 million, or 11%, with residential customers seeing an average bill decrease of 10.1% and Puget Sound Energy’s Annual Purchased Gas Adjustment filing, Docket No. UG-260780, which increases annual revenue by approximately $47.2 million, or 3.59%, with a residential customer bill impact of about $3.69 per month.  Agenda available here.

Bonneville Power Administration (BPA)

On October 21, 2026, the Ninth Circuit Court of Appeals rejected a challenge to BPA’s Markets+ participation, opening a path for BPA to instead join CAISO’s Extended Day-Ahead Market. On October 30, 2026, BPA held a Day-Ahead Market Participation Workshop and announced it expects to issue a draft decision on its day-ahead market choice in early December 2026, with a final record of decision targeted for February 2027.  More information is available here.

On October 29, 2026, BPA convened TC-27 settlement participants to announce it would not move forward with proposing adoption of the settlement agreement and would not initiate the TC-27 tariff proceeding.  More information about the TC-27 settlement and objections available here.  BPA is considering whether proposals from the now-inactive TC-27 pre-proceeding discussions will be incorporated into the upcoming TC-27R proceeding and will provide an update at the November 18 Grid Access Transformation (GAT) Workshop.  Information about the upcoming GAT Workshop available here.

Federal Agencies

FEDERAL ENERGY REGULATORY COMMISSION (FERC)

FERC Approves Midcontinent Independent System Operator, Inc. (MISO) Demand Response Changes

FERC approved MISO’s proposed tariff revisions, effective June 1, 2027, reforming MISO’s penalty provisions for Load Modifying Resources (LMRs), including Demand Response Resources, that fail to meet their performance obligations beginning with the 2027/2028 Planning Year.

Under the revised framework, MISO may use a real-time penalty and an Auction Clearing Price (ACP) penalty tied to the resource’s degree of underperformance and capacity-market compensation.  FERC concluded that the penalty framework is not overly punitive, as it is intended to incentivize performance during emergencies and replace capacity that MISO otherwise expects to be available.  FERC nevertheless required MISO to clarify through a compliance filing how the ACP penalty applies when an LMR reports itself unavailable and therefore does not receive a Scheduling Instruction.

The order also tightens the consequences of nonperformance for continued participation in MISO’s capacity market.  An LMR experiencing a complete performance failure will generally be disqualified for the remainder of the Planning Year unless it has fully performed in response to at least one Scheduling Instruction during the same Season.  Two complete failures in a Season will result in exclusion from the following Planning Year’s auction, and an LMR disqualified twice within three years will be barred from the auction for three additional Planning Years.  MISO will also retain discretion to prohibit an LMR with a single complete performance failure from participating in the following Planning Year.

FERC Warns of Fraud Scams

FERC issued a warner that scammers are impersonating FERC government officials, noting that “external filers have reported receiving phishing emails that falsely claim to be from FERC, including a fraudulent purported update to payment instructions.” FERC stated that FERC communications will be sent from .gov email addresses and official payment information is available on FERC’s website here.

U.S. DEPARTMENT OF ENERGY (DOE)

Notice of Funding Opportunity (NOFO) for Domestic Grid Components

DOE published a NOFO for the manufacture of distribution and power transformers, their associated components and materials, and other essential electric grid equipment.  DOE stated that the NOFO seeks to promote refurbishment and reuse of transformers and other grid components and to fast-track the identification, qualification, and integration of domestically sourced, alternative materials and subcomponents used by U.S. grid equipment manufacturers.

Independent System Operators (ISO) and Regional Transmission Organizations (RTO)

CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO)

Stakeholder Initiatives: Upcoming Meetings and Deadlines

2028 Local Capacity Requirements: Technical Study Criteria, Methodology, and Assumptions Meeting

The CAISO will hold a public stakeholder meeting on November 2, 2026, to discuss the criteria, methodology, and assumptions to be used in the 2028 Local Capacity Technical Study.  The draft study manual, meeting materials, and meeting details are available here.

Extended Day-Ahead Market (EDAM) Congestion Revenue Allocation Phase 2

The CAISO will hold an upcoming hybrid, full-day, EDAM congestion revenue allocation working group meeting on November 9, 2026.  The meeting details can be found here.  This meeting will be a continuation of prior working group meetings discussing design concept #3, which introduces a common simultaneous feasibility test that informs the congestion revenue entitlements incorporating congestion revenue rights in the CAISO balancing area and reserved transmission rights in the EDAM balancing area.

Reported Cost Savings in Real-Time and Day-Ahead Markets

The CAISO’s latest Markets and Quarterly Benefits Report was released on October 29, showing increased cost savings for participants in both electricity markets.  According to the ISO, the report shows cost savings of $11.238 for the EDAM, for its first two months of operation, with total reported benefits of $32.77 million since May.  For the Western Energy Imbalance Market cost savings for participants and their customers amount to nearly $10 billion, with cumulative totals savings since 2014 of $9.6 billion.

Resource Adequacy (RA) Modeling and Program Design Track 5

The CAISO will host the first working group meeting for the newly established RA Modeling and Program Design Track 5.  The meeting will be in hybrid format.  Meeting details and registration can be found here.

Proposed Revision Requests and Updated Business Practice Manuals (BPMs)

The CAISO has posted the proposed revisions requests reflecting edits to BPMs.  Revised BPMs that have completed the BPM management are posted here.

ISO NEW ENGLAND (ISO-NE)

ISO-NE Opens Markets to Distributed Energy Resource Aggregation

As of November 1, ISO-NE allows distributed energy resource aggregations to compete with traditional resources in the capacity, energy, and ancillary services markets.  Solar, storage, and other DER may now band together to participate in ISO-NE’s wholesale electricity markets.  ISO-NE stated that this change is a consequence of FERC Order No. 2222, which requires RTOs like ISO-NE to allow aggregations of DER to provide all wholesale market services that they are technically capable of providing.

Wholesale Electricity Prices and Demand

ISO-NE stated that for September 2026, wholesale power prices averaged $39.43 per MWh in the Real-Time Energy Market, up 16% compared to the previous year.  Day-Ahead Energy Market averages were $41.46/MWh, up 21% from September 2025.

Data Centers

DATA CENTERS AND LARGE LOADS

CAISO Board Approves Large-Load Proposal

On October 28, the CAISO Board of Governors approved a Large Load Enhancements proposal to facilitate the faster and more reliable interconnection of large loads, including data centers.  The proposal will be filed with the FERC by November 16, 2026, in response to FERC’s June 18, 2026 Show Cause Order (Order).

The Order directed CAISO and participating transmission owners to either demonstrate that their existing tariffs remain just and reasonable with respect to service to large load customers or to propose tariff changes to address FERC’s concerns.  The areas of concern outlined by FERC included:  (1) large-load interconnection application process, study process, and ongoing operational requirements, (2) transparency around network upgrade costs associated with serving large loads and protection against cost-shifting, (3) rates, terms and conditions applicable to co-located generation and load, (4) transmission service options for flexible and generation-associated loads, and (5) generation serving electrically-proximate or co-located load. 

The elements of CAISO’s Large Load Enhancements proposal include the following: 

Regarding large-load interconnection application and study processes, CAISO proposes to define “large load” as end users behind points of interconnection with peak load of 50 MW or greater and interconnecting to the transmission system.  CAISO also proposes ongoing coordination with the participating transmission owners on the load and resource interconnection processes, including reviewing any specific out of-cycle transmission additions or upgrades associated with large loads on a monthly basis in order to accommodate FERC’s 60-90 day process requirement for participating transmission owners’ load interconnection studies.  CAISO also proposes additional technical requirements for large-load to ensure operational visibility, and to maintain system reliability.

To address network upgrade cost transparency, CAISO proposes to publicly post aggregate amounts of proposed large-load additions in its operating area; planned network upgrades needed to accommodate large loads; and cost estimates for each planned network upgrade identified as needed for large loads.

CAISO also proposes to create a Flexible Interim Load Interconnection option, which would allow large load to interconnect before all associated network upgrades are complete, subject to operating restrictions required by prevailing grid conditions and constraints.  Large-load could then transition to firm service once network upgrades are complete.

The full proposal may be accessed here.  Once submitted on November 16, the proposal is subject to FERC approval.

Data Center Developer Sues County Over Permitting Restrictions

A data center developer sued the Pulaski County, Arkansas arguing that Pulaski County Ordinance No. 26-OR-19 was unlawful, unconstitutional, and without effect.  The ordinance regulates high-intensity digital infrastructure in Pulaski County and establishes a conditional use permit process.  The developer asserted that the ordinance will directly affect transmission rates and therefore is preempted under the Federal Power Act given that “the federal government holds exclusive jurisdiction over the operation, transmission, and sale of electric energy in interstate commerce.” The developer argued that the ordinance is also preempted under Arkansas law because the Arkansas Public Service Commission “holds exclusive jurisdiction over the generation and retail sale of electricity.”

Cities and Towns Adopt Data Center Restrictions

Third parties have reported that the Hamburg Town Board (Hamburg, New York) approved a one-year moratorium for data centers and the San Antonio City Council adopted regulations that require proposed data centers to be considered on a “case-by-case” basis. 

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[1] Per the CPUC’s Rules of Practice and Procedure Rule 14.3, comments on proposed decisions are due 20 days after issuance of the proposed decision, and reply comments are due five days thereafter. Comments on draft resolutions are due 20 days after the draft resolution appears in the CPUC’s daily calendar, per Rule 14.5.

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