November 11, 2026

Regulatory Update for November 11, 2026

(Covering November 3, 2026 - November 10, 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.

Jump to the following jurisdictions:

State Regulatory Agencies

Federal Regulatory Agencies

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

Data Centers

  Click here to download this update as a PDF

State Regulatory Agencies

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

Proposed Decisions and Resolutions

Resolution E-5481

This resolution approves Desert Community Energy’s request for electing to administer its energy efficiency funding according to the criteria set forth in Public Utilities Code Sections 381.1(e) and (f) (1) - (6) and Commission direction in Decision (D.)14-01-033 and D.24-04-007 on enabling CCAs to administer energy efficiency programs. The budget that Desert Community Energy requested to receive to fund its energy efficiency plan is $307,057. Southern California Edison is ordered to transfer $307,057 to Desert Community Energy for its three-year EE Plan.

Voting Meeting

The CPUC will hold a voting meeting on November 19, 2026 in Sacramento, California, at 11:00 a.m. PT. The energy-related items on the agenda are below:

Item 2. Resolution E-5455

This resolution approves, with modifications, Pacific Gas and Electric Company’s (PG&E) Advice Letter (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, Application (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.

Item 3. 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.

Item 4. 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 Research, Development, and Demonstration (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.

Item 6. 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 Decision (D.) 15-10-028, 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.

Item 7. Rulemaking (R.) 22-11-013 (Order Instituting Rulemaking to Consider Distributed Energy Resource Program Cost-Effectiveness Issues, Data Access and Use, and Equipment Performance Standards)

This decision establishes the guiding principles of accuracy, consistency, and transparency for the Avoided Cost Calculator used in cost-effectiveness analysis for distributed energy resources policies and programs. The decision also establishes a Distributional Equity Analysis as a companion to existing cost-effectiveness evaluations for distributed energy resources.

Item 8. Application (A.) 25-02-013 (Application of Pacific Gas and Electric Company for Compliance Review of Utility Owned Generation Operations, Portfolio Allocation Balancing Account Entries, Energy Resource Recovery Account Entries, Contract Administration, Economic Dispatch of Electric Resources, Utility Owned Generation Fuel Procurement, and Other Activities for the Record Period January 1 Through December 31, 2024)

In this proceeding, the Commission evaluates whether PG&E met the standard for compliance under the Energy Resources Recovery Account regulatory compliance process for the 2024 Record Year. This decision approves an all-party settlement agreement between PG&E, the Public Advocates Office and California Community Choice Association, resolving all contested issues scoped into this proceeding. In doing that, this decision also finds that PG&E has acted as a reasonable and prudent manager in compliance with applicable tariffs and Commission directives and thus approves PG&E’s 2024 Energy Resources Recovery Account Compliance Application.

Item 9. Rulemaking (R.) 26-04-009 (Order Instituting Rulemaking on California Advanced Electric Rate Design)

This decision authorizes an additional scope of work for up to $700,000 and contract extension for third-party consultant services to the Commission’s Energy Division relating to supporting the development of rate design and bill impact analysis tools as well as Energy Division staff analysis of rate design issues in this proceeding.

Item 10. Application (A.24-06-001 (Application of San Diego Gas & Electric Company for Approval of: (i) Contract Administration, Least-Cost Dispatch and Power Procurement Activities in 2023, (ii) Costs Related to those Activities Recorded to the Energy Resource Recovery Account, Portfolio Allocation Balancing Account, Power Charge Indifference Adjustment Undercollection Balancing Account, Transition Cost Balancing Account, Local Generating Balancing Account, and Modified Cost Allocation Mechanism Balancing Account in 2023, and (iii) Costs Recorded in Related Regulatory Accounts in 2023)

This decision authorizes San Diego Gas & Electric Company (SDG&E) to recover the net total of $3,022,040 in costs recorded to its Green Tariff and Shared Renewables (GTSR) balancing account from former GTSR customers and denies SDG&E’s request to recover the net total of $1,592,844 recorded to its GTSR memorandum accounts. This decision finds that Senate Bill (SB) 43 (Wolk, 2014) limits SDG&E from recovering GTSR-related costs from former participants in GTSR or from its own shareholders.

Item 12. Application (A.) 26-02-005 (Joint Application of Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company Requesting Commission Approval of Proposals for a BCR Calculation Methodology, Audit Methodology, and Cost Recovery Conditions as Specified in Resolution SPD-37)

This decision builds on Resolution SPD-15 and Resolution SPD-37, implementing SB 884 (McGuire, Stats. 2022, Ch. 819), codified at Public Utilities Code section 8388.5. The SB 884 program is one of several regulatory pathways through which utilities may seek authorization to recover costs associated with undergrounding investments. Unlike traditional regulatory pathways, however, SB 884 establishes a voluntary, expedited framework for the review of 10-year undergrounding plans designed to substantially reduce wildfire risk, improve reliability, and achieve cost efficiencies. The program’s longer-term planning horizon is intended to facilitate economies of scale, a sustainable supply chain, and declining undergrounding costs over time, ultimately benefiting ratepayers through more efficient and cost-effective wildfire risk reduction. This decision further implements the SB 884 framework by (1) adopting a standardized methodology for calculating Benefit-Cost Ratios that is consistent with the Commission’s Risk-Based Decision-Making Framework, (2) determining the audit framework for verifying any undergrounding costs recorded to the program’s one-way balancing account were properly recorded therein, and (3) adopting certain additional conditions (additional Phase 2 Conditions) to ensure that any costs ultimately recorded in the balancing account are just and reasonable.

Item 18. Resolution E-5473

This resolution approves amendments to extend two Portfolio Sales Agreements (PSAs) between SDG&E and San Diego Clean Power (SDCP) and between SDG&E and Clean Energy Alliance (CEA). As part of the Voluntary Allocation and Market Offer (VAMO) process, SDG&E entered into PSAs with SDCP and CEA with terms set to expire in 2034 and 2032, respectively. These PSAs resold long-term PCC 1 bundled RECs and energy from a pool of 26 PCIA eligible facilities under contract to SDG&E.

Item 31. A.25-06-017 (Application of Liberty Utilities (CalPeco Electric) LLC for Authority to Recover Costs Related to the 2020 Mountain View Fire Recorded in the Wildfire Memorandum Account)

This decision authorizes Liberty Utilities LLC (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.

Item 32. Application (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 partially authorizes PG&E to recover, on an interim rate basis, up to $456 million in revenue requirement, beginning January 1, 2027, and remaining in effect until a final decision is implemented. The decision applies a lower percentage increase to the electric functions, where PG&E requests increases, to limit the risk of overcollection that would have to be refunded. The decision applies a higher percentage decrease to the gas functions, where PG&E proposes decreases, so that customers receive more of those reductions sooner. The interim rate recovery is subject to refund. If a final decision on PG&E’s 2027 general rate case approves an amount less than what this interim mechanism has already collected, PG&E shall return any overcollection to customers, with interest calculated at the three-month commercial paper rate plus an additional Yield Spread Adjustment, if applicable, pursuant to D.25-03-010.

Item 33. 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.

Item 33A. 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.

Item 34. Application (A.) 22-05-015/016 (Applications of Southern California Gas Company and San Diego Gas & Electric Company for Authority, Among Other Things, to Update its Gas Revenue Requirement and Base Rates Effective on January 1, 2024)

This decision also addresses Southern California Gas Company’s (SoCalGas) and SDG&E’s Pipeline Safety Enhancement Program 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 operations and maintenance (O&M) costs. The decision finds $26.159 million of SDG&E’s requested capital expenditures to be unreasonable and therefore approves $213.037 million in capital costs. The decision’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 decision 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 decision finds $98.021 million of SoCalGas’s requested capital expenditures to be unreasonable and therefore approves $355.838 million in capital costs. The decision 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 decision 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 decision 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.

Item 35. Application (A.) 23-06-008 (Application of Pacific Gas and Electric Company for Recovery of Recorded Expenditures in Memorandum and Balancing Accounts Related to Wildfire and Gas Safety)

This decision authorizes PG&E to recover approximately $1,768.4 million (or $1.769 billion) in 2020–2022 costs recorded in the Wildfire Mitigation Plan Memorandum Account (WMPMA) and Fire Risk Mitigation Memorandum Account (FRMMA). The costs recorded in the WMPMA and FRMMA consist of expenses and capital expenditure PG&E incurred to implement wildfire mitigation activities. From 2020 through 2022, PG&E recorded a total of approximately $2,495.4 million (or $2.495 billion) in wildfire mitigation costs in the WMPMA and FRMMA. Of these recorded costs, PG&E is requesting approximately $2,245.7 million in cost recovery, after removing approximately $250 million from the requested costs for recovery. This decision determines that approximately $477 million of the $2,495.4 million in recorded costs is not incremental or reasonable and disallows the recovery of these costs. Compared to PG&E’s request, this decision approves approximately $1,768.4 million in recovery for 2020–2022 costs recorded in the WMPMA and FRMMA (i.e., a $477 million, or 21%, reduction to PG&E’s request).

Item 36. Rulemaking (R.) 18-07-005 (Order Instituting Rulemaking to Consider New Approaches to Disconnections and Reconnections to Improve Energy Access and Contain Costs)

This decision addresses Phase 2 issues on disconnection caps and pilot programs and considers solutions for reducing disconnection rates. This decision conditionally lifts the disconnection cap established in D.20-06-003 for SoCalGas and updates the disconnection caps for PG&E, Southern California Edison Company (SCE), and SDG&E. This decision authorizes limited, conditional increases in annual disconnection caps for PG&E, SCE, and SDG&E in 2027 and 2028, subject to a compliance filing and ongoing monitoring.

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.

Workshop on AB 2666 Implementation

The CPUC will host a hybrid workshop (both remote and in person) on December 8, 2026 to discuss implementation of Assembly Bill (AB) 2666 (Boerner, 2024), codified at Public Utilities Code section 451.8. AB 2666 requires the CPUC to analyze gas and electric utility general rate case costs and develop guidelines for calculating a rate of return. The workshop will be divided into three presentations or panels, each of which will be followed by a general Q&A. These presentations and panels will cover topics relating to establishing common cost categories and standardizing reporting requirements from AB 2666. Presenters and panelists may include state agencies, community-based organizations, academics, ratepayer advocates, and utilities.

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. – 3:30 p.m. PT.

December 14, 2026: Commissioner Workshop on Draft Energy Demand Forecast Results, 1:00 p.m. – 4:00 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)

The CEC will host a DAWG meeting on November 17, 2026 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.

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

The CEC hosted a webinar on November 10, 2026 to present and discuss commercially available and upcoming V2H solutions. The webinar included presentations from several automakers and charging equipment providers. The purpose of the workshop was to gather broad stakeholder input regarding V2H deployments as the CEC considers next steps and policies to facilitate access to bidirectional charging benefits for California EV drivers. Additional information can be found in Docket No. 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, restructuring local agency reimbursement, refining the community benefits agreement process, addressing post-certification change in project ownership or operational control, and updating the Appendix B information requirements applicable to the Opt-In Certification Program.

Comments regarding the proposed emergency regulations were due to the docket unit by 5:00 p.m. PT on November 10, 2026.

Senate Bill 254: Program Environmental Impact Report

On November 19, 2026, CEC staff will host a remote-access workshop starting at 10:00 a.m. PT to begin implementation activities pursuant to SB 254. According to the workshop notice, SB 254 “directs the CEC to prepare a program environmental impact report (PEIR) to facilitate more timely and efficient environmental review of clean energy facilities while preserving strong environmental protections and meaningful public participation.” According to SB 254, the CEC must prepare a PEIR covering the types of facilities for which it has received an Opt-In Certification application, which, thus far, includes battery energy storage facilities, solar energy facilities, and wind energy facilities. Written comments referencing Docket No. 26-PEIR-01 are due by 5:00 p.m. PT on January 15, 2027.

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.

Business Meetings

The next CEC business meeting will be held on November 18, 2026. The meeting agenda and supporting materials are available here.

CALIFORNIA AIR RESOURCES BOARD (CARB)

Ninth Circuit Issues Climate Disclosure Decision

The U.S. Court of Appeals for the Ninth Circuit issued a decision in USA Chamber of Commerce v. Sanchez, which found that SB 253’s Scope 1 and Scope 2 disclosure requirements were lawful but that SB 253’s Scope 3 disclosure requirements and SB 261 are likely unconstitutional.

The Ninth Circuit reasoned that Scope 1 disclosure requirements, which require companies to report greenhouse gas emissions from sources they directly own or control, and Scope 2 disclosure requirements, which require companies to disclose emissions from companies’ purchased energy, regulate commercial speech but survive intermediate scrutiny. The Ninth Circuit, however, noted that Scope 3 emissions, which compel reporting of indirect emissions from suppliers and customers, do not qualify as commercial speech and therefore are subject to strict scrutiny, which Scope 3 fails. The Ninth Circuit similarly noted that SB 261, which would require a reporting entity to assess and disclose climate-related financial risks, “involves predictive and normative judgments about future economic conditions” and therefore is also not a regulation of commercial speech and cannot survive strict scrutiny.

The Ninth Circuit thereby affirmed the district court’s previous denial of a preliminary injunction as to Scope 1 and Scope 2 disclosure requirements but reversed its denial as to a preliminary injunction as to Scope 3 disclosure requirements and SB 261 in its entirety and remanded to the district court the question whether SB 254’s Scope 3 provision is severable.

MINNESOTA PUBLIC UTILITIES COMMISSION (MPUC)

At its November 13, 2026, weekly agenda meeting, the MPUC will consider: (1) granting a site permit to Mankato Energy Center, LLC for the up to 30 MW Mankato Battery Energy Storage System in Blue Earth County, Minnesota (Docket No. IP7178/ESS-26-158); (2) granting a site permit to LSP CG Storage, LLC for the up to 80 MW Cottage Grove BESS Project (Docket No. IP7180/ESS-26-184); (3) granting a site permit to Mayhew Lake Energy Storage, LLC for the up to 100 MW project in Benton County, Minnesota (Docket No. IP7172/ESS-26-112); (4) approving Xcel Energy’s proposal to establish a Renewable Gas Interconnection Tariff and recover the costs of the purchase of gas through the Purchased Gas Adjustment (Docket No. G002/M-26-253); (5) accepting the 2025 annual GAP reports from Xcel Energy, Great Plains Natural Gas, CenterPoint Energy, Minnesota Energy Resources, and Greater Minnesota Gas, as well as approving Great Plains Natural Gas’ proposal for automatic enrollment (Docket Nos. G002/M-26-36; G004/M-26-37; G008/M-26-38; G011/M-26-39; G022/M-26-40); and (6) approving CenterPoint Energy, Xcel Energy, and Minnesota Energy Resources’ joint proposed modifications to the requirements from the Frameworks Order that governs how utilities comply with the Natural Gas Innovation Act (Docket No. G999/CI-21-566).

Additionally, on November 5, 2026, the MPUC granted a permit for Magellan Pipeline Company to reopen a gas pipeline near the Pipestone National Monument. Under the permit, Magellan cannot begin construction until it finishes surveying the approved route for cultural and archeological sites. Local news coverage can be found here.

PACIFIC NORTHWEST (OPUC, WUTC, BPA)

Oregon Public Utility Commission (OPUC)

On November 6, 2026, after securing re-election, Governor Tina Kotek said that she would propose statewide data-center standards addressing water use, transparency, energy use, and electricity sources, and urged legislative action within the first 60 days of the 2027 session.

On November 12, 2026, the OPUC will hold a Special Public Meeting concerning utilities’ standardized avoided-cost workbooks implementing Order No. 26-021 (Docket No. UM 2436). Staff memo and agenda available here.

Washington Utilities and Transportation Commission (WUTC)

On November 5, 2026, Kittitas County released a draft Environmental Impact Statement (EIS) for its Clean Energy Siting and Permitting project, evaluating potential changes to siting locations and permitting standards for solar, wind, battery storage, geothermal, and small modular reactors. Public comments are due December 11, 2026. More information available here.

Bonneville Power Administration (BPA)

BPA announced that it will extend the Grid Access Transformation (GAT) schedule. In addition to the November 18 workshop, BPA will add workshops in December and possibly January to discuss proposals before initiating the expedited BP-27R rate case and TC-27R tariff proceeding. Information about upcoming GAT workshops available here.

On November 6, 2026, BPA announced it has adjusted the billing factor for Operating Reserves effective for October billing following the Western Power Pool’s adoption of a new Contingency Reserve Obligations methodology. More information is available here.

On November 4, 2026, Earthjustice announced that conservation and clean-energy groups had reached a proposed settlement that would reduce BPA’s planned additional rate collections from $250 million to $212 million, pending approval by the BPA administrator. More information is available here.

Finally, the materials BPA shared on October 30, 2026, at the Day-Ahead Market Workshop are now available on its webpage 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 warning 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.

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

CALIFORNIA INDEPENDENT SYSTEM OPERATOR (CAISO)

Stakeholder Initiatives: Upcoming Meetings and Deadlines

Review of Final 2027 Resource Adequacy (RA) Compliance Filings and Determination of Deficiency

The CAISO has posted its aggregate assessment of the annual RA plans submitted by load-serving entities and central procurement entities along with the reliability-must-run units designated by the CAISO, for compliance with 2027 local, system, and flex resources RA requirements.

PJM INTERCONNECTION LLC (PJM)

PJM Accepts Additional Expedited Interconnection Track (EIT) Project

PJM accepted a fourth project in its new, temporary process designed to get large generation resources online quickly. The new project is a storage facility with 500 MW in nameplate capacity. The application window for the EIT opened on July 31, 2026 for projects that are backed by a primary siting authority and can begin operation within three years. In October, PJM accepted the first three proposals: two battery storage projects and one natural gas generator upgrade with more than 2,100 MW in combined nameplate capacity.

Through the EIT, PJM will approve up to 10 interconnection requests per calendar year in 2026 and 2027 for large new or uprated capacity resources. To qualify, resources must have, among other requirements, a commitment from a relevant state authority to help expedite site permitting and offer at least 250 MW of unforced capacity.

ELECTRIC RELIABILITY COUNCIL OF TEXAS (ERCOT) 

ERCOT Updates PUCT on Large- and Medium-Load Interconnection Review

On November 4, 2026, ERCOT filed an update with the Public Utility Commission of Texas (PUCT) regarding its review of large- and medium-load interconnection requests. ERCOT reported that it is continuing its “Batch Zero” eligibility verification process and has identified issues involving documentation of affiliate relationships, site control, long-lead-time equipment, and the amount of financial security posted. ERCOT expects to issue second-round requests for information to approximately 80% of developers, with responses due within five business days, and plans to submit its verification report to the PUCT by December 10, 2026. ERCOT also indicated that it expects to seek certain “good cause” exceptions to Batch Zero eligibility requirements, including for developers that posted required financial security after the applicable deadline and for certain large loads that were submitted as energized but had not energized by July 10, 2026.

Data Centers

DATA CENTERS AND LARGE LOADS

CAISO Board Approves Large-Load Proposal

On October 28, 2026, 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 loads 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 loads to interconnect before all associated network upgrades are complete, subject to operating restrictions required by prevailing grid conditions and constraints. Large loads 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.

--------------------

[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.

Media Contact

Jamie Moss (newsPRos)
Media Relations
w. 201.493.1027 c. 201.788.0142
Email

Practice Areas

Industries

Chapters

Jump to Page