Client Alert
Energy Law: Month in Review - October 2026
November 5, 2026
by Zev Simpser, Brian Bell, and Sonja Smerud
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Welcome to Dorsey’s Energy Law: Month in Review. We provide this update to our clients to identify significant developments in the previous month. Please reach out to any of the authors, listed above, to discuss these issues.
Regulatory Developments
FERC Approves Penalties for Nonperforming Demand-Side Resources
On October 23, the Federal Energy Regulatory Commission (FERC) approved a set of penalties in Docket No. ER26-1882 for Load Modifying Resources (LMR), or demand-side response and behind-the-meter generation assets. The penalties apply to resources that fail to fully perform when called upon during grid emergencies in the Midcontinent Independent System Operator (MISO) market. The new penalties follow a series of enforcement cases involving MISO’s demand response program. FERC reasoned that MISO’s existing LMR penalty structure did little to discourage fraud and other manipulative behaviors given that such demand resources are rarely needed in MISO’s capacity market. FERC directed MISO to resolve some inconsistencies in tariff language before the revisions go into effect on June 1, 2027. Regulators generally sought to balance economic market participation with the need to shed load in a timely manner and meet energy adequacy targets.
FERC Approves Local Transmission “Asset Condition” Process
FERC accepted ISO New England’s (ISO-NE) tariff revisions allowing ISO-NE a formal advisory role in reviewing asset condition projects. Asset condition projects are refurbishment projects aimed at repairing or replacing aging transmission infrastructure. Historically, asset condition projects have received little regulatory oversight and are planned by local utilities. The review plan was spurred by a consumer complaint to FERC reflecting concerns about visibility and cost-effectiveness. Review will now include, for example, ISO-NE’s assessment of project needs based on specific, concrete evidence of physical deterioration or impending failure of the transmission asset.
FERC Approves Duke NITSA Revisions Despite Consumer Protection Concerns
On October 9, FERC approved Duke Energy Carolinas’ large load transmission tariff revisions. The approval came despite concerns about burdening existing customers with the cost of large load network integration. The revisions amend Duke’s pro forma network integration transmission service agreement (NITSA) and include financial security requirements for network upgrades and shortfall payments. Large loads will pay a committed revenue contribution equal to 75% of the megawatt value in the load schedule for a 15-year period following the in-service date. Transmission customers requiring network upgrades to accommodate a large load will pay a monthly charge, to be reimbursed once the upgrades are in service. FERC Commissioner Judy Chang voted against Duke’s proposal, noting it lacked transparency around large load agreements and meaningful financial security mechanisms. Similar orders will likely be issued in the coming months in response to FERC’s show cause orders directing regional transmission organizations (RTOs) and independent system operators (ISOs) to propose revised large load interconnection rules that adequately protect existing customers from cost-shifting in response to data center buildout.
FERC Largely Rejects PJM’s Data Center Interconnection Plan
FERC recently rejected most of PJM Interconnection’s proposed large load interconnection plan, the Interim Resource Adequacy Service Framework (IRAS). The proposed plan included interim service provisions and “bring your own capacity rules” that would have allowed large loads to connect to the grid without matching new capacity if they agreed to be curtailed in grid emergencies. The plan also included a proposed definition and “registry” of large loads that includes information about the facility’s location, schedule, and capacity supply. FERC approved the large load registry but rejected the interconnection framework, reasoning that it discriminates against large loads and intrudes on state jurisdiction. FERC commissioners also noted that market distortions could result from excluding IRAS loads from PJM’s capacity auction demand curve.
Virginia Approves Fuel Cost Securitization in Response to Volatile Fuel Costs
The Virginia State Corporation Commission approved Dominion Energy’s (Dominion) requests for fuel recovery and cost increases, including about $922 million in securitization for under-recovered fuel costs from the 2025 and 2026 rate years. In Case No. PUR-2026-00058, Dominion requested revision to its fuel factor effective July 1, 2026. The basis for the decision approving the fuel factor revisions and securitization was increasing demand for power purchases from PJM because of Winter Storm Fern. Dominion received a similar approval for securitization of about $1 billion in deferred fuel costs in 2023 because of the Ukraine War. To better incentivize the use of renewable energy, intervenors in the rate proceeding argued that Dominion, rather than customers, should bear any fuel cost overruns. The decision will allow Dominion to issue bonds to spread recovery of fuel costs over a seven-year period but will add financing charges over time.
California Directs Utilities to Propose DER Orchestration and Load Flexibility Framework
On October 29, the California Public Utilities Commission adopted an application process and working group schedule for public utilities to propose a coordinated orchestration framework for managing distributed energy resources (DERs). The use of DERs, including customer-sited batteries, electric vehicles, and other technologies that can adjust when and how electricity is consumed, is expected to increase due to California’s transportation electrification policies, financial incentive programs for DERs, and climate and reliability goals. DER orchestration involves the coordination and management of DERs by a utility to optimize capacity utilization using visibility, forecasting, and control and scheduling tools. The approved application framework is centered around 11 guiding principles aimed at reducing electric system costs for ratepayers, supporting grid reliability, and advancing climate goals. Working group meetings and DER orchestration applications are expected to follow in the next 12 months from Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric Companies.
New York Cracks Down on Energy Services Companies
In October, the New York State Public Service Commission (NYPSC) revoked the eligibility of a private energy services company (ESCO) and several distributed energy resource (DER) suppliers to operate in the state. The companies failed to submit annual required compliance filings, used unregistered subcontractors, conducted improper customer enrollments, and ignored customer complaints, among other improper operations. These actions violated the NYPSC’s Uniform Business Practices for Distributed Energy Resource Suppliers (UBP-DERS), which are designed to ensure strong consumer protection. The state’s UBP-DERS provide for consistent business procedures for ESCOs, DER suppliers, and other energy brokers, consultants, and suppliers. Under those rules, if a consumer’s ESCO is no longer permitted to operate, electric service reverts to the local utility.
Wisconsin Announces Funding Opportunity for Grid Resilience
The Wisconsin Public Service Commission has approved a funding opportunity called the Grid Resilience Program for small utilities to facilitate investments in the modernization of the electric grid. The program is designed to guard against current and future threats to infrastructure, reduce the frequency and duration of service interruptions in rural and disadvantaged communities, and increase the skilled workforce to support resilience-related activities. Project proposals related to weatherization technologies and equipment are especially encouraged. Applications for the program are due by February 22, 2027, with $7.2 million in project funding available for Phase I.