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January 15, 2026

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State Briefs

CALIFORNIA

Trump Admin Sues Morgan Hill, Petaluma Over Local Natural Gas Bans

The Trump administration has sued the Bay Area cities of Morgan Hill and Petaluma to block their bans on natural gas infrastructure in new buildings.

The lawsuit claimed the local decarbonization measures deny consumers reliable and affordable energy while undermining “American energy dominance.” By banning the fuel gas piping “in pursuit of electrification,” the government argued, the cities “undermine and conflict with” federal energy policy.

Morgan Hill adopted its natural gas prohibition in late 2019. Petaluma followed suit in May 2021.

More: KQED

ILLINOIS

Peoples Gas Files for $202M Rate Increase

Peoples Gas filed for a $202.3 million rate hike request with the Commerce Commission.

The increase, which the company estimates will add $10 to $11 to monthly gas bills for typical residential customers, comes three years after Peoples Gas received a $303 million rate hike in 2023, the largest in state history. The company said the revenue is required to meet the ICC’s order to retire more than 1,000 miles of old iron pipes by 2035.

The ICC will review the request over the next 11 months.

More: Capitol News Illinois

IOWA

Gov. Reynolds Creates Nuclear Energy Task Force

Gov. Kim Reynolds announced the creation of the Iowa Nuclear Energy Task Force, which will generate a report and advise state leadership on opportunities to embrace nuclear energy in the state.

Reynolds said the task force marks a “strategic step forward” to ensuring Iowa has a “safe, efficient and responsible integration” of nuclear energy. The task force is asked to assess emerging nuclear technologies, engage with industry leaders to help develop the necessary workforce, and engage with manufacturers and other stakeholders to identify potential barriers to entry in the nuclear field.

Presently, Iowa has no operational nuclear energy plants, but NextEra Energy is working to restart the Duane Arnold Energy Center in Linn County.

More: Iowa Capital Dispatch

KENTUCKY

PSC Extends Kentucky Power Use of Coal Plant

The Public Service Commission has approved Kentucky Power’s plan to continue using the Mitchell Generating Station after 2028, concluding the coal-fired plant remains the least costly option available to meet the region’s power needs.

A Certificate of Public Convenience and Necessity allowed the company to maintain its 50% share of the plant.

The approval includes recovery of costs associated with federally required wastewater treatment upgrades at Mitchell, which will raise the average household bill by about $2.33/month.

More: The Mountain Eagle

MARYLAND

Conowingo Dam Appeal Dropped, Allowing $340M Settlement to Go Forward

Maryland’s $340 million settlement with the owner of the Conowingo Dam can now move forward after a group of Eastern Shore counties dropped their challenge of the deal.

The Department of the Environment, which brokered the settlement, had lobbied for the counties to back down because the appeal had the potential to derail or delay funds from dam owner Constellation. The state negotiated to receive the funds in exchange for issuing the hydroelectric dam a water quality certification, which it needs to obtain a 50-year license from FERC.

After state officials promised counties they could have input on the rollout of the environmental projects in the settlement, several counties pulled out in late December. Cecil County, which hosts the dam and has complained about the impacts of sediment build-up, was the final holdout, but dropped out Jan. 2.

More: Maryland Matters

MICHIGAN

PSC Adopts New Rule for Bill Increase Notifications

The Public Service Commission is set to adopt a new rule that will require utilities to notify each customer how much their rate-hike requests would cost if approved, both in a dollar amount and percentage amount.

It’s one of the changes being made by the PSC to increase customer participation in utility issues, including cases that set new rates. DTE Energy and Consumers Energy filed objections to the new rule before it was adopted.

More: Michigan Public Radio

NEW YORK

NYC GHG Emissions Drop to Pandemic Levels

New York City’s latest annual greenhouse gas inventory showed a decrease of about 5% in emissions citywide compared to the previous year and a 25% cut since 2005, when the city began tracking its emissions.

The COVID-19 pandemic spurred the largest drop in emissions since tracking began, with a 9% decline between 2019 and 2020 as people stayed home or left the city entirely. In 2024, transportation emissions were more than 16% higher than in 2020, but emissions from buildings and waste were 5% and 3% lower, respectively. Emissions from natural gas increased 15% compared to 2005 but still were at decade low.

More: The City

OHIO

PUC Approves Settlement to End FirstEnergy HB6 Cases

The Public Utilities Commission will end its House Bill 6-related investigations into FirstEnergy Corp. by approving a settlement agreement filed with the agency in December.

The settlement between FirstEnergy and multiple other groups — including the Office of the Ohio Consumers’ Counsel, the Ohio Manufacturers’ Association Energy Group and the Retail Energy Supply Association — will provide FirstEnergy customers with $249 million in restitution over three billing periods, the commission said. The settlement also designates $20 million to fund low-income programs.

The settlement will not include the previously announced $64.1 million in civil forfeitures.

More: Akron Beacon Journal

PENNSYLVANIA

Supreme Court Dismisses Appeals to Revive RGGI

The Pennsylvania Supreme Court has ended appeals of a lower court’s ruling that the commonwealth’s participation in the Regional Greenhouse Gas Initiative was illegal. 

The court’s order dismissing the cases as moot follows Gov. Josh Shapiro’s agreement to withdraw from the multistate climate compact as part of his deal with Republican state lawmakers to bring the five-month budget stalemate to a close in November.

More: Pennsylvania Capital-Star

TEXAS

Solar Supplies More Power than Coal to Grid in 2025

In 2025 — for the first year ever — solar provided more electricity to Texas’ main grid than coal-fired power plants.

Solar farms contributed 67,800 GW from January to December, according to ERCOT data. In comparison, coal-fired plants supplied 63,000 GW.

More: Houston Chronicle

VIRGINIA

Dominion Gas Plant on Hold While SCC Considers Petition

Dominion Energy’s proposed Chesterfield County natural gas plant is on hold, as the State Corporation Commission reconsiders its final order approving the project.

In a Dec. 15 decision, the SCC issued a brief ruling that it will consider a petition from opponents of the Chesterfield Energy Reliability Center — Appalachian Voices, the NAACP and Mothers Out Front. It will put the project on hold for at least the time being, according to the ruling. The petition raised multiple issues, including health impacts of air pollution, higher costs for customers and the disregarding of “substantial proof that new gas is not required to meet Virginians’ energy needs.”

Meanwhile, on Dec. 19, the Department of Environmental Quality approved an air permit for the project. However, it does not override the SCC’s reconsideration.

More: Virginia Business

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Company Briefs

Hallador Energy Appoints Sugg to Board of Directors

Hallador Energy last week announced it has appointed Barbara Sugg to its Board of Directors, effective Jan. 1.

Sugg is the former president and CEO of SPP.

Sugg’s appointment follows the resignation of David Hardie.

More: Hallador Energy

Sunrun, HASI Close $500M Distributed Energy Joint Venture

HA Sustainable Infrastructure Capital and Sunrun last week announced the closing of a joint venture to finance distributed energy assets.

HASI will invest $500 million over an 18-month period into the newly formed entity. The partnership intends to finance 300 MW of solar and energy storage capacity.

More: pv magazine

LG Energy Solution to Sell Ohio Battery Building to Honda

LG Energy Solution last week announced it will sell the building of its Ohio EV battery joint venture plant to its partner, Honda, for $2.9 billion.

According to regulatory filings, LG will dispose of the building and all building-related facilities of the joint venture L-H Battery Company — excluding the land and equipment — to Honda’s U.S. unit. The joint venture will continue to use the facility under a lease agreement, with no changes to production or operational plans.

The transaction is scheduled to be completed Feb. 28.

More: Batteries News

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PJM OC Briefs: Jan. 8, 2026

Stakeholders Delay Vote on Manual 1 Revisions

PJM’s Operating Committee deferred a vote to endorse revisions to Manual 1: Control Center and Data Exchange Requirements to give more time to review language removing a requirement that actual meter test results should be provided to the RTO. (See “PJM Seeks Quick Fix on Data Communications,” PJM Operating Committee Briefs: Dec. 4, 2025.)

PJM’s Ryan Nice said staff’s thinking in recommending the removal is that meter calibration and test results tend to be conducted by third-party specialists and are better addressed through resources’ interconnection service agreements. Nice said the tests represent a small part of how PJM models and validates resources’ output.

Stakeholders raised concerns that without PJM directly receiving the results of those tests, it would assume the data is accurate unless it is informed of a problem.

The proposed language also reflects NERC reliability standard CIP-012-2 (Cybersecurity – communications between control centers) requiring plans to “mitigate the risks posed by unauthorized disclosure, unauthorized modification and loss of availability of real-time assessment and real-time monitoring data in transit between applicable control centers.”

The revisions would detail the RTO’s PJMnet system for internal communications, require that members submitting distributed network protocol links provide their own data maps and definitions, and clarify that PJM will not consume or process data not needed for its own purposes, which Nice said is intended to underscore that PJM is not a generic data repeater for its members.

Manual Language to Implement AARs Endorsed

PJM presented a first read on revisions to Manual 3: Transmission Operations and Manual 3A: Energy Management System Model Updates Quality Assurance to conform with FERC Order 881, which requires the implementation of ambient-adjusted line ratings (AARs).

The Manual 3 changes include adding short-term emergency ratings to the Thermal Operating Guidelines, maintenance responsibilities for rating set lookup tables, and an option for transmission owners to resort to AARs or seasonal ratings during a dynamic line rating outage. The manual would set PJM’s transmission facilities rating database as the data source for lines with short-term emergency ratings.

The Manual 3A revisions would add two sets of 5-degree bands to the Transmission Facility Ratings Database for day and night, ranging between -55 degrees and 130 degrees F. The database would be available for all eDART users. Conditional rating tables would be added to cover loss of cooling, directional ratings and proxy stability limits.

Annual Recertification

PJM is planning to include member officers in its notifications around the commencement of the annual recertification process owing to an increase in the number of final warning letters and breach notices sent in 2025.

In response to feedback from stakeholders, the RTO did not include officers in the 2025 recertification process, but found many companies were less responsive. PJM determined that the omission of officers contributed to RTO staff having to make additional efforts to reach out to members.

Members are required to update their sector selection, affiliate disclosure, company information and contact managers by April 17. Market participants are also required to disclose their principals.

By the end of April, market participants should submit an officer certification form, risk management policies and audited financials for 2025.

December Operating Metrics

PJM’s Marcus Smith said load forecast performance was strong across the December 2025 holidays, a point of focus in recent years as the intersection between gas procurement cycles and difficult-to-predict holiday loads has led to strained system conditions.

The average hourly forecast error for the month was 1.78% and the average peak forecast error was 1.57%. Peak loads on several days exceeded the RTO’s 3% error benchmark: Dec. 17 was over-forecast by 3.53% due to high temperatures; Dec. 8 was 3.1% under-forecast due to high cloud coverage; cool temperatures on Dec. 14 led to a 3.31% under-forecast; and the Dec. 20 peak was 3.25% higher than expected due to cold and windy weather.

December saw three spin events, three shared system events, one high system voltage action, three cold weather alerts and 26 post-contingency local load relief warnings. Smith said the month was 5 degrees colder than the average of the past three Decembers and recorded the highest December peak load on Dec. 22.

A spin event Dec. 5 was initiated at 7:30 p.m. and lasted 4 minutes and 25 seconds. There were 2,350 MW of generation assigned and 373 MW of demand response, of which 49% and 69% responded, respectively.

Another event was declared the following day at 5:05 a.m. and lasted 7 minutes and 44 seconds. There were 2,350 MW of generation and 218 MW of DR assigned, with 79% and 91% responding.

The third event fell Dec. 28 at 5:07 p.m. and lasted 9 minutes and 46 seconds. There were 2,012 MW of generation assigned and 642 MW of DR, of which 76% and 89% responded.

The RTO faced below-zero temperatures and high snowfall during a winter storm that passed through the region Dec. 12-16. The peak load during the storm was 136,467 MW at 8:20 a.m. Dec. 15.

PJM’s Paul Dajewski said temperatures were lower than forecast during much of the storm and some generators were dispatched but ran into emissions limits preventing them from operating. Staff considered requesting waivers from those limits under the Federal Power Act Section 202(c).

The storm was the first winter event where gas generators were able to signal fuel supply concerns through an indicator on Markets Gateway, which several resources used to update PJM on their status. Four cause codes were added to eDART to increase the granularity of tracking gas-related outages.

Synchronized Reserve Inquiry

The Independent Market Monitor presented the latest results of its ongoing inquiry into the causes of synchronized reserve underperformance, this time looking at a 2,720-MW deployment Nov. 11. While PJM reported an 83% response rate, the Monitor argued PJM should consider reserves that overperform their assignment, which would increase the response rate to 104%. (See “Monitor Presents Synchronized Reserve Performance Inquiry,” PJM Operating Committee Briefs: Dec. 4, 2025.)

Communications have become a smaller driver as PJM has implemented new protocols for sending dispatch instructions to resources; however, parameters and personnel issues have become more pronounced. The single-largest cause of underperformance was parameter issues, followed by hardware issues and software.

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BPA Tx Planning Overhaul Prompts Concern for Northwest Clean Energy Compliance

Some of the Bonneville Power Administration’s proposals aimed at improving transmission planning processes risk pushing study timelines to the point where the agency’s customers could run afoul of Washington and Oregon’s clean energy targets, stakeholders say.

BPA paused certain planning processes and launched the Grid Access Transformation (GAT) project in 2025 to consider changes following a surge of transmission service requests (TSRs). The most recent transmission study includes 61 GW of new generation, compared with 5.9 GW in 2021, according to the agency. (See BPA Halts Some Tx Planning Processes Amid Surge of Service Requests.)

BPA’s proposal to tackle the queue involves a two-part approach: a transitional phase to get off the pause and a longer-term “future state” that will include more substantial reforms to BPA’s existing transmission processes, such as shifting toward proactive transmission planning (an approach that seeks to forecast transmission needs and prepare the system ahead of time rather than just reacting to customer requests).

During a Jan. 6 meeting, BPA staff and industry representatives discussed options the agency could pursue during its transitional phase to identify customers eligible for transmission service awards to get off pause while the agency continues to plan for the “future state.”

“Depending on the outcome of queue reform, the queue size will be a determining factor in which type(s) of transition analysis can be completed,” according to BPA’s presentation slides. “Additionally, the same team that does this transition analysis is also working to stand up proactive planning and achieve the future state. Essentially, more time dedicated to transition analysis will delay the future state.”

Some of the transition study options BPA has presented could present challenges for Oregon and Washington-based customers, Henry Tilghman, a consultant whose clients include Renewable Northwest and the Northwest & Intermountain Power Producers Coalition, told RTO Insider. (Tilghman spoke on his own behalf, not that of his clients.)

Washington and Oregon passed aggressive clean energy laws in 2019 and 2021, respectively, requiring electric utilities to meet strict greenhouse gas standards by 2030. (See Washington Agencies Adopt New Rules to Implement CETA and Clean Energy, Equity Goals to Reshape Oregon IRP Process.)

Many of the options presented by BPA would push study timelines for transmission service requests beyond the 2030 deadline, according to Tilghman. He noted that some options would result in transmission service awards before 2030, though those options would require smaller study volumes.

Tilghman’s clients have yet to adopt a preferred option, but he said the timeline to complete the transition study could be one factor they would consider in making their choice.

“There are a lot of ways to look at … what the right solution is here,” Tilghman told BPA at the Jan. 6 meeting. “One of them would be to focus on what gets the most new transmission service, even if that’s interim or conditional firm service, into the hands of customers by those 2030 deadlines. … And certainly one way we could go would be to design a program that would facilitate … filling up the transmission grid that will exist in 2030 with transmission service in customers’ hands.”

Seattle City Light’s Michael Watkins echoed Tilghman’s comments, saying the discussions are “about meeting customer needs for transmission for 2030, 2035 and 2040.” He added that “strict regulatory requirements” are forcing the industry “down certain roads.”

BPA must “answer those needs,” Watkins said. “Because the needs are large enough that if Bonneville does not answer those needs, someone else will. And … none of us may like how that happens — both customers and Bonneville. So, we need to come together and meet those needs somehow.”

Proactive planning is the fastest way to create available transmission to serve needs by 2030 and 2035, Watkins added.

“If we really hit the gas, we can do that,” he said. “But if we spend the next 24 to 36 months still trying to slice the existing pie, we’re not going to get there.”

‘Sweet Spot’

The discussion around Washington and Oregon’s clean energy goals was prompted by comments from Randy Hardy, the agency’s administrator from 1991 to 1997.

During the Jan. 6 meeting, Hardy reiterated claims he made to RTO Insider in June 2025, arguing that the states’ respective laws set off a “gold rush’ among developers, eventually leading to today’s situation. (See Industry Sees Challenges as BPA Considers ‘Radical’ Updates to Tx Planning.)

“That’s the nature of the problem,” Hardy said Jan. 6. “It’s not a Bonneville problem. It’s not a customer problem. Its origins are in the state legislative mandates, which have created essentially an unmeetable situation relative to the 2030 deadline and the 65 GW in the queue, which now Bonneville is left holding the bag and having to solve. And that’s what we’re all trying to do.”

In an email, BPA spokesperson Kevin Wingert said when the agency decided to transition to a new process for its large generator interconnection queue to be able to study the “the unprecedented number of gigawatts being requested (there are 61 GW of generation in the current study), we identified 16 GW of late-stage generation projects that were ready to move forward beyond the queue process into execution.”

“We’ve begun the process of integrating that generation at a rate of roughly 1 to 1.5 GW per year,” Wingert wrote. “We anticipate 7.5 GW being integrated by 2030, with the full 16 GW of late-stage projects being integrated by 2035. That 1 to 1.5 GW integration rate is record setting for BPA and represents a basic sweet spot in terms of capacity from workforce, contracting, manufacturing and supply chain elements. We anticipate maintaining that pace for the foreseeable future.”

Wingert added that BPA is “working on reducing our timeline for project delivery down to a five- to six-year window. This work is incremental in nature, but our current goal for full implementation on this effort is 2030 and includes efforts to increase study efficiencies like potential automation or contracting aspects of the work.”

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SPP: Ex-Idaho Commish to Manage Regulatory Policy in West

SPP has hired former Idaho commissioner Kristine Raper as its senior director of state regulatory policy for the West, effective Jan. 20.

Raper will work with state utility regulatory commissioners in the Western Interconnection to advance SPP’s mission as it expands its RTO footprint into the West and also develops its day-ahead Markets+ service offering.

The grid operator said in a Jan. 12 news release that Raper will assist the management team in addressing ongoing state and federal energy issues, initiatives and strategic matters at the state regulatory level.

“Kris brings years of experience providing well-respected leadership on key issues for state regulators and electric industry stakeholders in the West,” SPP General Counsel Paul Suskie said in a statement.

Raper, who will work out of Idaho, first was appointed to the state’s Public Utilities Commission in 2015 and re-appointed in 2021. She left the commission in 2022 to join WECC as vice president of external affairs.

Vijay Satyal, deputy director of clean energy markets and transmission for environmental nonprofit Western Resource Advocates, congratulated Raper for taking on the “uniquely challenging role” and using her “regulatory policy expertise and experience” in coordinating WECC’s West-wide grid reliability.

“As Kris knows well, the West is embarking on an effort for greater West-wide market integration,” Satyal said, name-dropping the West-Wide Governance Pathways Initiative that is setting up an independent organization to oversee CAISO’s Western Energy Imbalance Market and Extended Day-Ahead Market. (See Pathways Takes Key Step Toward Establishing ROWE.)

“WRA looks forward to Kris’ collaboration and SPP support toward grid modernization (reliability and markets integration) in the West,” Satyal added.

Raper has chaired the Western Interconnection Regional Advisory Body, an organization under the Federal Power Act that advises FERC, NERC and WECC on matters related to grid reliability in the West. She also was a member of the WEIM’s Body of State Regulators and served on its Governance Review Committee. (See Joint CAISO-EIM Authority Debated in West.)

She holds a bachelor’s degree in criminal justice from Boise State University and a law degree from the University of Idaho College of Law.

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PJM Presents RTEP Assumptions, $11.6B Package

State Assumptions for 2026 System Planning

The Organization of PJM States Inc. presented PJM’s Transmission Expansion Advisory Committee with a set of assumptions for the RTO’s planning process reflecting state legislation and policies.

Director of Legal and Regulatory Affairs Ben Sloan said the Independent State Agencies Committee (ISAC) submitted assumptions for PJM’s 2026 Regional Transmission Expansion Plan (RTEP) on Dec. 12, the third such submission it has made.

The ISAC added new assumptions around large load tariffs established in Ohio; several clean energy and electrification efforts; changes to integrated resource plans filed in Virginia; and updated offshore wind targets in Maryland, New Jersey and Virginia.

The New Jersey offshore wind targets were pushed back to start with 3,724 MW in 2034 and reach the 11-GW target in 2040. 8.5 GW are also expected to come online in Maryland between 2027 and 2031.

2026 RTEP Assumptions Timeline

PJM presented the timeline for the 2026 RTEP cycle, which started in November with establishing base case modeling assumptions. Through March, staff will continue building base cases and perform initial case review, with the possibility of changes to the assumptions if they are determined to have a significant impact.

Between March and June, the RTO will conduct baseline studies with the aim of opening a competitive proposal window in July 2026. The window is expected to close in August or September, at which point a mid-year retool may be conducted. Board of Managers approval of a package of upgrades is targeted for February 2027.

2nd Read on $11.6B RTEP Window

PJM presented a second read of its $11.6 billion package of recommended projects for inclusion in the 2025 RTEP. Board approval of the recommended projects is expected in the first quarter of 2026. (See PJM Considering $11.6B Transmission Expansion Plan.)

The proposals were grouped in three clusters: $4.8 billion in upgrades in southern PJM centered around a 185-mile undergrounded HVDC line between the Heritage and Mosby substations, along with several 500-kV projects; $2.8 billion to construct several 765-kV lines in the Columbus area; and $1.7 billion of upgrades in Mid-Atlantic Area Council (MAAC), most notably a 222-mile, 765-kV line between the Kammer and Juniata substations.

The MAAC projects were scrutinized by stakeholders questioning the need for the line to extend between Kammer and the planned Buttermilk substation. Some also questioned the use of seven-year scenarios to justify the project. The longer horizon scenarios are meant to right-size projects for shifting needs; however, stakeholders argued the need for the Kammer-Juniata line in the five-year scenarios is not fully demonstrated.

The scale of the projects included in the window is being driven by 8 to 12 GW of load growth expected in PPL and MAAC, along with capacity resource deactivations and delays in offshore wind development.

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PJM MIC Briefs: Jan. 7, 2026

Fuel Cost Policy Updates for Manual 15

The Market Implementation Committee endorsed an issue charge to evaluate whether revisions to Manual 15: Cost Development Guidelines are warranted to preclude market sellers from inflating cost-based offers by using inaccurate fuel cost estimates from affiliated suppliers. The issue charge passed with 81.9% support. (See “Fuel Cost Policy Issue Charge,” PJM MIC Tackles Issue Charges, Problem Statements.)

PJM’s David Hauske said the issue charge would memorialize the RTO’s existing practices around approving fuel cost policies.

Joel Romero Luna, an analyst with the Independent Market Monitor, said all of the currently approved fuel cost policies meet the changes contemplated by the issue charge.

Stakeholders questioned how the definition of “affiliate” used in the issue charge might interact with the tariff-defined term. PJM Associate General Counsel Chen Lu said “affiliate” was lowercased intentionally to avoid tying it to the governing document definition.

Manager of Stakeholder Process and Engagement Michele Greening said PJM can revise the issue charge to allow for changes to the governing documents if necessary.

Monitor Reminder for Reviewing Fuel Cost Policies

The Monitor presented a reminder that market participants with fuel cost policies expiring in November 2026 should review the compliance of their policies and update them if needed. Those who fail to extend their policies will be required to submit a new one and either submit cost-based offers priced at zero or use PJM’s temporary cost offer method in the meantime.

PJM Proposes Performance Penalties for Non-emergency Load Management

PJM presented a proposal to assess performance penalties against demand response (DR) resources that do not meet their obligations during a non-emergency load management deployment.

Curtailment service providers (CSPs) that do not meet their obligations would be subject to a penalty rate set at half the charge for capacity resources that fail to respond during a performance assessment interval (PAI), which would be approximately $1,150/MWh for the 2027/28 delivery year. The additional penalties would count toward the annual stop-loss limit capping the amount of capacity performance penalties a resource can be assigned in a delivery year.

PJM’s Pete Langbein said the revenues collected from the penalties would be allocated to load-serving entities (LSEs) as a bonus on the logic that they purchased the capacity CSPs are expected to provide.

According to the problem statement brought by PJM, there were six deployments in the summer of 2025 totaling 30 hours, with a weighted average performance of 67%.

“This is significantly lower than in prior years and much lower than the overall test results of 103% for the [2024/25] DY. PJM expects to dispatch load management (and/or PRD will be required to respond) more frequently in the future due to lower reserve margins,” PJM wrote.

Voltus presented a non-performance penalty based on the IESO market design, which would set charges at the shortfall measured in unforced capacity (UCAP) times the daily capacity rate and a non-performance factor based on event duration. A portion of the penalties would go to overperforming CSPs, and the remainder would be allocated to consumers.

Auction Report Correction

PJM has reposted its report on the 2027/28 Base Residual Auction (BRA) to correct two errors related to the installed reserve margin (IRM).

Langbein said a rounding error on the pool-wide accreditation factor led to the IRM accreditation being understated at 14.4%. The report has been updated to correct that value at 14.9%. (See PJM Capacity Auction Clears at Max Price, Falls Short of Reliability Requirement.)

The report’s executive summary also did not account for price-responsive demand (PRD) when discussing the reserve margin.

PJM Presents Issue Charge on Storage Participation in Energy and Ancillary Service Markets

PJM’s Danielle Croop presented a problem statement and issue charge to expand the capability of the RTO’s energy storage resource (ESR) participation model to account for state of charge, opportunity costs and other participation rules for the energy and ancillary service markets.

Both documents note that PJM has an obligation under FERC Order 841 to incorporate state of charge in storage dispatching in 2026, a gap the RTO wrote can lead to infeasible dispatch instructions.

The problem statement argues a closer look at the ESR model is necessary due to the amount of storage under development in PJM.

“As of November 2025, PJM’s interconnection queue has over 3.5 GW of energy storage under construction, ~1.2 GW in transition cycle 1 and over 9 GW in transition cycle 2. Even if only a portion of these projects become operational, PJM can expect a significant increase in battery storage on its system. As its penetration grows, PJM needs to ensure that its market rules can effectively manage these limited-duration resources,” PJM wrote.

Croop said other RTOs have integrated large amounts of storage in their markets, creating an opportunity for PJM to review other market design elements and their success, such as how storage resources are required to submit offers and their parameters.

The issue charge lists market rules that may be part of the discussion as including “energy must-offer rules, intraday offer rules, uplift eligibility and resource parameters.” It also would open the conversation to whether hybrid resources should be included.

Croop told RTO Insider the energy market must-offer requirement for storage resources is not as cut and dried as for traditional resources. They are required to offer their full capability, measured in UCAP, into the market.

Responding to questions around peak shaving adjustments and load forecasting, Croop said the issue charge is narrowly focused on storage participation in the energy and ancillary service markets. While those are issues worth talking about, that should come with a dedicated issue charge.

Flexible Resource Issue Charge Endorsed

Stakeholders endorsed by acclamation an issue charge seeking to rework the definition of flexible resources, with the aim of reducing instances where resources committed in the day-ahead market on flexible parameters cannot be dispatched on other schedules in the real-time market. (See “1st Read on Flexible Resource Definition Clarification Issue Charge,” PJM MIC Tackles Issue Charges, Problem Statements.)

Flexible resources typically are held offline until committed by PJM or the resource owner self-schedules, with lost opportunity cost (LOC) credits paid to compensate the owner for real-time profits that were missed out on. The flexible definition pertains to resources that can start up within two hours and run for two or fewer hours, known as 2×2 parameters.

If a flexible resource changes either its start time or minimum run time to be longer than three hours, it becomes ineligible for LOC credits and cannot be evaluated by intermediate term (IT) SCED. The issue charge aims to address instances where a flexible offer is not needed, and other inflexible schedules could allow the resource to operate.

PJM’s Susan Kenney gave an example of a resource committed on a flexible schedule in the day-ahead market and which is offer capped due to a market power determination owing to a transmission constraint. If that constraint does not materialize, IT SCED would not be able to consider any of the resource’s other offers with inflexible parameters.

She said PJM has solutions in mind and expects the issue can be addressed within a few months, leading to the issue charge being brought through under the CBIR Lite pathway, which offers a more streamlined stakeholder process.

Stakeholders Endorse Quick Fix on Offline Resource LOC Eligibility

The MIC endorsed by acclamation a quick fix proposal to tighten when secondary reserves are eligible for LOC credits. The quick fix pathway allows for an issue charge to be brought concurrent with a proposed solution. (See PJM MIC Tackles Issue Charges, Problem Statements.)

The proposal addresses instances in which offline resources, which are supposed to be ineligible for LOC, are viewed as being online by settlement calculations and made eligible for credits.

PJM’s Suzanne Coyne said the issue arises due to a discrepancy between settlement and how real-time (RT) SCED determines if a resource is offline. The dispatch software considers a resource offline if it is not operating when assigned a commitment, while the settlement side focuses on whether the unit was operating at the start of that commitment. If the resource begins ramping up between the time it is dispatched and the start of its commitment, it can improperly be considered eligible for LOC credits.

If endorsed by the Markets and Reliability Committee at its Feb. 19 meeting, implementation could begin in March, Coyne said.

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Judge Again Lifts Revolution Wind Stop-work Order

A federal judge has lifted the stop-work order against one of the five offshore wind projects shut down by the Trump administration Dec. 22.

The Jan. 12 victory by Revolution Wind mirrored its September 2025 win in the same case, when the same judge lifted an earlier stop-work order issued by the Bureau of Ocean Energy Management. (See Judge Lifts BOEM’s Stop-work Order on Revolution Wind.)

The joint venture of Skyborn Renewables and Ørsted is several months from completion and is designed to send 704 MW of power at peak output to Connecticut and Rhode Island.

Later Jan. 12, Ørsted said construction would resume immediately while the court proceedings continue on the Aug. 22 and Dec. 22 stop-work orders. It said it would continue to look for an expedited and durable resolution with the Trump administration.

In both rulings, U.S. District Judge Royce Lamberth — appointed to the federal bench by former President Ronald Reagan — wrote that Revolution likely was to suffer irreparable harm if the halt remained in place.

Some of the offshore wind developers are making a similar point, framing it as an existential threat.

The move is costing the five remaining U.S. projects millions of dollars a day and jeopardizing tightly orchestrated construction timelines. The specialized installation vessels needed for the projects are booked years in advance and the operators cannot adjust their schedules.

Notably, Empire Wind said in a Jan. 6 court filing that if it cannot resume work by Jan. 16, the project faces likely termination.

Likewise, Sunrise Wind said Jan. 9 that the stop-work order constitutes an enterprise-level threat that is inflicting irreparable harm that will compound if the court does not issue a preliminary injunction by the week of Feb. 1.

The five U.S. projects are in various stages of construction. Some were only a few months from completion when the U.S. Department of the Interior issued a 90-day stop-work order Dec. 22, citing national security. Interior claims some of the reasons are classified secrets and is not making them public or sharing them with the wind developers.

The court fights are the culmination of President Donald Trump’s longstanding dislike of wind power and of the efforts by him and his administration to thwart it starting on Day 1 of his second term. (See All U.S. Offshore Wind Construction Halted and Offshore Wind Developers Fight to get Back in the Water.)

When the nascent U.S. offshore wind sector peaked in the early 2020s, more than a dozen projects were in the pipeline and President Joe Biden set a national goal of 30 GW by 2030. But the grand vision began to fade well before the 2024 presidential election, due to cost, logistical and supply chain challenges.

Since then, Trump’s stance and the risks raised by his policy changes have scared off investors. Further construction appears unlikely any time soon beyond the five existing projects, which total just 5.8 GW of nameplate capacity.

Revolution initiated its court fight Sept. 4. The attorneys general of Connecticut and Rhode Island subsequently joined in.

To submit a commentary on this topic, email forum@rtoinsider.com.

Coastal Virginia Offshore Wind (CVOW) developer Dominion Energy sought a preliminary injunction Dec. 23. It is fighting the Department of Defense’s attempts to withhold the secret reasons for the stop-work order.

Empire developer Equinor challenged the suspension Jan. 2.

Ørsted filed a complaint over Sunrise on Jan. 6 and motioned for a preliminary injunction Jan. 9.

The attorney general of New York, where power would flow from Empire and Sunrise, filed complaints for declaratory and injunctive relief Jan. 9.

All the proceedings were filed in the U.S. District Court for the District of Columbia except for CVOW, which was filed in the Eastern District of Virginia.

Avangrid and Copenhagen Infrastructure Partners have not announced a response to the suspension of Vineyard Wind 1, which is in late stages of construction and already generating power with some of its turbines.

Meanwhile, offshore wind opponents are not resting while all this continues.

ACK For Whales, a coastal Massachusetts 501(c)(3) formed to oppose offshore wind, filed its latest lawsuit Jan. 9 in U.S. District Court for the District of Columbia against Interior. It seeks to overturn regulatory approval of Vineyard Wind 1 on the grounds that it was unlawful.

The Oceantic Network cheered Revolution’s Jan. 12 court win: “The U.S. offshore wind industry has always worked closely with the federal government to ensure national security interests were prioritized in the siting and permitting of every project in federal waters. Oceantic applauds this result to get the project moving again to deliver reliable, affordable power to communities across New England that desperately need it.”

ISO-NE has said Revolution’s expected output already is part of its capacity calculations. (See ISO-NE Warns Halting Revolution Wind Boosts Reliability Risk.)

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PJM PC/TEAC Briefs: Jan. 6, 2026

Planning Committee

Stakeholders Endorse Expanded Dual Fuel Manual Definition

The Planning Committee endorsed by acclamation manual revisions to reflect FERC’s granting of a PJM proposal to expand the definition of dual fuel gas generation to include configurations where fuel is stored offsite but can be directly supplied by a dedicated pipeline (ER25-3413). (See “Reworked Dual-fuel Definition Endorsed,” PJM MRC/MC Briefs: July 23, 2025.)

The revisions to Manual 21B: PJM Rules and Procedures for Determination of Generating Capability require that dual fuel resources with off-site storage be “similarly situated and comparable to the existing classes of dual fuel gas-fired resources.”

Transmission Expansion Advisory Committee

Supplemental Projects

Dominion presented a need to replace 229 structures on four lines due to deterioration of bracing, crossarms and insulators. About 30.2 miles of steel towers and H-frames were installed in 1979 and serve 54 MW of load and 50 MW of solar capacity. The towers are along the Lanexa-Harmony Village 230-kV line and the Lanexa-Goalder’s Creek, Goalder’s Creek-Owl Trap and Owl Trap-Harmony Village 115-kV lines.

The utility presented a $35 million project to serve a 100-MW industrial load in Goochland County by constructing a 230-kV substation, named West Creek, along the Rockville-Short Pump 230-kV line. The double circuit line would be expanded by 6.5 miles to the new substation. The project is in the planning phase with a projected in-service date of July 26, 2028.

Dominion presented a $32 million project to serve a 300-MW data center in Culpeper County by constructing a 230-kV substation, named Shaw, along the Kyser-Remington line. The project is in the planning phase with a projected in-service date of May 1, 2028.

Dominion presented a $21 million project to serve a 176-MW data center in Louisa County with a new 230-kV substation, named Frances, adjacent to the Southall substation and connected by a new double circuit 230-kV line. The project is in the planning phase with a projected in-service date of Aug. 1, 2027.

A $12 million Dominion project would resolve a 300-MW load drop violation associated with the construction of the Frances substation by rebuilding 1.1 miles of the Southall-North Anna 230-kV line, which would pass through Frances, and expand North Anna with new 230-kV breakers at the line’s termination. The only alternative considered was a new 230-kV source from the Gordonsville substation 30 miles away. The project is in the planning phase with a projected in-service date of Dec. 30, 2028.

A $21 million project from Dominion would serve a 292-MW data center in Louisa County with a 230-kV new substation, named Wesbey Drive, adjacent to the Foxbrook Lane substation. It is in the planning phase with a March 1, 2029, in-service date.

FirstEnergy presented a need in the JCPL zone to address the possibility of the Manchester substation being forced offline if the Cookstown-Larrabee-Whitings 230-kV line is interrupted or there is a fault on a remote end breaker. The substation serves about 7,000 customers with 23 MW.

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FERC Approves Generator Fines for Violations of ISO-NE Offer Rules

FERC has approved an agreement resolving an investigation into alleged violations by Berkshire Power Co. of ISO-NE energy offer rules. Tenaska Power Services, the parent company of Berkshire Power at the time of the violations, has agreed to pay a $51,000 penalty to the U.S. Treasury and $78,354 plus interest in disgorgement to ISO-NE (IN25-13).

The investigation concerned reductions to the dispatch requirement of Berkshire Power’s 251-MW gas generator in January 2021. The generator had a 229-MW capacity supply obligation (CSO) at the time. FERC’s Office of Enforcement and Regulatory Accounting concluded Tenaska violated the ISO-NE tariff “by modifying the real-time offers of the Berkshire Generator based on economic factors rather than physical availability.”

Under the rules of ISO-NE’s capacity market, resources with CSOs must offer into the day-ahead and real-time energy markets an amount of power that meets or exceeds their CSOs. Resources can reduce their offer requirements only to account for physical — not economic — limits.

According to the stipulation of facts under the Jan. 12 consent agreement, the generator could have procured enough gas to operate at its 251-MW economic maximum, though it would have had to pay a higher price for the gas than it anticipated when it made its day-ahead offer for Jan. 11, 2021. Berkshire Power asked ISO-NE to reduce the maximum dispatch of the generator to 150 MW, failing to disclose that the unit did not have a physical limit.

The Office of Enforcement “determined that attempts to reduce the dispatched level of the Berkshire Generator resource falsely and misleadingly communicated to ISO-NE a physical inability to operate at the resource’s CSO,” adding that “such a reduction was not due to a physical inability to operate but rather an economic decision not to procure higher-priced fuel.”

FERC ruled that the agreement between Tenaska and the Office of Enforcement “is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations stated above and in the agreement.”