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December 7, 2025

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ISO-NE Outlines Accreditation for Active, Passive Demand Resources

ISO-NE outlined proposed capacity accreditation for active and passive demand capacity resources at the NEPOOL Reliability Committee meeting Nov. 18.

The changes are part of the second phase of the RTO’s wide-ranging Capacity Auction Reform (CAR) project, which aims to develop a seasonal capacity market and establish a marginal reliability impact (MRI) approach to accreditation that values resources based on their expected contributions to reducing energy shortfalls.

Passive Demand Capacity Resources

ISO-NE’s passive demand capacity resource category is largely composed of energy efficiency resources but also includes some distributed generation.

Under the current accreditation process, ISO-NE determines seasonal qualified capacity based on estimated performance during a “fixed set of performance hours,” which is intended to estimate resources’ “expected contribution to resource adequacy during tight system conditions,” the RTO noted in a memo issued prior to the RC meeting.

ISO-NE said the current set of performance hours “do not align well with hours when resource adequacy is at risk,” noting that the most important hours for resource adequacy change as the resource mix changes.

Transitioning to a marginal reliability impact (MRI) accreditation process will better capture passive resource contributions during projected shortfall periods, said Clara Berger, senior market development analyst at ISO-NE.

The RTO plans to evaluate resources’ MRI value based on “class-based hourly profiles for different technologies and end uses.”

Each resource’s final accreditation value would reflect the class values and maximum capabilities associated with each of its components, as passive resources often include multiple assets.

For distributed generation participating as passive demand capacity, ISO-NE plans to make resource-specific performance adjustments. These resources submit hourly data to the RTO, which will enable these adjustments.

Berger noted that the new methodology would allow the RTO to account for performance differences between classes that are not captured under the existing rules.

“This approach incentivizes the development of PDR assets and measures that provide the greatest value to system reliability,” ISO-NE said.

Active Demand Capacity Resources

ISO-NE’s proposed approach to accrediting active demand capacity resources (ADCRs) is similarly focused on capturing the resources’ ability to reduce shortfall.

Under the current rules, ISO-NE accredits active demand resources based on information submitted when the resources enter the capacity market as new resources. The RTO does not update this information in subsequent auctions to account for actual performance.

“While the existing framework for ADCR qualification does not depend on ADCRs’ demonstrated ability to reduce demand during stressed conditions, the proposed MRI framework for ADCRs will utilize both ADCRs’ offered capability and actual performance for accreditation,” ISO-NE wrote.

The RTO noted there is “a considerable amount of heterogeneity in ADCR performance,” which creates risk that the market is procuring resources that are unable to perform at their full capacity during the most important hours.

Like passive resources, the contributions of active demand resources can depend on time of day, making it important for ISO-NE to evaluate accreditation at the most important hours for system reliability, ISO-NE said.

In the new accreditation process, the RTO proposes calculating MRI values using hourly profiles based on each resource’s maximum reduction values offered over the past three years, with adjustments for the observed performance factor.

For new resources, the profile will be based on the performance of other resources in the portfolio of the lead market participant. If this data is not available, ISO-NE will base the profile on the performance of all existing active demand resources, with separate class averages for standalone resources larger than 5 MW.

Tie Benefits

Also at the RC, ISO-NE discussed how it plans to calculate tie benefits in a seasonal market.

Tie benefits are intended to quantify the reliability contributions of transmission lines connecting New England to neighboring regions. ISO-NE currently determines annual tie benefits based on summer values because the New England grid is a summer-peaking system.

The RTO noted that tie benefits associated with cross-border lines with Canada reflect “seasonal load diversity” associated with Quebec and the Maritimes’ winter peaks, which enable the provinces to reliably export power when the New England grid is stressed in the summer.

In comparison, because New York and New England have similar load profiles, New York tie benefits “are mainly the result of diversity in resource outages or availability,” ISO-NE noted.

As part of the CAR changes, ISO-NE plans to begin calculating tie benefits seasonally while maintaining the same basic modeling approach.

Under a seasonal framework, both New York and Canadian tie benefits will likely be driven by “diversity in resource outages or availability,” instead of surplus capacity, which may reduce the overall amount of tie benefits the region can expect in the winter.

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Voltus, Mission:data Argue Data Access Issues Stymie Residential DR in PJM

Voltus and Mission:data pushed back on opposition to their complaint against PJM from the RTO and others on using statistical modeling for residential demand response customers, saying the current rules have residential customers providing just 0.4% of registered DR in the market (EL26-4).

“Complainants wish to make it completely clear for the record: Voltus and Mission:data’s complaint is limited to residential customers,” they said in an answer filed Nov. 18. “Voltus and Mission:data are not proposing that statistical sampling be employed for any other class of customer, or to sample across customer classes.”

PJM argued in its response that the complaint was trying to get around state rules, which have made it hard to access interval meter data for residential customers for legitimate reasons. The RTO also said it lets DR aggregators use statistical modeling when interval metering data is not available at all for residential customers. (See PJM Asks FERC to Deny Demand Response Metering Data Complaint.)

Allowing DR aggregators to use those statistical modeling techniques when interval meter data is made unobtainable by state rules would unlock residential DR in PJM, Voltus Chief Regulatory Officer and former FERC Chair Jon Wellinghoff said in an interview Nov. 19.

“I would say there’s probably several thousand megawatts of DR that could be brought into PJM if we could access those residential customers, but this is the block,” Wellinghoff said. “We are being blocked by the fact that we don’t have reasonable access to interval meter data.”

The original complaint detailed Voltus’ efforts to procure the needed data from utilities for residential customers and how that proved difficult enough to be infeasible. It did that after FERC rejected a similar complaint from CPower on the grounds it had not filed enough information to prove data access rules were a hindrance to signing up customers for wholesale DR.

Voltus has no problem going through information security regulations to access the data where they are available, but it showed in the original complaint that many utilities across PJM make it very difficult for any third parties to get access, he added.

FERC granting the complaint could lead to states making their rules more workable, Wellinghoff said.

“It will give money in the pockets of residential consumers who are hurting from utility bills,” he added. “It will provide money to them for participating in these programs.”

Two of the biggest issues facing the industry are interconnecting large loads and affordability, which can be in tension. DR can help free up space on the grid to connect additional loads, and it can save customers from paying for extra investments to the grid, while directly giving money to participants.

“All the governors in PJM should be all over this complaint, telling FERC you should approve it immediately,” Wellinghoff said.

These kinds of DR programs for residential customers get around resistance to more economically elegant price-responsive demand, which could be a grid resource given the right price signals such as time-of-use rates, Wellinghoff said. But PRD has not proved popular among consumers, even as technology has advanced.

“It’s simply because consumers would much rather have some third party provide some service to them that can control independently their devices in ways that will help the market but also preserve the comfort in their home and provide them money in their pocket,” Wellinghoff said. “But they don’t want to do anything actively, because they’ve got other things to do.”

Having a third-party aggregator handle the optimal charging for a plug-in car or when to moderate air conditioning demand makes it easier for consumers who need to focus on their family life or jobs, he added.

The utilities with interval meters for residential customers have unfettered access to the data and could set up these programs themselves, but they lack the incentives to do so, Wellinghoff argued.

“They have no interest or incentive to have consumers go on time-of-use rates,” Wellinghoff said. “They have no interest or incentive to help customers participate in wholesale markets because they don’t make any money doing that. In fact, they lose money by doing that, because what that does is it allows consumers to help the system run more efficiently.”

That means less investment in the system, and less investment means fewer returns for shareholders, he added.

In addition to opposition from the RTO and member utilities, PJM’s Independent Market Monitor opposed the complaint on the grounds that the statistical modeling methods were by nature less accurate than the real data, which would degrade the RTO’s ability to track Capacity Performance and its ability to maintain resource adequacy.

“What the IMM also does not acknowledge is that PJM, in fact, accepts this ‘uncertainty’ and lack of precision for financial settlements today, where interval meters do not exist, as outlined in Manual 19,” Voltus said in its answer. “PJM’s statistical sampling process is designed to be rigorous and requires [that] ‘samples must be designed to achieve a maximum error of 10% at 90% confidence.’ The IMM does not explain how complainants’ proposal would introduce unacceptable certainty beyond what is established practice today.”

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Enviros Challenge MISO, SPP Queue Express Lanes

Environmental groups are further pressing their opposition to MISO‘s and SPP’s fast-track studies for primarily fossil fuel projects, challenging both in the D.C. Circuit Court of Appeals in a pair of lawsuits.

The petitions for review, filed with the court Nov. 18, contest FERC’s separate approvals of MISO’s Expedited Resource Addition Study and SPP’s Expedited Resource Adequacy Study (ERAS) processes, allowing load-responsible entities to nominate qualified projects for fast-track reviews to maintain resource adequacy.

Earthjustice filed the MISO petition on behalf of environmental groups Clean Wisconsin and Natural Resources Defense Council. It was joined in the filing by the Sierra Club.

Separately, the Sierra Club filed a petition with the court against SPP’s “unnecessary” proposal. The organization said the ERAS proposal favors gas generation at the expense of wind, solar and battery storage projects.

The filings came one day after the Sierra Club and NRDC, represented by Earthjustice, were party to a similar request to the D.C. Circuit over SPP’s accreditation methodology for clean energy resources. (See related story, SPP’s ELCC Methodology Contested at Appeals Court.)

The groups said MISO’s interconnection-queue express lanes bestow an “undue advantage” for fossil fuel generation, with ratepayers funding the grid upgrades needed to accommodate them. They asked for a reversal of FERC’s approval order.

They argued FERC incorrectly brushed aside the potential for the fast lanes to aggravate wait times and complicate studies for regularly queued resources.

“FERC is letting grid operators like MISO rewrite the rule book to the benefit of fossil fuel and data center companies, and at the expense of everyone else,” Ada Statler, a senior associate attorney at Earthjustice, said in a statement. “FERC is sidelining cheaper clean energy projects and allowing utilities to pass on the higher costs of methane gas to other customers, despite its legal mandate to ensure just and reasonable rates.”

Caroline Reiser, an NRDC senior attorney, said the fast lanes create an environment where a handful of mostly gas plants can cut in line to their financial benefit.

Sierra Club Senior Attorney Greg Wannier added that MISO is “spending too much time trying to benefit monopoly utilities and the gas industry at the expense of clean energy and independent producers.”

The Sierra Club said MISO’s process allows fast-tracked projects to “pass on significant upgrade costs to residential customers and to skip over clean energy projects that have been waiting for years to connect to the grid.” It argued that the clean energy waiting in MISO’s 175-GW interconnection queue is more affordable than the 18 GW of gas generation under study in the fast lane.

The Sierra Club and Natural Resources Defense Council objected to MISO’s design while it was pending before FERC. (See MISO Fast Lane Proposal Disadvantages IPPs, Retail Choice States, Critics Tell FERC.)

MISO has received 49 project applications representing more than 26 GW for its expedited queue. Most proposals entail natural gas-fired units. (See MISO Selects 10 Gen Proposals at 5.3 GW in 1st Expedited Queue Class.)

MISO Vice President of System Planning Aubrey Johnson said during a Nov. 11 Entergy State Regional Committee meeting that MISO believes the fast lane already has met its objectives to accelerate resource additions.

Altogether, MISO’s temporary process would enable 68 projects, with 10 slots reserved for submissions from independent power producers and eight reserved for entities serving MISO’s retail choice load in downstate Illinois and a percentage of Michigan.

Sierra Club Appeals SPP ERAS

The Sierra Club said that despite no “solid evidence” of a capacity shortage, SPP claimed its ERAS proposal was necessary to address rising capacity demands. It said SPP has a history of favoring thermal projects over renewable energy and that the ERAS process’ structure would make it virtually impossible for wind or solar facilities to participate in this new process.

The organization said the ERAS allows the fast-tracked projects to pass upgrade costs to residential customers and clean energy projects that have been waiting for years to connect to the grid. It said it previously alleged at FERC that SPP “improperly” dismissed the potential for fast track to exacerbate challenges in processing and connecting the rest of the RTO’s queued resources.

SPP spokesperson Seth Blomeley told RTO Insider that staff are reviewing the Sierra Club’s filing. “We remain confident in the merits of our plan, which was approved by FERC,” he said in an email.

The Sierra Club argues that SPP claims ERAS is necessary to meet increased demand from data centers but that SPP suggested in other regulatory contexts that other reforms to the queue would address resource shortfalls.

The Sierra Club pointed to Duke University research that found new demand for electricity from data centers and other large loads can be flexed to avoid building expensive new gas plants while maintaining electric grid reliability.

FERC approved SPP’s ERAS proposal in July. It was conditional on making a compliance filing within 30 days of the order’s issuance (ER25-2296). (See FERC Approves SPP’s ERAS Process, Accreditation.)

The Sierra Club’s rehearing request was rejected in November, “deemed to have been denied” after no FERC action was taken.

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$12B MISO 2025 Tx Portfolio Close to Final Approval

A MISO board committee advanced 432 projects from transmission owners at a cost of almost $12.3 billion under the RTO’s 2025 Transmission Expansion Plan.

The System Planning Committee voted unanimously to approve the MTEP 25 package at a Nov. 17 teleconference. The plan now moves to the full Board of Directors for consideration at its final meeting of the year on Dec. 11.

The projects, which total 1,901 miles, would support 11.6 GW of spot load additions. Louisiana contains the most investment at $3.4 billion. Wisconsin follows with $1.8 billion and Indiana with almost $1.7 billion. (See MISO 2025 Tx Expansion Estimate Drops Slightly to $12.4B.)

MISO Executive Director of Transmission Planning Laura Rauch said large loads seeking to reserve spots on the grid influenced the sizeable investment.

MTEP 25’s most expensive project — Entergy Louisiana’s $1.2 billion Cargas 500-kV and Smalling 500-230-kV stations in northeastern Louisiana — is planned to support a new $10 billion Meta data center.

Southern Louisiana’s Babel-to-Webre 500-kV line project is the second-most expensive MTEP 25 project at $1.066 billion. Entergy Louisiana said it’s needed to meet NERC reliability criteria.

The Missouri Multi-Entity New Transmission (MoMENT) project, a $604 million joint venture between Ameren, Evergy, MISO, SPP and Associated Electric Cooperative, is the third-most expensive. The 345-kV and 161-kV lines and substation in central Missouri are meant to improve reliability and be in service by December 2030.

Rauch told board members that MISO emphasized the collaboration behind the MoMENT project in its MTEP 25 report.

MISO’s Jeremiah Doner said load growth, AI data centers and economic development — all the “hot button issues” — influenced MTEP 25.

“The common theme this year is around those large load additions,” Doner said during a Nov. 3 gathering of the Planning Advisory Committee (PAC).

PAC’s 11 membership sectors voted in early November to approve MTEP 25. Six sectors voted in favor of the portfolio, two abstained from voting and three sectors didn’t respond to the emailed ballot.

MISO’s state regulatory sector typically abstains from voting on MTEP portfolios, reasoning that it’s improper for state commissioners to preemptively judge the projects that will come before them later for separate approvals.

MTEP 25 still contains a $92 million maintenance project for a 345-kV line that was part of MISO’s 2011 Multi-Value Project portfolio. Xcel Energy will replace cracking davit arms on a multi-value project in Minnesota. Any maintenance on multi-value projects must be classified under the multi-value category.

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FERC Gives Go-ahead on Tougher MISO DR Testing Rules

FERC has greenlit MISO’s plan to require its demand response to make real-world demand reductions to fulfill the RTO’s testing requirements.

FERC said the “modifications more clearly define and standardize the existing testing procedures” in a Nov. 17 order (ER25-2845).

MISO now can mandate DR to make actual megawatt reductions for testing instead of submitting mock tests to prove capability. MISO worked on the proposal over 2025. (See MISO Tries to Ward Off DR Fraud with New Testing Regime.)

“[W]e find that establishing stricter testing waiver criteria and adding specific testing parameters for demand resources in the tariff will provide greater certainty that demand resources will be available when called on by MISO,” FERC said, adding that the rules should diminish the “likelihood of market participants registering resources into the auction in a manner that does not accurately reflect the true capability of their resources.”

The commission granted MISO’s requested effective date of July 15, 2025, so the new testing regime is in place by the 2026/27 capacity auction. It said it weighed the quick turnaround time against the importance of accurate testing. It pointed out that MISO allows market participants to use “operational data gathered in the ordinary course of business” to prove full demand reduction or allows resource owners to defer testing until May 29, 2026.

MISO has about 15 GW of DR as of late 2025. But MISO has said its experience shows that only about half of the DR fleet is available when needed.

Under the new MISO paradigm, DR resource owners must demonstrate they can honor their notification time while dropping demand within the time-of-day periods that match with hours that MISO expects system risk to occur. The resources must hold their demand reduction for 15 minutes, covering at least two meter intervals. Owners must show a full reduction of all the megawatts they specified in registration during a real power test. MISO said it would allow some resources that experience a weather impact during testing to demonstrate a bit less than their full stated capability.

MISO will allow select DR owners to proceed with a mock test if a state authority expressly allows it or if it’s a proven resource that has responded to a call in the past three years and has not changed its specifications since.

DR and distributed energy resource aggregators argued before FERC that MISO’s plan allows discriminatory treatment between load-serving entities’ DR programs and aggregators of retail customers.

Voltus and Advanced Energy United said MISO’s testing waivers for load-serving entities’ DR programs amounted to aggregators’ DR groupings being held to a different standard. The RTO included testing waivers for retail DR programs overseen by state regulatory authorities. It didn’t extend the possibility of waivers to aggregators.

FERC said the testing exceptions aren’t discriminatory and recognize “states’ interest and expertise in ensuring that the demand response programs under their jurisdiction are effective.” The commission further pointed out that MISO’s tariff already contains the potential for testing exemptions for retail programs managed by state regulators. It said it was “reasonable for MISO’s testing requirements to account for relevant testing provisions in retail programs.”

The testing rules are part of a myriad of new restrictions MISO has placed on its DR since the RTO, its Independent Market Monitor and FERC staff discovered multiple instances of fraud, misrepresentation or rule violations among its DR fleet. (See MISO Tries to Clear Up Assortment of New DR Rules.)

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DOE Issues 3rd Emergency Order to Keep Michigan Coal Plant Open

The U.S. Department of Energy has reupped a coal-fired power plant in West Olive, Mich., for another 90-day period, preventing its planned retirement for a third time.

DOE issued another emergency order to MISO and by extension, plant owner Consumers Energy, to keep the 1,420-MW J.H. Campbell plant running from Nov. 19, 2025, to Feb. 17, 2026.

U.S. Secretary of Energy Chris Wright once again said that an “emergency exists in portions of the Midwest region …  due to a shortage of electric energy, a shortage of facilities for the generation of electricity and other causes.” He directed MISO and Consumers Energy to take “all measures necessary to ensure that the Campbell Plant is available to operate” and told MISO to write DOE by Dec. 3 to describe its efforts to keep Campbell running.

Consumers Energy originally planned to wind down operations at the plant in late May 2025, but DOE delivered its first emergency order on the eve of its retirement date. A second order in August followed on the heels of the first. The newest order brings prolonged operations to 270 days past the plant’s planned retirement date.

DOE framed its order as strengthening Midwestern grid reliability as MISO enters winter weather. The department also argued that Campbell would have retired “15 years before the end of its scheduled design life” if it were allowed to power down.

As of the end of September, the plant’s extended operations cost about $80 million, according to Consumers Energy’s financial disclosures. (See J.H. Campbell Bill Rises to $80M on DOE’s Stay Open Orders.)

The Environmental Defense Fund and Earthjustice continued to call the series of orders illegal and vowed to keep fighting them in the courts.

“Consumers Energy committed to retire the plant in 2022 under a settlement approved by Michigan state regulators, finding that replacing the plant with a variety of cleaner resources — including wind, solar and storage — would reduce costs for Michigan customers. DOE’s series of emergency orders ignore those decisions and are now putting consumers across the Midwest on the hook to keep this aging, expensive and highly polluting plant online,” EDF lead counsel Ted Kelly said in a statement.

Kelly said keeping the plant open is a “guaranteed way to needlessly” raise customer bills and worsen air pollution and pointed out the plant has “burned through over $600,000 in losses every day.”

DOE claimed that Campbell has been “critical” to MISO operations during its deferred retirement. It said it operates “regularly” during high demand and low renewable energy output.

But EDF said the plant suffered a partial breakdown in June, and Campbell Units 1 and 2 were completely offline when demand peaked during the month. What’s more, the nonprofit said NERC’s annual winter reliability assessment, released Nov. 18, concludes MISO is resource adequate “even in situations with extreme levels of demand and generator outages.”

Michael Lenoff, Earthjustice senior attorney, called the plant a “jalopy” that’s “prone to breaking down.”

During a third-quarter earnings call at the end of October, Consumers Energy CEO Garrick Rochow said he expects the emergency orders to continue in the long term and Consumers to comply with them.

Rochow said the utility has “a very flexible workforce that is committed … [to] following through with this order through the Department of Energy.”

Rochow said Consumers agrees with FERC that costs of the plant should be allocated across MISO Midwest. He said the region benefits from the continued operation of the plant, not just Consumers ratepayers. Consumers has “great confidence in our ability to recover” costs and will “continue to invest in the plant thoughtfully,” Rochow said.

Rejji Hayes, CFO of Consumers parent CMS Energy Corp., said Consumers is treating all costs associated with Campbell’s extensions as a regulatory asset. He said so far, there has been “minimal” capital investment. Hayes said once Consumers starts receiving cost recovery from MISO Midwest customers, the company would refund Michigan customers.

“We’re trying our best to make sure that Michigan customers are held harmless as we continue to operate the plant to the benefit of the region as noted,” Hayes said during the earnings call.

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Nonprofit Groups Sue N.Y. and N.J. over Pipeline Approval

A group of environmental, energy and water safety nonprofits have sued New York and New Jersey over their recent permits for the Northeast Supply Enhancement pipeline project that reversed multiple prior denials by state environmental authorities.

The New York Department of Environmental Conservation and the New Jersey Department of Environmental Protection, both of which approved the project Nov. 7, were sued Nov. 18. (See Permits for Trump-Favored Gas Pipeline Approved by N.Y. and N.J.)

“DEC’s approval is a 180-degree reversal; in 2020 it denied the exact same application,” Susan Kraham, managing attorney for Earthjustice’s northeast region, said in a press release. “The project hasn’t changed; the impacts haven’t changed; the only thing that has changed is DEC’s decision, which it reversed with no reasonable explanation,”

The NESE project would expand the capacity of Williams Cos.’ existing Transco Pipeline, including building 23 miles of new pipe along sections in Pennsylvania, New Jersey and New York City. The majority of that is designed to go underwater through Raritan Bay to New York Harbor. The plaintiffs say that constructing the pipeline and associated compressor station would violate state air and water quality standards, release mercury and chemicals into the water, and destroy local shellfish habitat.

“The Sierra Club was shocked and disappointed to see New Jersey and New York move ahead with Williams Transco’s dirty and harmful NESE project,” Anjuli Ramos-Busot, director of the Sierra Club’s New Jersey chapter, said in a press release. “We will not stop fighting this project.”

President Donald Trump moved to stop construction on Empire Wind 1 but reversed course after claiming to reach a deal with Gov. Kathy Hochul in May. The White House claimed Hochul “caved” on natural gas, while the governor’s office denied any deal was reached. (See BOEM Lifts Stop-work Order on Empire Wind.)

The plaintiffs include NY/NJ Baykeeper, Protectors of Pine Woods, Food and Water Watch, the New Jersey Safe Energy Coalition, the Surfrider Foundation, the Sierra Club and a group representing local homeowners. They are represented by the Eastern Environmental Law Center, Earthjustice and the Natural Resources Defense Council.

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FERC Greenlights LS Power to Sell CPower, 12.9 GW to NRG

FERC has approved LS Power’s deal to sell 12.9 GW of its gas generation in PJM, NYISO and ISO-NE, as well as its 6-GW demand response business, CPower, to NRG Energy for $12 billion (EC25-102).

The transaction, approved Nov. 14, was opposed by PJM’s Independent Market Monitor, as well as the New Jersey Division of Rate Counsel and Maryland Office of People’s Counsel, which argued it would harm competition and lacked safeguards against market power manipulation.

The Monitor urged the commission to condition its approval on requirements around how NRG could structure its cost- and price-based offers, subject them to the requirement that they offer into the day-ahead and real-time energy markets, base the DR strike price on the cost of dispatch and commit to not removing the generators’ capacity status to serve co-located load. (See NRG, PJM IMM Disagree on LS Power Deal’s Market Power Impact.)

NRG submitted analysis on how the deal would affect prices and ownership concentration, finding that the Herfindahl-Hirschman Index (HHI) for the New York City local capacity market is moderately concentrated and would increase from 1,085 points to 1,122 for the 2026 summer auction and go up from 1,157 to 1,214 in the 2026 winter auction. It determined the PJM capacity market is unconcentrated, with an HHI that would increase from 563 points to 565 across the RTO and would decrease within the MAAC zone from 851 to 840. They argued the increases in NYISO are small and below the commission’s threshold for rejecting a transaction and that the units in New York City would be considered pivotal and therefore subject to mitigation rules.

Commission staff issued a deficiency letter Aug. 13, requesting that the companies file more information about whether the DR resources were included in the horizontal market screens for PJM and NYISO. The companies responded with additional sensitivities showing there would be a “trivial impact” in the city and that the sensitivities for PJM and MAAC likewise found little impact.

The Monitor argued that the three-pivotal-supplier test would more accurately represent the impact to market power than the HHI, particularly given how tight PJM’s capacity market is.

“Regarding the PJM IMM’s arguments that the proposed transaction will increase market power in PJM, we find that the PJM IMM has not demonstrated that the proposed transaction will have an adverse effect on horizontal competition,” FERC wrote. “Although intervenors may submit alternative competitive analyses, accompanied by appropriate data, to support their arguments, the commission historically has not relied on three-pivotal-supplier test results or hourly market share analysis for its analysis of [Federal Power Act] Section 203 transactions, and we decline to do so here. Neither the three-pivotal-supplier test results nor hourly market share analysis cast doubt on the results of applicants’ [delivered price test], which indicates that the proposed transaction does not increase market concentration in any relevant market.”

During NRG’s third-quarter earnings call, CEO Larry Coben said the company expects the deal to close in the first quarter of 2026. It includes $6.4 billion in cash and NRG purchasing about 11% of LS Power’s shares, though it will directly receive less than a 10% holding to avoid the commission’s threshold for determining when a party holds functional control. The remainder will be transferred to an independent trust.

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NERC Winter Reliability Assessment Finds Many Regions Facing Elevated Risk

Rising electricity demand has outpaced winter capacity growth over the past year, leaving many North American regions at elevated risk for outages if they face extreme weather this winter, NERC reported in its newly released Winter Reliability Assessment.

Demand in areas covered by the report has grown by 20 GW since last winter, but corresponding grids have added just 9.4 GW of new supplies to meet the higher consumption, the report said.

“The bulk power system is entering another winter with pockets of elevated risk, and the drivers are becoming more structural than seasonal,” NERC Director of Reliability Assessments John Moura said during a Nov. 18 webinar on the report. “We’re seeing steady demand growth faster than previous years, landing on a system that’s still racing to build new resources, navigating supply chain constraints, and integrating large amounts of variable and integrated inverter-based generation.

“We also added the continued threat of extreme cold weather, which has changed over the years, and the margin for error narrows quickly,” he said.

The assessment finds highest risk of outages during extreme weather in the WECC Northwest and Basin regions; ERCOT; SERC Reliability’s Central and East regions; and the Northeast Power Coordinating Council’s New England and Canada Maritime Provinces regions.

While the past two winters have seen noticeable improvements in the delivery of natural gas to bulk power system generators, gas availability remains precarious during extreme cold due to the uneven application of voluntary freeze protection mitigation, NERC found.

“Gas production and supplies going to generators really do strongly affect how well the bulk power system can perform during winter conditions,” NERC Manager of Reliability Assessments Mark Olson said during the webinar. “These two systems are inextricably linked.”

New England stands alone in the report as facing “risk to natural gas pipeline capacity.” The region’s demand forecast for this winter is 2.9% lower than the previous winter’s demand, and firm imports and demand response can make up for retired power plants, the study said.

“New England continues to closely monitor regional energy adequacy, particularly during extended cold snaps where constrained natural gas pipelines contribute to rapid depletion of stored fuel supplies,” the report said. “ISO-NE’s deterministic winter scenario analysis shows limited exposure to energy shortfalls this winter. In New England, winter energy concerns are highest in scenarios when stored fuels are rapidly depleted; during these periods, timely replenishment is critical to minimizing the potential for energy shortfalls.”

‘Pragmatic, Proven Tools’

New England has for decades faced the issue of energy shortfalls during winter, and the idea of building new natural gas pipelines there has gained traction. (See Pipeline Expansion Highlights Key Questions About Gas in New England.)

“Expanding the gas infrastructure into a constrained area like the Northeast would help as you get to these low-temperature periods where gas-fired generation is competing with other users of the gas system; the gas infrastructure would better postured to be able to support the uses,” Olson said. “So basically, for electric reliability, we would expect fewer generator curtailments due to fuel issues, if we can expand that capacity, which can provide reliability benefits.”

That would mean fewer generator outages and less reliance on backup fuels, allowing the region to be more resilient during extended cold snaps, he added.

NARUC recently released its Gas-Electric Alignment for Reliability report, which recommended construction of more pipelines to improve electric reliability. (See NARUC Report Seeks to Make Headway on Gas-electric Coordination.)

Moura said “the preponderance of material that’s being presented to decision-makers around gas-electric” points in the same direction: “That alignment between gas and electric are critical, these are interconnected systems, and there needs to be some changes in the future.”

The power industry continues to build new natural gas plants, but they are not always paired with new pipelines, or contracts with firm service able to ensure delivery during the coldest days of the year, he added.

“The findings around aligning the markets, being able to put in more resilience through more infrastructure, are all lining up with what we need to have a reliable and resilient system in the future,” Moura said.

The National Petroleum Council plans to publish another report on gas-electric coordination in early December that will include recommendations to shore up the reliability of both systems, Moura said.

Electric Power Supply Association CEO Todd Snitchler said his group’s members are investing in the resources needed to maintain reliability, including gas-fired plants and batteries. Evolving demand forecasts increase uncertainty, but competitive markets can shield customers from risk, he said.

“Policymakers should avoid extreme rhetoric or drastic interventions driven by outlier projections and instead focus on pragmatic, proven tools that support reliability and encourage cost discipline,” Snitchler said. “Competitive markets remain the most effective mechanism to deliver reliable, innovative and cost-effective energy. With targeted reforms — and continued private investment — we can better ensure the dependable, affordable power system Americans expect this winter and for years to come.”

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NERC Standards Committee Rejects Nuclear Reporting Carve-out

In a relatively light monthly conference call Nov. 18, NERC’s Standards Committee unanimously agreed to reject a standard authorization request that would have exempted nuclear generators from the reporting requirements of reliability standard EOP-004-4 (Event reporting).

The Nuclear Energy Institute (NEI) proposed the SAR in March, with the goal of making EOP-004-4 consistent with recent changes to the Department of Energy’s DOE-417 form, used by generator owners, generator operators, balancing authorities and reliability coordinators to report electric emergency events and disturbances.

Reportable events include many cyber and physical security events, islanding, system-wide voltage reductions of 3% or more and complete operational failure or shutdown of the transmission or distribution system.

Similarly, EOP-004-4 requires GOs, GOPs, BAs, RCs and other registered entities to report certain events to the ERO, including damage to or destruction of a facility, physical threats to a facility or control center, generation and transmission loss, and complete loss of off-site power to a nuclear generating plant. Entities may use either DOE-417 or the form attached to the standard to report incidents.

Earlier in 2025, DOE-417 was updated to exempt operators of commercial nuclear plants regulated by the Nuclear Regulatory Commission (NRC) from reporting requirements. NEI’s SAR (page 15 of the agenda) proposed revising EOP-004-4 to provide a similar exemption, similar to that found in CIP-008-6 (Cybersecurity — incident reporting and response planning). That standard excuses cyber assets at facilities regulated by the NRC and its Canadian equivalent from reporting cybersecurity incidents to NERC.

However, NERC staff was “very concerned” about the proposal, NERC Manager of Standards Development Sandhya Madan told SC members, because it would eliminate “NERC’s only mandatory source of physical event incident reports for nuclear power plants.” She also said the reporting requirement is not duplicative, contrary to another of NEI’s arguments, because NERC does not have another route for such information.

Jennie Wike, compliance lead at Tacoma Public Utilities, pressed Madan on this point, asking whether keeping the reporting requirement for EOP-004-4 would run afoul of the Trump administration’s push to “eliminate duplicate requirements across government agencies.” In response, Madan repeated that while the NRC might consider the requirement in DOE-417 to be duplicative because the NRC already receives such reports, NERC does not have any other avenue for GOs and GOPs to submit the information.

Paul MacDonald, director of reliability standards, compliance and enforcement for the New Brunswick Energy and Utilities Board, reminded attendees that the standard also applies to Canadian utilities that are not subject to the NRC. He said the information was “important … for NERC to analyze” the behavior of nuclear plants during grid events.

Despite her earlier questions, Wike made the motion to accept NERC staff’s recommendation and reject the SAR. In accordance with NERC’s Rules of Procedure, the SC must provide a rationale for the rejection to NEI within the next 10 days, which Chair Todd Bennett volunteered to do.

INSM Standard Posting Approved

The SC agreed to authorize the posting of proposed standard CIP-015-2 (Cybersecurity — internal network security monitoring [INSM]) (Page 23 of the agenda) for an initial 45 calendar day formal comment and ballot period. Ballot pools will be formed in the first 30 days, and ballots will be conducted in the last 10 calendar days of the period.

The standard was developed under Project 2025-02 (Internal network security monitoring standard revision), in accordance with FERC’s June 26 order to modify the new INSM standard CIP-015-1 by extending its reach. (See FERC Approves NERC’s Proposed INSM Standard.) FERC directed NERC to file, within the next 12 months, a new standard that extends INSM implementation to electronic access control or monitoring systems, along with physical access control systems, outside a utility’s electronic security perimeter — the electronic border around its internal network.

Presenting the draft standard, NERC Manager of Standards Development Alison Oswald said the standard drafting team “has worked very quickly” to respond to FERC’s directive, and that “initial feedback … on this proposed draft has been very positive.” This motion passed unanimously.

New Members Elected

Finally, Standards Developer Dominique Love presented the results of the elections for new SC members that concluded Nov. 3. Seven members have been confirmed to begin two-year terms beginning Jan. 1, 2026:

    • Segment 1: Brandon Weese, NERC compliance manager at American Electric Power
    • Segment 2: Jamie Johnson, infrastructure compliance manager at CAISO
    • Segment 3: Claudine Fritz, senior manager for the principal compliance program at Exelon
    • Segment 4: William Pezalla, vice president for regulatory affairs at Old Dominion Electric Cooperative
    • Segment 5: Terri Pyle, head of utility operational compliance and NERC compliance at Oklahoma Gas and Electric
    • Segment 9: Paul MacDonald

No nominee for the two-year term in Segment 8, or the special election for a one-year term in Segment 5, received a simple majority, so NERC will conduct a runoff election for both seats in early December, Love said. In addition, the nominee for Segment 7 withdrew, so another nomination period is required.

Segment 10, representing regional entities, has an alternate election procedure. NERC will announce the nominee at a later date.