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December 13, 2025

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FERC Accepts NYISO’s Firm Fuel Tariff Revisions

FERC has approved NYISO’s tariff revisions that change the mechanism by which generators opt in to the “firm fuel” capacity accreditation resource class, enable modeling improvements related to natural gas constraints and update the bidding requirements for capacity suppliers (ER25-2245, ER25-2257). 

The proposal was the subject of months of discussions between NYISO, stakeholders and the Market Monitoring Unit. (See Firm Fuel Proposal Continues to Confuse NYISO Stakeholders.) The Board of Directors approved the revisions in May. 

The revisions, effective July 16, are aimed at shoring up winter fuel as the New York grid transitions into a winter-peaking system. The ISO and the New York State Reliability Council are concerned the downstate gas turbine fleet will find itself competing with home heating for fuel during peak periods. 

Suppliers will have until Aug. 1 each capability year to opt into the firm fuel capacity accreditation resource class. For the first capability year under the new paradigm, 2026/27, NYISO requested — and FERC approved — a slightly later deadline of Nov. 1 for generators to elect as firm to give market participants time to adjust to the changes. 

Generators opting firm must have fuel supply, transportation and replenishment strategies in place by Dec. 1 of the capability year through the end of February. They must be able to run for 56 hours over seven consecutive days during the winter period.  

If a generator is unable to secure firm fuel supplies or if something has gone wrong with the fuel supplier, it is required to notify NYISO. Doing so essentially compensates that generator as if it opted as non-firm. Failure to notify NYISO could result in audit and financial sanctions. 

Failure to perform as required could result in audit and financial sanction if the failure was found to be within the plant management’s control. 

NYISO’s tariff revisions were supported by the Independent Power Producers of New York and Ravenswood Operations. They told FERC that proposal will produce “efficient outcomes that reflect the marginal reliability value of conventional generators” and better address winter reliability risks. 

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FERC Faces Challenge in Balancing Executive Order and Legal Requirements

FERC is working to comply with an executive order from President Donald Trump requiring a review of all regulations it’s issued under its major governing statutes. The commission’s former general counsel warned it could be a boondoggle if handled incorrectly.

The order directs FERC and other energy agencies to include sunset provisions in its regulations, to the extent permitted by law. That would require FERC to re-examine them periodically or allow them to lapse, said Matt Christiansen, who was general counsel at FERC during the Biden administration and now is a partner at Wilson Sonsini Goodrich & Rosati.

“The CFR [Code of Federal Regulations] that pertains to FERC is like three or four inches thick,” Christiansen said in an interview with RTO Insider. “It’s at least 1,000 pages. So, we’re talking about a lot of regulations that are potentially subject to this order. That means FERC staff has to spend a huge amount of time determining what would stay, what would go, what would happen to the industry and what would need to follow on if certain regulations are removed.”

That includes fundamental rules that regulate the power industry such as allowing wholesale transactions using market-based rates.

“If the market-based regulations just disappear, it’s not clear what would fill that vacuum and what would happen to regulated entities,” he said.

The U.S. Code is more than 60,000 pages and “unelected agency officials” wrote most of the legally binding rules, which often stretch the statutory provisions beyond what Congress enacted, said the executive order called “Zero-Based Regulatory Budgeting to Unleash American Energy.”

“In particular, the previous administration added more pages to the Federal Register than any other in history, with the result that the Code of Federal Regulations now approaches a staggering 200,000 pages,” the order said. “These regulations linger in such volume that serious reexamination seldom occurs. This regime of governance-by-regulator has imposed particularly severe costs on energy production, where innovation is critical. The net result is an energy landscape perpetually trapped in the 1970s.”

Another big challenge to implementing the order is the Administrative Procedure Act (APA), which under Supreme Court precedent requires agencies to use the same procedures to amend a regulation that they used to enact it, said Christiansen.

“FERC uses notice-and-comment rulemaking to amend the CFR, which entails an opportunity to be heard on every aspect of every provision that’s added or removed from the CFR,” he added. “Then FERC, as part of its reasoned decision-making obligations under the Administrative Procedure Act, owes a non-arbitrary, non-capricious response to all those comments, which is a huge amount of work. I don’t think you can just insert a sunset clause and stop enforcing those provisions or [remove] them altogether.”

That’s potentially a huge task for an agency that has lost staff and is dealing with a federal hiring freeze. Christiansen said FERC already was understaffed, compared to its growing responsibilities, under the Biden administration.

“I think adding such a big task as the EO at least seems to contemplate on its face would be really taxing on staff and could complicate FERC efforts to do some of its bread-and-butter statutory requirements,” Christiansen said.

Christiansen said that there are regulations that could be streamlined, but FERC needs to get the process correct so it doesn’t lead to extended litigation. Chair Mark Christie said the same thing in his press conference following the April open meeting just after the order was released.

“I think the idea of a regulatory house cleaning where you look at all your regulations is a very, very good idea,” Christie said. “We’re already in the process of looking at — for example, we’re starting with regulations that were proposed that never got a final vote. They’re sort of like zombie proposals that somebody at one time thought was a good idea. They got them out as a NOPR [Notice of Proposed Rulemaking], but they just sort of have been there for years.”

Christie was describing proposals that never advance to a final rule because of leadership changes or changing priorities of the chair. But when it comes to rules that actually are finalized, the APA needs to be followed.

“You’ve got to follow it. And whatever we do, I want it to be effective. And I want it to stand up in court, because losing in court is not something I like to do,” Christie said in April. “I want to win in court.”

E&E News by POLITICO published a story on the executive order and got hold of a document circulating among commissioners that offers a potential response. However, FERC votes publicly and, especially with a looming leadership change at the agency with a new chair awaiting confirmation, much could change by the White House order’s deadline of Sept. 30.

Executive orders can have short shelf lives depending on who wins the next election. If this one were to stay in place, it would require regular reviews of major FERC rules such as Order 888, which set up the open access transmission rules, and other foundational orders. Those rules have helped to establish the entire market-based regulatory structure that governs most of the power industry.

“There might be pockets of the industry that are OK with big changes, but I think on the whole the industry would prefer stability rather than the upheaval that I think this rule at least contemplates,” Christiansen said. There are strategies that FERC, if so inclined, “could employ to mitigate some of that uncertainty.”

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Calif. Electric Reliability Outlook Strong, CEC Report Says

California should have plenty of electricity available to meet demand over the next few years, even during extreme weather events or if new energy resource installations are delayed, the California Energy Commission (CEC) said in a new report.

The positive outlook is a change in flavor after difficulties over the past decade with rolling blackouts, emergency flex alerts, public safety power shutoffs and capacity shortages.

Now, the Golden State is expected to have more than 4,000 MW of surplus capacity this summer under normal conditions, while under an extreme shortage scenario, more than 700 MW of surplus will be available, the California Energy Resource and Reliability Outlook 2025 report says.

In 2024, California set “another record year for resource development — adding more than 6,800 MW of new capacity,” the report says. More of these new resources started operating before the summer season compared with the prior four years, with more than 49% of the added capacity in 2024 operating before the start of summer, which “contributed greatly to supporting grid reliability during the heat waves in July and September” of 2024, the report says.

Much of the credit for the optimistic reliability outlook also goes to eight new transmission projects, including the TransWest Express project, the Greenlink project, the Gateway South and West projects and the Southwest Intertie project. Some of these projects are operating, while others are close to operation or under construction.

Tariff and Import Uncertainties

One reliability unknown going forward, however, is the effect the Trump administration’s recent tariffs could have on electricity infrastructure equipment. The CEC warned new tariffs could have a major impact on electricity resources, such as circuit breakers, transformers, solar panels and battery storage systems. Tariffs on equipment might “significantly reshape market dynamics across the energy sector,” the report says.

“For utilities and renewable energy developers, tariffs can delay project timelines, create uncertainty and increase installation costs, potentially delaying completion dates,” the report says. “The impact varies widely depending on domestic manufacturing capacity — areas with robust local production might see minimal disruptions, while sectors reliant on specialized imported components could experience substantial price increases and supply shortages.”

Over the past two years, California also has become less reliant on imported power. In 2023 and 2024, CAISO requested less imported electricity than in 2021 and 2022 due to the installation of new energy resources — mostly battery storage facilities — in the state.

But even so, California continues to be a net importer of power: It pulls about 29% of its electricity from outside the state, particularly in the evening when electricity demand is highest.

Import availability also is decreasing for California due to tightening supply West-wide, the report says. CAISO has a total import limit of 11,665 MW and 5,500 MW during resource adequacy risk hours.

Beyond 2030, California’s grid can be “quite sensitive to a reduction in the resource build or a reduction in import availability,” according to the report. Even if the state adds all of its planned new resources between 2025 and 2035, the grid nonetheless will remain dependent on its neighbors for resource adequacy, the report says.

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MISO Tries to Ward Off DR Fraud with New Testing Regime

MISO has filed with FERC to impose more exacting testing requirements on its demand response resources in an effort to stop fraud in its capacity market.  

The filing seeks to eradicate a standard option for DR owners to submit mock, hypothetical testing of their capabilities instead of demonstrating actual reductions through real power tests. Under the new paradigm, DR owners can proceed with a mock test only if a state authority expressly allows it or if it’s a proven resource that has responded to a MISO call in the past three years and hasn’t changed its specifications. (See Amid Fraud, MISO Plans Stricter Testing of Demand Response.)  

MISO asked for a July 15 effective date in its July 14 filing (ER25-2845). It said making real power tests the norm is necessary to “address instances of fraudulent registration facilitated, in part, by use of the testing waiver currently in the tariff to register resources from which no demand reduction is possible.” MISO plans the testing requirements to be in full force by the 2027/28 planning year.   

The grid operator said it needs confidence that the demand reduction capability that clears in its seasonal capacity auctions corresponds to resource performance in real time. MISO said the stepped-up testing standards should result in improved grid reliability, with “MISO operators having greater confidence in the ability of registered resources to perform when called upon during emergencies.”  

If the rules go through, demand response resource owners must demonstrate they can honor their notification time while dropping demand within the same time-of-day periods that correspond to hours that MISO expects system risk to occur and has picked out ahead of time. The resources must hold their demand reduction for 15 minutes, covering at least two-meter intervals.  

MISO proposed that demand response 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 show a little less than their full stated capability.  

“The test is not a panacea. It is a bare minimum requirement to show us you can drop,” MISO’s Joshua Schabla said at a July 9 Resource Adequacy Subcommittee meeting. “We don’t want the test to barrier to entry. We just want the test to validate that you can do what you say you can do.”  

MISO Independent Market Monitor Carrie Milton said MISO’s new testing requirements are likely to weed out demand response forgeries.  

Milton also said she and monitoring staff continue to review past conduct of demand response and load-modifying resources in MISO. She said there’s likely more instances of manipulation and emphasized IMM David Patton’s past contention that a yet-unconstructed data center was able to clear capacity in MISO’s 2024 capacity auction.  

“If you’re just an empty field, you really can’t conduct a test,” Milton said at the July 10 MISO Market Subcommittee meeting.  

Since 2024, MISO has planned five total FERC filings in response to recent instances of demand response gaming the RTO’s capacity market or coming up short when called upon.  

The RTO already has made three filings: one to introduce a new availability-based capacity accreditation for demand response; another to stop emergency demand response from also registering as an load-modifying resource (LMR) or demand response resource; and another to crack down on bad actors by forbidding demand response owners from double-counting participants, making fraudulent registrations or deliberately inflating their baseline electricity use to exaggerate reductions.  

In addition to the testing clampdown, MISO said a fifth and final filing will put new non-performance penalties in place and allow market participants to replace their LMR capacity after clearing the MISO capacity auction if the resource is rendered unable to respond during a planning year.  

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PJM PC/TEAC Briefs: July 8, 2025

Planning Committee

Stakeholders Endorse POI Jurisdiction Changes

The Planning Committee endorsed by acclamation a PJM proposal to rework how it determines the jurisdiction a resource point of interconnection (POI) falls under in an effort to designate more low-voltage facilities as being under state jurisdiction. (See PJM Proposes Changes to Determination of Jurisdiction over Generation.)

The proposal would establish a “bright-line test” where resources interconnecting to facilities below 69 kV would be designated state jurisdictional and required to obtain a wholesale market participation agreement (WMPA). Higher-voltage POIs would be required to receive a generation interconnection agreement (GIA). There also would be a backstop mechanism where jurisdiction could be assigned regardless of voltage depending on how the transmission owner, FERC or relevant electric retail regulatory authority has defined the cost-recovery method.

The current first-use paradigm designates the first resources interconnecting to a distribution facility to participate in PJM’s markets as state jurisdictional and all subsequent interconnections as falling under federal jurisdiction. If the proposal had been implemented when the WMPA pathway was first established, PJM Associate General Counsel Thomas DeVita said about 12 to 15% of projects that received an interconnection service agreement (ISA) or GIA would have gotten a WMPA instead.

During the June 3 first read on the proposal, DeVita said the aim of the proposal is to focus the GIA process on more complicated applications to high-voltage facilities which take a greater number of staff hours to study, while continuing to have visibility into distribution-level interconnections.

PJM Vice President of Planning Jason Connell said system impact studies for a generator pursuing a WMPA are completed by electric distribution companies rather than the RTO and produce a simpler agreement for it to process.

1st Read on ELCC Manual Revisions

PJM’s Josh Bruno presented a first read on revisions to PJM Manual 21B: PJM Rules and Procedures for Determination of Generating Capability to codify FERC’s approval of a proposal the RTO filed to establish two new resource classes for accreditation under the effective load-carrying capability (ELCC) process (ER25-1813). (See PJM Stakeholders Endorse Proposals to Rework ELCC Accreditation.)

The changes add the oil-fired combustion turbine and waste-to-energy steam classes as discrete categories for resource accreditation, starting with the 2027/28 Base Residual Auction. Oil generation was included in the miscellaneous “other unlimited resource” category, while waste-to-energy was modeled under “steam” generation.

Following the March 19 Markets and Reliability Committee meeting, Bruno told RTO Insider that breaking oil combustion turbines out as a separate class allows PJM to better capture the types of correlated outages that tend to affect them and provides the ELCC modeling with more performance data than if each unit was looked at individually.

PJM Recommends Sunsetting Relay Testing Subcommittee

PJM’s Stan Sliwa presented a first read on revisions to the Relay Subcommittee (RS) charter to sunset the Relay Testing Subcommittee and include its activities in the RS. The proposed language also would clarify who is able to participate in the RS, which is limited to members who have signed the Operating Agreement and are transmission or generation owners in PJM.

Transmission Expansion Advisory Committee

Update on 2025 RTEP Window 1

PJM has published an addendum to the problem statement and study files for its 2025 Regional Transmission Expansion Plan Window 1, which opened for developers to submit solution proposals on June 18 with an Aug. 18 deadline.

An additional scenario was added to the 2032 base case modeling the expected bulk transfer if offshore wind developments in New Jersey and Delaware are not completed. Removing that generation from the modeling resulted in overloads on the South Bend-Keystone 500-kV, Keystone-Conemaugh 500-kV, Conemaugh-Juniata 500-kV, Brighton-Doubs 500-kV, Keystone-Juniata 500-kV and Burches Hill-Possum Point 500-kV lines.

Removing the offshore wind also resolved overloads on the Rock Springs-Bramah 500-kV line and Peach Bottom 500-kV bus identified in other scenarios.

PJM’s Wenzheng Qiu said removing the projects increases power flows from west to east and from south to north, which will be considered in evaluating the robustness of projects submitted in Window 1.

PJM also updated the window’s problem statement to reflect that no major regional transfer issues were identified in the 2030 base case. However, several high-voltage overloads were found in the seven-year case.

Staff chose not to include clusters with overloads on the AG1-125-Marysville 765-kV line and the 765-kV corridor between Wilton Center and Marysville due to the lines being limited by equipment. Multiple overloads on the 500-kV network in the Mid-Atlantic Area Council region also were not included as they are not present aside from the scenario removing the offshore wind developments.

PJM did include a pair of overload clusters in the Columbus, Ohio, region where N-1-1 analysis found widespread local system voltage issues expected to worsen with load growth forecast to continue beyond the seven-year horizon.

Overloads on the 138-kV and 115-kV networks ATSI along the East Springfield-Melissa-London corridor were included.

Supplemental Projects

Duke Energy presented a $186 million project to serve a customer planning to bring 800 MW of load to Butler County, Ohio, by 2030. It would proceed in four phases, starting with tapping into the Miami Fort-Woodsdale 345-kV line to provide initial service for about 300 MW of load. The first phase will be paid for by the customer.

Next, Duke will build a 345-kV substation, named Wayne-Madison, at the customer’s location to be looped into the Woodsdale-Miami Fort line. It will be looped in with about one mile of new transmission at a cost of $40 million for the second phase, which is envisioned to be complete by the end of 2028.

The third phase involves building a new Cotton Run substation cutting into the Miami Fort-West Milton 345-kV line and connecting to Wayne-Madison with a new 5.5-mile 345-kV circuit. The third phase is estimated to cost $45 million and to be done by June 2029.

The project will complete with the rebuilding of the 138-kV Port Union-Toddhunter double circuit line to upgrade one side of the line to 345-kV, with corresponding equipment installed at Port Union. This phase is estimated to cost $101 million and be complete by the end of 2030.

FirstEnergy presented a $344 million project to rebuild its 69-mile Sammis-Star 345-kV line due to the towers failing wind and ice load tests. It has 22 wood pole H-frame and 375 steel lattice towers along its length, and a tornado left 13 towers destroyed in a cascading failure. The project is in the conceptual phase with a possible in-service date of May 30, 2031.

The utility presented another three projects to repair lines experiencing degradation and end-of-life issues. A $74 million project would rebuild 14.5 miles of the Niles-Shenango 345-kV line, repairing wood poles and reconductoring. A $53 million project would replace 33 steel towers along the double circuit 345-kV corridor between the Beaver Valley, Hanna and Mansfield substations and reconductor about 13.5 miles. A $21 million project would rebuild elements of the Bayshore-Davis Besse 345-kV line.

Dayton Power and Light presented several needs to serve new customers across Ohio. Some of the load is expected to begin coming online in the next few years, scaling to about 1.6 GW by 2030.

PPL presented a need to serve a customer seeking 230-kV service for 1.5 GW of load near Gouldsboro, Pa. The customer is expected to come online in 2027 drawing 300 MW and scale to its full consumption by 2030.

PSEG presented a $27 million project to reduce network strain on the Newark switching station by installing two 230/13-kV transformers at the nearby McCarter switching station and transferring several circuits to that facility. The project is in the conceptual phase with a possible in-service date in December 2029.

Dominion presented a $54 million project to rebuild three lines nearing the end of their useful life: the 30-mile Chesterfield-Lanexa 115-kV line, 14.6-mile Chesterfield-Chickahominy line and 14.2-mile Chickahominy-Lanexa 230-kV line. The Chesterfield-Lanexa line would be built to 230-kV standards but operate at 115 kV, while the other two lines would remain rated for 230 kV. Equipment at the substations also would be upgraded. The project is in the engineering phase with an expected in-service date of Dec. 31, 2028.

Several stakeholders requested that TOs presenting supplemental projects intended to serve large loads specify whether those consumers have been submitted to PJM as large load adjustments to its annual load forecasts.

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GE Vernova to Pay Nantucket $10.5M for OSW Mess

The manufacturer of an offshore wind blade that disintegrated in July 2024 has agreed to pay a Massachusetts beach community $10.5 million. 

The town and county of Nantucket said the agreement with GE Vernova for the Vineyard Wind 1 incident is compensation for costs and losses sustained by the town and local businesses. The settlement was announced almost a year to the day after debris began washing up on beaches during the height of the tourist season. 

It was a landmark failure for the young U.S. offshore wind industry, which already was struggling against cost and logistical hurdles, and it provided new ammunition for offshore wind opponents. 

A year later, the offshore wind sector is on the ropes, facing continued popular opposition and a hostile new presidential administration. The latest potentially harmful move by federal regulators was to inform Maryland officials about errors in the final permit they issued for wind power projects off that state’s coast. 

The July 13, 2024, incident south of Nantucket was a failure that just kept getting worse for Vineyard Wind 1, an 800-MW joint venture of Avangrid and Copenhagen Infrastructure Partners. (See Blade Failure Brings Vineyard Wind 1 to Halt.) 

The project already was behind schedule, and federal regulators slapped lengthy work stoppages and limits on it after. The developers faced a roar of local criticism about the speed and manner in which they publicized the incident and a chorus of told-ya-so attacks from offshore wind foes nationwide. 

GE Vernova’s internal investigation revealed quality control problems at the Quebec factory where subsidiary LM Wind Power built the blade that disintegrated. It determined that multiple blades already installed on Vineyard Wind turbines would need to be removed and replaced at additional cost of time and money. (See GE Vernova Gives Update on Offshore Wind Woes.) 

Nantucket said debris entered the water table, settled on the seabed and washed up on town beaches, necessitating a monthslong cleanup. 

The settlement bars Nantucket from making disparaging remarks about GE Vernova and related parties covered in the lawsuit, although the town can make accurate good-faith comments on the blade incident. 

In its July 11 statement, Nantucket said it “commends GE Vernova for its leadership in reaching this agreement.” 

Nantucket Select Board member Brooke Mohr also kept within the boundaries of the agreement, saying: “Offshore wind may bring benefits, but it also carries risks — to ocean health, to historic landscapes and to the economies of coastal communities like Nantucket, known worldwide as an environmental and cultural treasure.” 

Nantucket now will place the financial settlement in a community claims fund and hire an administrator to review claims. 

Work continues on Vineyard Wind. A July 7 mariners update indicated safety zones around five of the 62 turbine foundations. 

On the very last business day of the Biden administration, the U.S. Bureau of Ocean Energy Management approved a revised construction and operations plan for Vineyard Wind 1 that reflected blade removals. (See Prior to Trump Inauguration, Feds Lift Suspension on Vineyard Wind 1.) 

Three days later, on the very first day of his second term, President Trump issued a directive that chilled some offshore wind development and essentially froze planning on future projects. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

Aside from a stop-work order slapped on Empire Wind 1 for a few weeks, however, work has been allowed to continue on the other projects already under construction — Coastal Virginia Offshore Wind, Revolution Wind and Vineyard Wind 1. 

By contrast, EPA on March 14 placed a hold on the air quality permit issued to New Jersey’s last actively pursued offshore wind project — Atlantic Shores, which still was well short of construction. (See EPA Puts Hold on Atlantic Shores OSW Permit.) Its developers later shelved the plan indefinitely. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.) 

Likewise, US Wind’s Marwin 1 and Momentum Wind are federally permitted but have not started construction off the Maryland coast. 

On July 7, EPA informed the Maryland Department of Environment that the construction permit it issued June 6 to US Wind is deficient and would need to be reissued with clarification that appeals of the permit must be directed to EPA, not to the state, because the state issued the permit under federal authority. 

Failure to rectify the error could result in invalidation of the permit on appeal, EPA wrote. 

On July 11, wind power opponent U.S. Rep. Andy Harris (R) of Maryland applauded the EPA finding, saying: “The EPA has confirmed what many of us knew for years — this project was approved with glaring procedural and legal flaws. The Maryland Department of the Environment had no business directing the public to appeal a federal permit to a state court, and such a decision showed both incompetence and a disregard for public input from my affected constituents in Worcester County.” 

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Earthjustice Blasts NYISO ‘Power Trends’ Report to State Officials

ALBANY, N.Y. — Earthjustice claimed that NYISO’s latest annual “Power Trends” report was full of misleading statements that favor new natural gas generation in a letter July 7 to New York state officials, including Gov. Kathy Hochul. 

“The ‘Power Trends’ report is not based on new information or analysis but is rather a summary of prior NYISO reports and analysis, none of which found that fossil-fired generation is necessary for reliability or that repowering aging power plants is beneficial for New York or the grid,” Earthjustice wrote. “Instead, it seems that NYISO is irresponsibly seeking to create a false narrative that New York needs new gas generation, even though there is no evidence to support that claim.” 

The organization noted that NYISO had not made any new finding of a reliability need and called into question its concerns about large load additions, arguing that “many recent reports have noted the uncertainty of those speculative new loads.” 

“NYISO is using reliability as a way to justify more gas infrastructure, even though their own analysis shows no new reliability need exists,” wrote Eric Walker, energy justice senior policy manager for WE ACT for Environmental Justice, who co-signed the letter. “Meanwhile, clean energy projects that could save New Yorkers billions are stuck in NYISO’s interconnection queue. Delaying renewables and expanding gas infrastructure isn’t just bad policy; NYISO’s false narrative puts environmental justice communities further in harm’s way.” 

The report, released June 2, included a section outlining the case for the refurbishment and repowering of old power plants, though it did not favor any particular resource. (See NYISO Makes Case for Repowering in Latest ‘Power Trends’ Report.) 

“We encourage every policymaker to read ‘Power Trends’ for a fact-based assessment of electric system reliability, climate policy advancement and economic development,” Kevin Lanahan, NYISO vice president of external affairs and corporate communications, said in a statement. “‘Power Trends’ suggests that repowering of all aging resource types — renewable and fossil — be examined to determine the opportunity for capacity additions, efficiency and carbon reductions.” 

Rachel Spector, deputy managing attorney for Earthjustice, said the organization had noticed signs of backsliding on New York’s climate law from local officials.  

“We are starting to hear from agency folks the idea that we need to start thinking about repowering gas plants or adding new gas generation,” Spector said. “It seems like it was clearly in response to ‘Power Trends.’” 

Spector said Earthjustice has “real concerns” about New York’s commitment to meeting its clean energy goals and the requirements of the climate law.  

“We don’t want to deny that there are major issues we have to figure out in the coming years with the grid, but there are a lot of things we could be doing, like speeding up renewables,” Spector said. 

The letter, also signed by representatives of the Environmental Defense Fund and Evergreen Action, notes that the report says the interconnection queue contains nearly 350 proposals, with nearly 50,000 MW of proposed clean resources. 

Lanahan cited the Alliance for Clean Energy New York’s support of NYISO’s recent interconnection changes for reducing the wait time in its queue. 

ACE NY Executive Director Marguerite Wells told RTO Insider that the report showed the state is not deploying resources fast enough, and the organization hopes NYISO’s “significant reforms” will save time as the process matures. 

“But it is not enough to reform one process, especially in the wake of federal hostility,” Wells said. “To fully realize the immense benefits that renewable energy projects can bring, we need all state agencies to work together. NYISO has shown that new generating sources are needed in the coming years. Wind and solar power are the resources that can be online in the shortest time.” 

Wells said “red tape” should not force the state to rely on “technologies of the past” when renewables are ready to go. 

Hochul’s office did not respond to a request for comment by press time. 

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PJM OC Briefs: July 10, 2025

1st Read on Manual Revisions Detailing Generation Deactivation Process

PJM’s Michael Herman presented revisions to Manual 14D: Generator Operational Requirements to reflect the deactivation process stakeholders approved in January.

The changes are set to be voted on by PJM’s Operating Committee on Aug. 7, followed by the Markets and Reliability Committee on Aug. 20. (See “Stakeholders Endorse Changes to Generator Deactivation Requirements,” PJM MRC/MC Briefs: Jan. 23, 2025.)

The changes would require resource owners intending to retire a unit participating in the capacity market to provide PJM with at least one year’s notice before the desired deactivation date, while resources not participating in the capacity market would have to follow the notification process for seeking an exemption from the requirement that they must offer into the market.

The proposal also would remove the $2 million cap on project investments allowed in the deactivation avoidable cost credit, limit the yearly adder for investments to 10% and remove language causing the credit to be determined through the daily deficiency rate rather than the deactivation avoidable cost rate (DACR) when the DACR and applicable multiplier exceed the deficiency rate.

The proposal aims to increase transparency around reliability must-run (RMR) agreements by requiring resource owners to submit expected costs to be recovered to the Independent Market Monitor and PJM, which will publish the information. The Monitor also will publish market power letters, and notifications will be sent to stakeholders regarding RMR arrangements.

PJM Initiates Black Start Reliability Backstop Process

PJM has opened communications with transmission owners under the black start reliability backstop process to determine if a third request for proposals (RFP) is needed to secure at least one fuel-assured resource for each zone.

PJM’s Ray Lee told the OC there are several zones without a fuel-assured black start resource following repeat RFPs, although a final count has not been completed yet. He said staff wanted to provide stakeholders with notice that the process has been started as early as possible.

The dialogue with transmission owners is the first step of the backstop, which can either result in an RFP where transmission owners in zones lacking a fuel-assured resource are required to submit a proposal or PJM actively monitoring the shortage. If an RFP with mandatory proposals is held, PJM will select the best proposal, and the transmission owners must make a Section 205 FERC filing.

June Operating Metrics

PJM in June experienced an average hourly load forecast error rate of 1.81% and a peak error of 1.83%, with five days outside its 3% peak error rate benchmark.

The peak on June 13 was a 4.01% overforecast due to temperatures coming in 6 to 8 degrees Fahrenheit cooler than expected, while the June 27 peak was 7.11% overforecast with a multiday heat wave ending as temperatures fell by as much as 12 degrees.

The June 7 peak was 3.75% underforecast with temperatures 4 to 5 degrees higher than predicted, while unexpected heat and humidity on June 8 contributed to a 3.5% underforecast. The June 10 peak was 4.67% underforecast due to high temperatures and humidity.

The month saw one spin event, four shared reserve events, three maximum generation emergency alerts, 12 pre-emergency load management reduction actions, one high system voltage action and two hot weather alerts issued. There were 69 shortage cases approved between June 22 and 25, as well as on June 30.

The spin event occurred June 22 at 7:37 p.m. and lasted 7 minutes and 46 seconds. There were 1,907 MW of generation assigned with 56% responding and 418 MW of demand response (DR) assigned with 65% responding.

Periodic Review of Manual 13

PJM presented a set of revisions to Manual 13: Emergency Procedures drafted through the document’s periodic review.

The revisions codify PJM’s practice of conducting two voltage reduction action tests each year and add detail to its manual load dump action, including specifying that members should identify critical gas infrastructure that could impact generation capability.

The language clarifies that pre-emergency DR deployments are not a trigger to enter NERC Energy Emergency Alert Level 2 and removes a reference to an outdated NERC standard limiting the amount of contingency reserves consisting of interruptible load to 33%. It also specifies that PJM will curtail non-pseudo-tied exports as needed when it issues a primary reserve warning, emergency load management reduction action or maximum generation emergency action.

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PJM MIC Briefs: July 9, 2025

Stakeholders Endorse Changes to Storage Participation in Regulation Market

The Market Implementation Committee endorsed by acclamation a PJM proposal to allow demand response resources with behind-the-meter storage to participate in the regulation market when there is the capability for energy injections. (See “PJM Presents Education on Demand Response in Regulation Market,” PJM MIC Briefs: June 2, 2025.) 

The proposal would allow DR customers to participate as regulation-only resources when there is no load or a net injection at the point of interconnection, so long as they’ve received authorization from the relevant electric distribution company and it’s reflected in a net energy metering agreement. 

The change is part of PJM’s wider proposal to comply with FERC Order 2222, which is set to be effective Feb. 2, 2028 (RM18-9). 

Jay Marhoefer, CEO of Intelligent Generation, said tariff changes by certain EDCs that allow behind-the-meter storage to participate in the regulation market while injecting had the unintended consequence of voiding the PJM — and FERC-endorsed — process for allowing injection, either through a PJM interconnection service agreement (ISA) or wholesale market participation agreement (WMPA). 

Marhoefer said the proposal would recognize that certain utilities want to encourage regulation participation and can settle the injection. “There’s no engineering issue, there’s no technical issue, this is strictly an accounting issue,” he said. 

Independent Market Monitor Joe Bowring opposed the proposal as a one-off benefit to a small subset of market participants and argued that if the commission had intended for elements of PJM’s compliance filing to be implemented earlier, it would have reflected that in its order. 

PJM Presents Manual Revisions for Regulation Market Redesign

PJM presented a first read on a slate of manual revisions to conform with FERC’s approval of a redesign of the RTO’s regulation market (ER24-1772). The changes to the regulation market create one price signal with resources offering regulation up and down products, replacing a model with Regulation A for long deployments and Regulation D for fast response and bidirectional products offered by market participants. (See “PJM Presents Regulation Market Rework,” PJM MRC/MC Briefs: Dec. 20, 2023.) 

The changes to Manual 11: Energy & Ancillary Services Market Operations add detail to offer structure, DR participation, how regulation range limits affect resource clearing and lost opportunity cost (LOC) credits. PJM’s Joseph Tutino said the changes essentially create a new Section 3, expanding it by eight subsections. 

The Manual 15: Cost Development Guidelines revisions specify that cost increases for variable operations and maintenance (VOM) are zero for regulation resources also participating in the energy market, as those costs are recoverable in energy offers. It also updates references to regulation performance to instead read as regulation mileage. 

The Manual 28: Operating Agreement Accounting changes include the formula for the regulation clearing price credit and how shoulder interval opportunity costs are determined. 

First Read on Real-time Renewable Dispatch

PJM’s Vijay Shah presented a first read on a proposal to create a new Effective EcoMax parameter for wind and solar resources for dispatch in the real-time energy market. The proposal is set to be voted on by the MIC at its Aug. 6 meeting, followed by the Markets and Reliability Committee on Sept. 25 and Members Committee on Oct. 23. A FERC filing is envisioned in November or December. (See “2 Renewable Dispatch Packages Advance to MIC,” PJM MIC Briefs: June 2, 2025.) 

The parameter would use a forecast value of the resource’s capability for each five-minute interval, which is intended to better reflect how a unit will perform than the existing Eco Max parameter. Shah said PJM’s security-constrained economic dispatch is limited to dispatching resources up to Eco Max, which can prevent them from being set at their full output.  

Resources would be limited to ramping up to 20% of their installed capacity per minute to minimize volatility, which Shah noted still would allow them to increase to 100% in a five-minute interval. 

The proposal would retain curtailment flags for wind resources and establish them for solar as well. Curtailment flags for all resources are set to be removed in July. However, a Distributed Resources Subcommittee (DISRS) poll found 96% support for a variant of the proposal retaining them for renewables. 

During the June 2 MIC meeting, Shah said eliminating curtailment flags would require generation owners to follow their basepoints and avoid situations where intermittent resources with low marginal costs are curtailed because their bid-in parameters are lower than actual output, resulting in higher-cost units being committed. 

Monitor Proposes Rewrite of Offer Capping Issue Charge

The Independent Market Monitor proposed revisions to a problem statement and issue charge exploring how resources scheduled in advance of the day-ahead market have their offers capped to widen their scope to include transparency on how those resources are committed, how the commitments are communicated, which offers are used and how uplift is calculated, among other things. The original problem statement and issue charge were sponsored by PJM and supported by the Monitor in February. 

The changes add four key work activities to the issue charge: 

    • education on how PJM schedules resources ahead of the DA market, including triggers for those commitments, how market participants are notified, commitment instructions, inputs and models used to determine commitments, and constraints not included in unit parameters; 
    • consideration of more transparency on the process for advance commitments; 
    • updating the uplift calculation for units with multi-day commitments; and 
    • determining how units with advance commitments are treated in the DA market. 

Joel Romero Luna, market analyst with the Monitor, said the rules should be specific about the commitment instructions so generators know the amount of gas a resource should be procuring for a specific commitment. Leaving the instruction unclear can lead to resource owners buying more gas than needed and being compensated for fuel not used or can lead to resource owners not buying enough gas to match PJM’s expectations. 

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PJM Stakeholders Discuss Quadrennial Review Proposals

PJM and several stakeholders presented proposals to define the contours of RTO’s capacity market design for the 2028/29 Base Residual Auction (BRA) and the three following auctions as part of the market’s Quadrennial Review.

The review aims to update the variable resource requirement (VRR) curve — which defines the amount of capacity the market procures and at what cost — to address changing market conditions. In a report commissioned by PJM, the Brattle Group said the key challenges that must be addressed are tightening supply and demand, uncertainty in the cost to build new capacity and accounting for several changes PJM has made to how it identifies reliability risks and determines the capacity value for different resource types.

The review also looks at the inputs to the VRR curve such as the reference resource technology class, whose costs are key inputs across the market; the cost of new entry (CONE) to build the reference resource in various regions of PJM; and the energy and ancillary services (EAS) offset, which estimates revenues outside the capacity market to net against CONE.

The Market Implementation Committee is set to vote on the proposals during its Aug. 6 meeting, followed by same-day Markets and Reliability Committee and Members Committee votes Aug. 20. The proposals also would require the approval of PJM’s Board of Managers. PJM aims to file its recommendation with FERC by Sept. 30.

Stakeholders Divided on Reference Technology

Much of the discussion during the July 9 first read on the proposals at the MIC centered on whether to retain the combustion turbine reference resource or adopt PJM’s recommendation to shift to a combined cycle unit in all regions except ComEd, where a four-hour battery electric storage system (BESS) would be the reference resource.

PJM’s Skyler Marzewski said staff believe a CC is best situated for meeting demand. Developers have shown interest in building new resources based on submissions to the reliability resource initiative (RRI), a fast-track interconnection queue the RTO opened earlier this year. Six of the projects selected for expedited interconnection studies through the RRI were new CC resources. (See PJM Selects 51 Projects for Expedited Interconnection Studies.)

“There was no clear winner, but when we really had to sit down and pick one, it seemed like a combined cycle was the best resource … what that means is it was the most economical,” Marzewski said.

PJM’s proposal includes several changes to other Quadrennial Review components to account for the higher EAS revenues for a CC over a CT to prevent the midpoint of the VRR curve from “collapsing” — an issue that led PJM to reverse a shift to a CC reference resource in 2022. Marzewski said the viability of new CC units is helped by emissions standards proposed under EPA’s power plant rule being held in abeyance by the D.C. Circuit Court of Appeals, with a new rule likely being issued by the end of the year. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts and EPA Proposes Repealing Limits on Power Plant Greenhouse Gas Emissions.)

The net EAS parameters would remain the same aside from updating unit-specific parameters to account for the CC and BESS reference resources, Marzewski said.

Requirements for gas generation to implement carbon capture technology under the Illinois Climate and Equitable Jobs Act led to storage being the most economic capacity resource, Marzewski said.

Independent Market Monitor Joe Bowring said the goal of the capacity market is to solve the “missing money” problem by ensuring capacity resources can recoup any costs to provide capacity above what they earn through the energy and ancillary service markets. While a CC has been the most common resource over the past few decades, the economics of their development are based on EAS revenues. Combustion turbines, however, would go bankrupt almost immediately without capacity revenues, making the capacity market critical to ensuring the viability of peaking units and defining the missing money.

The Monitor’s proposal would use a dual-fuel CT as the reference resource, with some changes over the status quo for characteristics such as heat rate and operating and maintenance costs.

LS Power proposed to use a four-hour battery for ComEd and a dual-fuel CT for all other regions, with updated CONE values. Director of Project Development Tom Hoatson said the goal of the Quadrennial Review should be to stabilize the capacity market while stakeholders address more holistic issues in other stakeholder processes.

Hoatson said CCs are not dependent on capacity revenues to be viable in PJM, whereas CTs and battery storage cannot subsist on energy revenues alone.

Pennsylvania Public Utility Commission Vice Chair Kimberly Barrow proposed a four-hour battery in ComEd and for all other regions a CC reference resource based on unit characteristics included in earlier IMM proposals, which would result in lower CONE values than the PJM proposal.

Changes to VRR Curve Shape

The PJM proposal also would revise the calculations defining the three points on the VRR curve: the maximum price would be set to the greater of 1.75 times net CONE or 0.6 times gross CONE, while the midpoint would be half of the price cap. The status quo shape has a maximum price that is the greater of 1.75 times net CONE or gross CONE and a midpoint at 0.75 times net CONE. The minimum price would remain zero.

Marzewski said tying the midpoint to the maximum price instead of net CONE would prevent it from falling to zero when EAS revenues for the reference resource are high.

He said the proposed curve’s performance is similar to the existing shape, resulting in a loss of load expectation of 0.084 events per year if net CONE is estimated accurately compared to 0.073 if the current shape is applied to a CC. With an accurate net CONE, Brattle’s modeling estimated an average clearing price of $380 MW/day with a standard deviation of $155 and the price hitting the cap 9.5% of the time. An underestimated net CONE would have a clearing price of $532 MW/day and hit the cap 37.7% of the time, while an overestimate would clear at $228 MW/day and have a 0.5% chance of hitting the cap.

Marzewski said PJM opted not to follow Brattle’s recommendation of a marginal reliability impact curve as most of the expected benefits also could be achieved by implementing a sub-annual capacity market design. During the June 18 Markets and Reliability Committee meeting, Pennsylvania Gov. Josh Shapiro’s office introduced a problem statement and issue charge to shift to a seasonal market. (See Pennsylvania Brings Seasonal Capacity Issue Charge to PJM.)

The Monitor’s proposal would set the maximum price at the lower of 1.5 times net CONE and gross CONE, consistent with the original PJM design, and set the midpoint at half of the maximum. Bowring said the gross CONE of a CC is significantly higher than the gross CONE of a CT and that PJM’s proposed 1.75 times net CONE generally was greater than gross CONE in the most recent auction.

Bowring said current conditions in the capacity market are almost entirely the result of adding large data center loads. The result is likely to be future auctions clearing at the maximum price. He argued that the potential resultant triggering of the PJM backstop auction would mean the return of cost-of-service regulation for new generation. That would be inconsistent with the competitive market design and unfair to existing generators, he said. The Monitor has recommended repeatedly that the best solution in the capacity market would be to require new data center loads to bring their own generation.

Barrow’s proposal would set the maximum price at 1.15 times gross CONE minus 0.75 times the EAS offset, with the midpoint at half that value. Unlike all other proposals and the status quo, the minimum price would be reached at 106% of the reliability requirement rather than 104.5%.

The LS Power proposal uses the status quo VRR curve shape.