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April 11, 2025

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ACP Road Map Suggests Market Changes to Increase Storage Participation

The American Clean Power Association on April 8 released a report produced by The Brattle Group laying out how organized markets can replicate the success CAISO and ERCOT have had in deploying energy storage resources. 

The “Energy Storage Market Reform Roadmap” includes detailed changes for the energy, capacity and ancillary services markets, with individual “road maps” for MISO, NYISO and PJM guiding how to grow storage in their territories. 

The report and road maps focus on those grid operators because they have “opportunities for market reform,” their states are pursuing decarbonization, and they have a mix of central planning and market-based investment. 

CAISO and ERCOT have shown that with updated market rules, energy storage delivers substantial value and complements both thermal and renewable generation to help meet reliability needs. 

“Energy storage technologies add a new dimension of flexibility and efficiency to our electric grid,” ACP Vice President of Energy Storage Noah Roberts said in a statement. “Energy storage has proven to boost reliability and lower energy costs. In Texas, the state added 5 GW of energy storage in one year, eliminating calls for customers to reduce electricity use during historic summer heat, stabilizing the grid through volatile winter storms, all the while delivering more than a billion dollars in energy cost savings. This road map outlines actionable steps to better utilize energy storage to deliver reliable and affordable power across the United States.”  

Before FERC issued Order 841 in December 2020 to open up the RTOs to energy storage, the resource faced barriers to participation in the markets, which were designed around the attributes of other generators. Where the organized markets have encouraged deployment and removed barriers, storage has helped prevent blackouts and reduced pressure on customers during tight operating conditions on the grid, while delivering cost savings, ACP said. 

One of the areas the report and road maps focus on is the need to replace retiring generation while maintaining reliability and meeting growing demand in many parts of the country. Storage can help replace the reliability services retiring generation provided while keeping a lid on high capacity prices, ACP said. 

Many generators were planned to support local transmission needs, especially when they were built in load pockets. Retirements will continue to trigger transmission violations, and some of those are too localized for capacity markets to solve. 

The industry’s historic answer for those situations is to build transmission, and sometimes to keep power plants running with out-of-market, reliability-must-run contracts while that is built. But storage, or non-wires alternatives, can contribute to solving those issues at lower costs to consumers, the paper says. “RTOs should identify solution(s) that lead to the lowest costs for ratepayers when procuring reliability solutions out of market.” 

Some RTOs, including PJM, do not consider non-wires alternatives for retiring generators. Others do, but they are rarely picked because of a lack of comprehensive benefit-cost analysis, which is exacerbated by the short notice period between the solicitation date and required online date, the report says. 

On average in PJM, RMRs have cost $300/MW-day, which is well above the market clearing prices in the long term of $100/MW-day, according to the paper. Studies have shown the benefits of competitive solicitations both in transmission infrastructure procurement and generator procurement, it says. 

Energy storage — especially long-duration and multiday — may be able to resolve both transmission security constraints and provide flexibility value to the grid, the report argues. 

The report highlights how CAISO oversaw a process to replace the 165-MW Oakland gas plant that announced its retirement in 2016. The ISO picked Pacific Gas and Electric’s Oakland Clean Energy Initiative, which included some transmission upgrades, storage and demand response that met the need at a lower cost than transmission or generation solutions alone. 

It also pointed to NYISO’s efforts to replace the dual-fuel Narrows and Gowanus plants that were slated for retirement this year. The plants were to be replaced by the Champlain Hudson Express Line to bring hydropower down from Quebec, but the line was delayed until 2027. 

NYISO identified a short-term reliability need and issued a competitive solicitation for a solution, but none of the responses could solve it in time. Recently, NYISO said the peaker plants will still be needed for the next couple of years. (See related story, NYISO Reaffirms Need for NYC Peakers in Summer.) 

“As electricity grids struggle to keep pace with the feverish growth in energy demand across the country, every electron of power counts,” Eolian COO Stephanie Smith said in a statement. “Battery energy storage helps both thermal and renewable energy technologies optimize their participation and increase reliability and resilience by providing power when and where it is needed quickly. By updating existing rules to account for new technologies, regional electricity markets can enhance grid performance and lower costs for consumers.” 

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NY Energy Summit: Patience Trumps Angst

ALBANY, N.Y. — Energy and transmission development in New York can be an exercise in patience and persistence, with supportive policy messages counterbalanced by complex regulations, high costs and long timelines.

The annual New York Energy Summit often is a showcase of this dichotomy, a chance to catch up on the latest developments in the Empire State and share thoughts on how to build on those changes or get around them.

The 2025 edition of the event could have been more of this, given the important policy decisions being hashed out a block away in the state Capitol. But they often seemed overshadowed by national developments — a brewing global trade war, trillion-dollar hourly swings in the financial markets and murmurs of a recession or stagflation bearing down on the U.S. economy.

Clearly the need to expand and modernize New York’s grid persists regardless of who is in the White House, and the timelines will extend beyond the term of any one president, or any three.

But as recent weeks have shown, a president can change the landscape markedly in much less than a single term — or even worse, shroud the landscape in a fog of uncertainty.

As New York Public Service Chair Rory Christian noted in a keynote address: “Difficult times lie ahead.”

Sergio Garcia, Rabobank | © RTO Insider 

“Inaction is not an option,” he said. “I encourage you to lean into this moment, not despite the uncertainty, but because of it.”

New York’s grid is like most others — it needs extensive and expensive modernization and expansion as it faces potentially huge load growth. The state also has some of the most ambitious plans in the nation to decarbonize the power portfolio feeding that grid, as well as some of the highest costs and most rigorous processes for carrying all these plans out.

Rapid-fire directives coming from the White House since Jan. 20 have made the prospect more daunting.

Inflation and interest rate fluctuations have created new financial risks, as have President Donald Trump’s repeated tariff threats. Previously committed grants and tax incentives remain under threat.

An executive order issued on Day 2 of the New York Energy Summit targets key policy decisions in climate-focused states and calls out New York by name.

State officials speaking at the Infocast event acknowledged the uncertainty facing everyone in the room but said it has not changed New York’s vision.

U.S. Rep. Daniel Goldman (D-N.Y.) | © RTO Insider

“If there’s one message to take away today it is that the state of New York is fully committed to our clean energy goals,” said Georges Sassine, vice president of large-scale renewables for the New York State Energy Research and Development Authority, which is leading the efforts to decarbonize the state, particularly its generation portfolio.

Christian heads the Department of Public Service, which leads regulatory efforts to put the infrastructure in place to accomplish these policy goals.

“[The goals] require, above all, a modernized grid,” Christian said. “We’re entering an era where our history of flat demand and flat load growth is no longer the norm. We’re in an era where need for interconnecting multiple resources in a short period of time is no longer a luxury but a necessity.”

Christian laid out some of the steps being taken toward this Grid of the Future, as the proceeding is named, and toward the flexibility needed to make it meet the needs at an affordable cost.

Georges Sassine, New York State Energy Research and Development Authority | © RTO Insider

Like any long-running process with thousands of stakeholders, there is not unanimous agreement on the details, nor universal satisfaction with the pace.

The state has seen slow buildout of renewables in the nearly six years since passage of its landmark climate law mandated the transition, and multiple panelists said state regulators need to adjust their approach accordingly — fossil fuels will be needed longer than the state hoped.

Matt Schwall, director of regulatory affairs for Alpha Generation, said all six of his company’s plants in New York are operating with Title Five state air permits that are expired and awaiting renewal.

“And that’s not just unique to us; that’s every generator in the state. It’s tough to convince an investor to put money in the state when you don’t know if you can even get a permit.”

Independent Power Producers of New York President Gavin Donohue, whose members produce much of the state’s electricity, said reliability concerns are growing.

Marguerite Wells, Alliance for Clean Energy New York | © RTO Insider

“The state needs to be realistic about what it takes to keep the lights on, on a day-to-day basis, and there needs to be a recognition that permits need to be issued in an effort to maintain that reliability,” he said.

NYISO Vice President of Market Structures Shaun Johnson said: “Particularly in some areas of the state, we have razor-thin margins. We, at the moment, don’t have a lot of flexibility to be able to ramp up new generation quickly and meet those future demand needs.”

The solution, he added, is not simple; it is a mix of load demand, market signals and state policy that will attract investors. “Because at the end of the day, they can choose — am I going to come to New York? Am I going to go to Virginia? Am I going to go to Texas? Where am I deploying my capital? And in some ways, we’re all competing against each other for that capital.”

New York has had some very visible problems adding generation — 88 renewable projects canceled their offtake contracts after cost escalations swept the industry in 2023. Those projects would have provided sizable progress toward the state’s clean energy goals and toward meeting the need for more gigawatts of capacity. The contracts are gone but the projects themselves are not necessarily dead, and the state will try to draw them and others back into its portfolio.

Matt Schwall, Alpha Generation | © RTO Insider

Sassine said more requests for proposals (RFPs) are in the works, along with requests for information (RFI) to shape those RFPs.

“We very much look forward in these RFI processes to get feedback from all stakeholders on how we should be thinking about risk-sharing, going forward in light of all this federal uncertainty,” he said.

The state-owned New York Power Authority has begun working in its new role as a renewables developer, and the vice president leading the effort, Vennela Yadhati, said renewables have a key advantage over the fossil fuel generation that suddenly is in favor in Washington: speed of deployment.

Multiple speakers at the summit noted the yearslong wait for a newly built gas turbine. Yadhati contrasted the relative speed with which solar and onshore wind generation are being built and cited the resilience those industries have developed.

“The renewables industry has been through administration changes in the past,” she said. “We have been through uncertainty in the past, but we continue to strive and thrive, actually, in this market.”

New York Public Service Commission Chair Rory Christian | © RTO Insider

Marguerite Wells, executive director of Alliance for Clean Energy New York, placed some of the onus for moving ahead on the renewable energy developers themselves.

Some developers, she said, have submitted “tire kicker” proposals they were not fully committed to, contributing to the sluggish nature of the NYISO interconnection queue, and others have cut corners on their community outreach efforts — a potentially serious mistake in a home-rule state where local opinion can slow or block a proposal.

As the level of public opposition and concern around projects and politicization of renewables grows, it is more and more incumbent on developers “to do a better and better job with community relations and stakeholder work,” Wells said. “I think that often gets short shrift.”

New York’s infamously slow timelines, she added, are getting better, through the state’s streamlined regulatory processes and through NYISO’s newly revamped interconnection process.

Shaun Johnson, NYISO | © RTO Insider

“I think we can see that the new process is doing what it’s supposed to do,” Wells said. “It’s painful to go through it now. It’s much more expensive and it’s faster, and it’s more technically challenging to get all that work done in a shorter period of time. But the end goal is to have an interconnection process that more similarly mimics what Texas has done, which is get a project through in a year or two. Used to be five to seven in New York, and that’s not necessary.”

U.S. Rep. Daniel Goldman (D) conceded that his opinions hold no sway with Trump and that he is worried about the fate of renewable projects both present and future.

But he said the country’s need for electricity and the benefits renewables have provided for red congressional districts will be more influential than the opinions of a congressman representing a deep-blue New York City district.

IPPNY CEO Gavin Donohue | © RTO Insider

Goldman urged listeners to stick with the approach that most of the renewable energy community seems to have adopted the day after Election Day, emphasizing the good of the nation rather than the good of the planet.

“Let’s set aside the climate benefits as we are making this case right now, because the economic and national security case for clean energy is stronger than ever.”

He added: “We absolutely cannot give up with this administration — even if those wind turbines are unattractive.”

Vennela Yadhati, New York Power Authority | © RTO Insider

Sergio Garcia, executive director of project finance at Rabobank, counseled patience and a longer view. Financial planning is difficult until budget and policy negotiations produce a firm picture of the tax incentives that grew from the Inflation Reduction Act.

“Right now, we’re all distracted with the IRA,” he said. “It’ll change — in what form, I have no clue. Until we have visibility in there, it makes your jobs a lot harder, because you need to deploy capital.”

Garcia added: “It’s a reality check, right? It did work before the IRA, and it’ll work again in one form or another, and renewables will continue to strive because it is the lowest levelized cost of energy. So I think there’s plenty to do. I think that banks are all active, and we’re all like looking for projects to finance.”

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Texas Loan Program Loses 2 More Gas Projects

Texas’ loan program for gas generation has lost two more projects, marking the third and fourth companies to withdraw projects from the due diligence review process. 

Constellation and WattBridge became the latest to pull projects from the Public Utility Commission’s In-ERCOT Generation Loan Program, part of its Texas Energy Program. The companies took out four projects totaling 1,410 MW.  

The 16 remaining applications total 8,346 MW of capacity and $4.46 billion in requested loan amounts. The TEF is a $5 billion, low-interest program designed by lawmakers to quickly add new natural gas plants. 

PUC spokesperson Ellie Breed said staff intend to advance additional applications to the due diligence phase at a future open meeting. 

Constellation was seeking financing for 300 MW of gas-fired generation at its Wolf Hollow III facility. It told the PUC in March it was unable to determine “with certainty” the project’s overall costs because of the “uncertain timing” in receiving an air permit from the Texas Commission on Environmental Quality. That would prevent Constellation from signing a binding loan document. 

Wattbridge withdrew three projects totaling 1,110 MW of capacity. It said the TEF’s financing terms “introduce risk and costs that result in lower than anticipated returns with elevated risks.” 

The company also said it was withdrawing a 510-MW project in the Houston region from the pool of remaining applicants.

Two other companies pulled their projects from the TEF earlier in 2025. They cited supply chain issues as delaying the projects and keeping them from meeting a December 2025 deadline for initial loan disbursements. (See 2 Companies Withdraw Texas Energy Fund Projects from Consideration.) 

More than 4,650 MW of capacity has been withdrawn or denied from the original submitted applications. Nearly a third (3,903 MW of 12,249 MW) of the projects that advanced to due diligence now have been withdrawn or denied. 

“Texas will get new gas resources … but gas plants take time,” noted Stoic Energy principal Doug Lewin in his newsletter. “They can’t be developed fast enough to ensure reliability or allow for economic growth in the next three or four years, and possibly longer than that.” 

Kristi Hobbs, ERCOT’s vice president of system planning and weatherization, told board members April 7 that all 16 Texas Energy Fund projects recommended for due diligence by the PUC have submitted full interconnection study (FIS) applications with the ISO and are in various phases of the generation-interconnection process. Seven applicants have completed the full study processes. 

“Moving forward, a lot of progress on those,” Hobbs told the board. 

The TEF was created by the Texas Legislature in 2023 to add more dispatchable generation to the grid and was approved by voters later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state. 

The fund is composed of four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and Texas Backup Power Package. 

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NEPOOL Markets Committee Briefs: April 8-9, 2025

The NEPOOL Markets Committee (MC) held a two-day meeting focused on ISO-NE’s capacity auction reform (CAR) project. (For more coverage of the meeting, see ISO-NE Outlines Market Power Mitigation Measures for CAR Project.)

Ambient Temperature Derates

In other business, Hannah Johlas of ISO-NE presented an analysis of how ambient temperatures affect the performance of non-nuclear thermal resources, which the RTO developed in response to stakeholder requests. The analysis included an evaluation of third-party studies, capacity audit data and historical operational data.

All three components of the study showed a significant decline in the capacity of thermal resources as temperatures increased, equal to about a 3-4% decline in performance between 90 and 100 degrees Fahrenheit. The analysis did not evaluate the effects of ambient temperatures on fuel availability or resource outages.

While ISO-NE plans to calculate resource capacity accreditation at 90 F in the summer and 20 F in the winter, some stakeholders express concern that temperatures beyond this range could affect reliability.

ISO-NE does not plan to include modeling of ambient temperature effects in the CAR project due to the limited impacts and challenges of incorporating the additional modeling into the project. Johlas said it’s uncommon for the entire resource fleet to face temperatures above 90 F, even as climate change increases temperatures.

Some stakeholders pushed back on this conclusion, making the case that extreme heat often coincides with stress on the grid, and that a 3-4% reduction in the capacity of a 22,000-MW thermal fleet could cause a capacity reduction of up to 880 MW.

Demand Response Distributed Energy Resource Aggregations

Also at the MC, Dennis Cakert of ISO-NE presented conforming changes for FERC Order 2222, focused on demand response distributed energy resource aggregations (DRDERAs), which are aggregations of DERs that can reduce demand and inject energy into the grid.

Order 2222 requires transmission operators to eliminate barriers for distributed energy resource aggregations to participate in wholesale markets.

ISO-NE proposes to make DRDERAs eligible to participate in the day-ahead ancillary services market and to receive net commitment period compensation (NCPC). Including DRDERAs in NCPC would prevent “economic incentives to not offer true costs or follow dispatch instructions” in the energy market, Cakert said.

ISO-NE also proposes to reduce the minimum size requirement for resources participating in the regulation market from 5 MW to 100 kW “to align with the approved Order No. 2222 design.”

The changes would take effect in November 2026. ISO-NE will continue discussions on the conforming changes at the MC in May, targeting a vote on the proposal in June.

Tie Benefits

Matthew Ide, representing the Interconnection Rights Holders Management Committee, presented on the value of tie benefits and pushed back on the New England Power Generators Association’s (NEPGA’s) arguments in March that including tie benefits in the installed capacity requirement (ICR) creates reliability risks. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The ICR determines the amount of capacity ISO-NE must procure in the capacity market, while tie benefits refer to the emergency support New England can expect to receive from neighboring regions during a capacity shortage.

At the MC in March, Bruce Anderson of NEPGA said the “current market design ‘assumes away’ approximately 2,000 MW of capacity demand based on the belief that system energy from neighboring control areas is equivalent to ‘firm capacity,’” creating risks of under-procurement and price suppression.

At the April MC meeting, Ide emphasized that tie benefits are not a market product, and instead are “the reasonably assumed reliability benefits that come from transmission infrastructure that enables emergency assistance between regions.”

Tie benefits “are a reasonable and appropriate input into the ICR calculation,” he added.

Ide said tie benefits are supported by contracts ensuring ISO-NE will receive tie benefits from neighboring regions if this support does not jeopardize reliability in the neighboring region. Even if weather conditions are similar across regions, it’s highly unlikely for regions to experience resource outages threatening reliability at the same time, he said.

“Network load customers pay for all the tie benefits that come from the [pool transmission facility] ties through regional transmission rates. In return, load receives the benefit of a lower ICR and less need to procure capacity to meet the ICR,” he added.

He noted that FERC has found including tie benefits in the ICR to be just and reasonable, and that a recent ISO-NE analysis found the “underlying methodology is robust and thorough in the capacity quantification of tie benefits.”

ICR in a Prompt Auction

Manasa Kotha of ISO-NE discussed how the transition to a prompt market will affect the RTO’s methodology for establishing the ICR. He said ISO-NE will begin the ICR process about a year prior to each capacity commitment period.

“The primary conforming change for the ICR setting process is mainly the timeframe,” Kotha said, adding that reducing this timing from four years to one year will allow ISO-NE top use more up-to-date data, load assumptions and interface limits.

“Under CAR-Prompt, the data will all be provided closer in time to the commitment period, which is expected to enhance the accuracy of the ICR-related values,” Kotha said.

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ISO-NE Outlines Market Power Mitigation Measures for CAR Project

ISO-NE discussed its plans for preventing and mitigating market power as it overhauls its capacity market and resource retirement processes at the NEPOOL Markets Committee’s meeting April 8.

The RTO’s Capacity Auction Reform (CAR) project proposes to reduce the time between auctions and capacity commitment periods, transitioning the region from a forward market to a prompt construct. ISO-NE also plans to decouple resource retirements from the capacity offer process because the timing of the prompt market would not give the RTO enough time to address reliability issues created by retirements.

Under the new format, ISO-NE would require retiring resources to submit deactivation notices two years prior to their retirement from the market. As proposed, retirement notices would be binding and trigger an ISO-NE review process of potential reliability and market power issues. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.)

The market power analysis would include a conduct test to evaluate whether the resource is expected to be economic and a net portfolio benefits test to study whether a market participant’s overall portfolio would benefit from the resource retirement.

If a resource fails both tests, ISO-NE would issue a penalty equal to 1.5 times the participant’s expected portfolio-wide revenue increase from the retirement. These charges would be credited as a refund to all market participants.

“The market power charge is expected to be used infrequently,” said Kevin Coopey, principal analyst at ISO-NE. “Ideally, the risk of being charged deters the exercise of market power.”

The tests and charges would be based on expected market outcomes prior to the forward auction, instead of the actual market results.

“By evaluating market power at the notification deadline, we consider the perspective of the participant at the time of the deactivation notification,” Coopey said.

Coopey said basing market power charges on the actual auction results would create a nearly two-year delay for participants to learn the actual charge amount, creating significant uncertainty associated with unexpected events distorting market results and risks of excessively large charges.

Some stakeholders expressed concern about reconciling differences between the market expectations of participants and the ISO-NE Internal Market Monitor.

“The IMM acknowledges that different assumptions may be reasonable when the market participant holds different market information or beliefs,” Coopey said. “The IMM will accept different assumptions when they are reasonably justified.”

Responding to stakeholder requests for ISO-NE to allow participants to withdraw retirement requests, Coopey said the RTO is “considering the feedback,” adding that “the increased optionality of having withdrawable notifications must be balanced against the risk of increasing the likelihood of reliability retentions.”

ISO-NE has expressed concern that participants could fish for out-of-market resource retentions if they are allowed to withdraw a retirement request when a resource is not retained.

Responses to the proposal for a market power charge have been mixed, with some stakeholders arguing the proposal may not be punitive enough to prevent exercising market power, while others made the case it would be too punitive and could create reliability issues by preventing deteriorating resources from retiring.

Ben Griffiths of LS Power advocated for more flexibility on the timing of retirement submissions, proposing that resources not needed for reliability should be allowed to retire with less than two years of advance notice.

“Without commenting on the merits of the two-year notice proposal, allowing for accelerated exit of resources determined nonessential for reliability would reduce market inefficiencies and resource owner concerns about forced market participation,” Griffiths said.

“Optional, expeditious deactivation for non-reliability resources lets the region split the difference on notification: Longer notice period lets the region proactively explore reliability implications of each deactivating resource, while accelerated exit allows it to avoid a lengthy exit period when they aren’t needed,” he added.

Also at the MC meeting, ISO-NE presented its plans for mitigating market power concerns on offers within the capacity market. Andrew Copland of ISO-NE said that “in the ISO’s current design, most key components of seller-side market power mitigation framework will remain substantively unchanged.”

He said ISO-NE will run a conduct test and a pivotal-supplier test to evaluate market power, and it plans to impose a “binding offer ceiling at the IMM’s estimated competitive offer price” for resources that fail both tests. Copland said ISO-NE will publish a capacity cost review threshold; all offers that surpass the threshold will be subject to cost review by the IMM.

Copland also noted that ISO-NE is updating its auction participation rules for the prompt market and will require “all commercial resources capable of providing capacity … to offer it into the auction.”

He said resources that hold unused capacity interconnection rights pose a barrier for other resources looking to enter the market and could cause these resources to incur significant interconnection costs. He noted that participants can include multiple cost levels within a capacity offer from a single resource to account for the potential added costs of offering a resource’s full capacity.

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Texas Groups Ask FERC to Reject Puerto Rican Company Petition for Regulation

ERCOT, Oncor and the Texas Public Utility Commission have asked FERC to deny a petition from Puerto Rican company Pluvia to bring the territory under the commission’s Federal Power Act jurisdiction (EL25-57). 

Pluvia seeks a finding from FERC that its proposal to transmit power to Puerto Rico via batteries on cargo ships could make it subject to the commission’s regulations. (See Petition Asks FERC to Potentially Claim Jurisdiction over Puerto Rico.) 

The parties all filed similar motions, but none of them were aware of the petition, filed in early February, until after the due dates for comments, they said. 

If the commission granted Pluvia’s petition, the precedent would threaten ERCOT’s jurisdictional status, in which its few connections to the rest of North America’s grid do not give FERC jurisdiction over its markets, the Texas grid operator said April 8. 

“ERCOT recognizes the immense challenges the people of Puerto Rico have endured since Hurricane Maria and supports efforts to rebuild and modernize the island’s electric grid,” it told FERC. “Yet, as explained below, Pluvia’s petition is not the right path to achieve these crucial goals.” 

Granting the petition would require an unprecedented reinterpretation and expansion of FERC’s licensing jurisdiction under FPA Part I, which authorizes the commission to license non-federal hydroelectric projects on federal reservations or affecting navigable waters of the U.S., and under another section that gives FERC power to grant preliminary permits for such projects. 

But using storage to transmit power is not a hydro project; the proposed sites in Puerto Rico are not considered federal reservations; and the transportation of cargo from the mainland to the territory would not involve crossing navigable waters of the U.S., ERCOT argued. 

“Such a radical change could have serious implications for the jurisdictional independence of Texas’s intrastate ERCOT grid,” said the PUC, which oversees ERCOT’s markets in the same way FERC regulates others in the U.S. All the transmission between it and other states is provided pursuant to FERC orders under sections 210 and 211 of the FPA. 

“Because Pluvia’s proposal does not involve any physical flow of electric energy between states, Pluvia presents no valid basis for the requested declaration,” the PUC said. “What Pluvia requests would be a radical redefinition, contrary to precedent, of the meaning of ‘electric energy’ under the FPA to include stored potential energy that would later be converted into electric energy. And it would redefine ‘transmission’ under the FPA to include the shipment of charged storage devices that does not involve the flow or comingling of electric energy in interstate commerce. … 

“This ‘clarification’” — as Pluvia said in its request — “is contrary to law and totally unjustified: It would require the commission to ignore the plain text of the FPA and depart from well-established precedent analyzing the same issues in the context of the ERCOT market.” 

Oncor had filed to intervene in late March, making similar arguments, and Pluvia had asked FERC to deny the late intervention. 

Oncor responded that while it was late, Pluvia’s project is in early stages and FERC actually weighing the merits of its earlier filing would not burden it. FERC has been liberal in allowing late interventions in cases involving its jurisdiction, Oncor said. 

“Even if Oncor had not moved to intervene in this proceeding, the commission still would need to assure itself that it has statutory authority to grant the relief Pluvia seeks,” the utility said. “As such, Oncor intervening to raise jurisdictional arguments does not unduly prejudice or burden Pluvia.” 

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Northwest’s Only Nuclear Plant Could Get Uprate

Operators of the Columbia Generating Station (CGS) are seeking an extended power uprate for the facility, which is the Northwest’s only commercial nuclear power plant and a supplier of electricity to the Bonneville Power Administration.

Energy Northwest’s extended power uprate and efficiency improvement project for CGS would increase the power plant’s electric generating capacity from the current 1,207 MW to 1,393 MW in 2031.

Energy Northwest, a consortium of utilities from across Washington state, owns and operates the plant near Richland, Wash. BPA markets the energy produced and pays all costs, which are included in the revenue requirements of its power services rate structure.

BPA and Energy Northwest hosted a meeting April 8 on the proposed uprate. Energy Northwest said it would seek BPA Finance Committee approval next month. The uprate also requires Nuclear Regulatory Commission (NRC) approval.

Energy Northwest also is considering seeking a 20-year license renewal for CGS, which would extend operations through 2063.

Synergizing Projects

The uprate would coincide with so-called lifecycle management projects at the power plant, in which work on certain components already is scheduled. For example, replacement of the high-pressure turbine would cost the same with or without the power uprate, said Tammi Oldham with Energy Northwest.

In addition, the project potentially could take advantage of tax credits: either the production tax credit, an annual credit based on incremental generation, or the one-time investment tax credit.

“We see there is a growing demand for power, and we think an extended power uprate is a very [easy], cost-effective way to meet that growing need,” said Energy Northwest’s Jeff Windham.

“Overnight” direct costs, which don’t include interest expenses, are projected at $465 million for the lifecycle management projects and an additional $670 million for the extended power uprate, for a total of $1.135 billion, according to an Energy Northwest presentation. Indirect costs are estimated at $30 million.

Work related to the uprate would occur during refueling and maintenance outages scheduled for 2027, 2029 and 2031, Energy Northwest said.

Although the lifecycle cost and benefits of the extended power uprate are expected to reduce rates, Energy Northwest noted that rate pressure would increase during construction until the project starts generating energy.

BPA’s resource program includes the CGS extended power uprate in the least-cost portfolio for meeting future customer needs, a Bonneville representative said during the meeting. The uprate would reduce the amount of new solar and wind capacity BPA otherwise would need to acquire.

Uprates on the Rise

Nuclear power plants across the U.S. have been turning to power uprates to meet soaring electricity demand. In one recent example, Georgia Power has proposed uprates to four of its nuclear reactors in its 2025 Integrated Resource Plan. (See Georgia Power Proposes Nuclear Uprate, Delay in Fossil Retirement.)

Since the 1970s, the NRC has approved 171 uprates totaling 8,030 MW of electric power, roughly equivalent to eight new reactors. Nuclear plants typically increase their output by using slightly more enriched uranium fuel or a higher percentage of new fuel, Energy Northwest said.

Power uprates fall into different categories based on the percentage by which power will be increased, according to the NRC. Stretch power uprates fall within the design capacity of the plant and generally are up to a 7% increase.

In contrast, extended power uprates require “significant modifications” to a plant’s major equipment. Power increases in extended uprates may be as high as 20%.

The NRC said it’s preparing for more uprate requests.

“We’re already looking at our past reviews to see how we can process these requests as efficiently as possible while maintaining safety,” the agency said on its website.

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NYISO Reaffirms Need for NYC Peakers in Summer

NYISO continues to find a reliability need for New York City this summer and two peaker plants in the city should be allowed to continue operations into 2027 if necessary, according to sensitivity results for the first-quarter Short Term Assessment of Reliability (STAR), presented April 7 to the Transmission Planning Advisory Subcommittee. 

Ross Altman, NYISO senior manager of reliability planning, said the city would be deficient by 281 MW for five hours on a hypothetical summer peak day during normal weather conditions if the Gowanus and Narrows peaker units are offline. Both barge-borne floating plants were built in the early 1970s and are owned by AlphaGen. 

The ISO said it continues to believe the plants should be allowed to operate beyond their planned retirement in May, until May 2027 or a “permanent solution” is in place. 

But NYISO also is concerned about unplanned outages at aging plants; the accelerated retirement of other, smaller New York Power Authority gas plants; the impact of heat waves; and delays on the Champlain Hudson Power Express transmission project.  

The status of the fossil fuel fleet and NYISO’s assumptions about their retirements occupied much of the discussion. Altman said the ISO was not forecasting retirements; rather, the intent of the analysis was to understand how many old plants were at risk of failure. 

“What we’re showing with aging fossil fuel [power plants] isn’t purely economic or policy driven,” Altman said. “As complicated, spinning heavy machines age, they are more likely to fail.” 

Chris Casey with the Natural Resources Defense Council asked NYISO to make it clear in the final Q1 STAR report, due to be released by April 14, that it wasn’t talking about normal retirements. He said the language of the presentation made it confusing as to whether the “deactivations” were a normal process or from catastrophic failure.  

Doreen Saia, chair of the energy law practice at Greenberg Traurig, asked whether the ISO was implying with this analysis that it was worried that if a fossil fuel generator went offline, it would not get it back.  

“If that’s part of your analysis, it needs to be said someplace because I think it’s an absolutely fair assumption,” Saia said. “I don’t know why you would think you could get them back in this environment where gas turbines aren’t favored and the owner could very well sell or repurpose their very attractive real estate.”  

NYISO also presented its 2025 preliminary baseline forecast for the next 10 years of load growth for both the winter and summer capability periods.  

The ISO projects roughly 3,700 GWh of large load growth in 2025, mostly concentrated in the North Country and Buffalo. In 2026, roughly 7,800 GWh of large load is forecast to be on the grid.  

These large loads constitute the greatest driver of growth in New York. In the near term, they dwarf both electric vehicle and building electrification forecasts. Economy-driven demand growth is projected to remain relatively low through 2035 because of poor economic forecasts.  

Without the large loads, New York likely would see declines in overall energy consumption because of outmigration and slowing economic growth through 2031. The forecasts did not consider the Trump administration’s tariffs.  

The ISO also expects energy efficiency gains to mitigate load growth, with strong support from behind-the-meter solar and energy storage.  

Casey said he agreed with several skeptical stakeholders that some of the sensitivity scenarios did not present credible possibilities. He went further, saying that given the tariffs from the Trump administration, the baseline forecast could be “way above” reality. 

“There is a realistic possibility that things will stay as they are,” Casey said. “A lot of economic development and large loads that we anticipate coming are not going to come, or are not going to come when they are expected.” 

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BPA Flooded with Comments on Draft Day-ahead Market Decision

The Bonneville Power Administration elicited nearly 150 comments in response to the March 6 draft policy outlining its decision to join SPP’s Markets+ rather than CAISO’s Extended Day-Ahead Market.

BPA’s tentative decision in favor of Markets+ offered little surprise to Western electricity sector stakeholders involved in the development of day-ahead markets in the West.

Still, the draft’s release ended nearly two years of speculation about a potential surprise — or whether the agency might succumb to political pressure and delay its choice to let developments play out around the West-Wide Governance Pathways Initiative’s efforts to bring more independent governance to CAISO’s markets. (See BPA Selects SPP Markets+ in Draft Policy.)

The torrent of comments (so far) have offered few surprises as well, with supporters of each market staking out many of the same positions they’ve voiced since BPA kicked off its day-ahead market participation stakeholder process in July 2023.

RTO Insider’s round-up of the comments is by no means a comprehensive one, but we have sought to include many from key players in the industry and important constituencies. More comments were being posted to the BPA site throughout the day, and we will continue to review them for inclusion in future articles.

BPA officials have said they will respond to the comments and expect the agency to issue its final record of decision in early May.

‘Compelling’ Choice

Unsurprisingly, the consumer-owned utilities (COUs) that make up BPA’s base of “preference” customers largely supported the draft policy and urged the agency to finalize its decision without delay.

A common thread among the COUs backing the draft policy was the market governance issue, with some contending the Markets+ framework provides an independent governance structure that EDAM lacks.

For example, Gary Huhta, general manager at Cowlitz County Public Utility District, urged BPA “to proceed without delay” instead of waiting for the Pathways Initiative to wrap up “development of a partial independent governance structure.”

Pathways is developing a “regional organization” (RO) that will assume governance over EDAM and CAISO Western Energy Imbalance Market.

“BPA’s choice of Markets+ over CAISO’s EDAM is compelling, as its superior independent governance, uniform resource adequacy requirements, [greenhouse gas] design and a congestion revenue mechanism that promotes transmission investments,” Huhta wrote.

Snohomish County PUD shared Huhta’s sentiment. Snohomish noted that for Pathways to succeed, the California Legislature would have to support the initiative. And even if lawmakers back the proposal, Pathways “would not achieve full independence due to the remaining significant intertwining of CAISO and the new regional organization, including shared staffing and a shared tariff.”

“Under the proposal, CAISO would retain the dual roles of a participating balancing authority for one part of the footprint and the market operator for the full footprint that could result in a conflict of interest,” Snohomish contended. “Given the magnitude of trade likely to occur within day-ahead markets, and the potential influence of market rules and market operations over the allocation of costs and benefits of market participation, Snohomish has a strong preference for the fully independent governance structure of Markets+.”

Snohomish also is one of the signatories to the so-called “issue alerts” published recently to highlight the purported advantages of Markets+ over EDAM. (See 7th ‘Issue Alert’ Highlights Markets+ Footprint.)

The Western Public Agencies Group (WPAG), which consists of 27 COUs in Oregon and Washington, supported the draft policy. The organization noted the policy comes as utilities prepare to sign new long-term provider-of-choice contracts slated to go into effect in 2028 and set the conditions under which BPA sells federal power to customers.

“BPA’s proposal to participate in a day-ahead market is the type of strategic progression needed to meet the moment and to secure the region’s long-term future,” WPAG wrote. “What is more, based on BPA’s extensive analysis, Markets+ appears to be the market for the job.”

Vancouver, British Columbia -based energy trader Powerex, a key Markets+ backer, said it “strongly supports” BPA’s draft policy, writing that it “reflects thorough analysis, extensive stakeholder input and a clear understanding of the long-term structural, operational and economic implications of organized day-ahead market participation.”

The company also said it agrees with BPA’s conclusion that the SPP market is the best option “to protect the value” of the federal hydroelectric system and “uphold its statutory obligations, and promote a durable, fair and transparent market platform for Bonneville, its customers and the region.”

‘Ignores the Facts’

But the region’s two largest consumer-owned utilities by number of customers — Seattle City Light and Eugene Water and Electric Board (EWEB) — stood out among COUs in opposing BPA’s draft decision.

“BPA’s decision to join Markets+ does not comply with the agency’s statutory obligation to provide ‘the lowest possible rates to consumers consistent with sound business principles.’ Rather, BPA’s premature decision ignores the facts presented by its own record and analysis,” City Light wrote in comments that extended to 114 pages.

City Light reiterated the key concerns it expressed in a letter to BPA Administrator John Hairston last November after the agency played down the value of the results of a study it had commissioned to compare the potential economic benefits of participating in either market. (See Markets+ Leaning ‘Alarming,’ Seattle City Light Tells BPA.)

“BPA’s own economic analysis indicates that joining the California Independent System Operator’s Extended Day Ahead Market offers the largest benefits to its customers, followed by choosing to not join any day-ahead market,” the Seattle utility said.

City Light said Markets+ “is worse for BPA customers than EDAM by $165 million to $221 million annually — and these losses persist indefinitely into the future,” while continued participation in the WEIM would provide only $79 million to $130 million in greater benefits than joining the SPP market.

The utility also contended “all available analysis” indicates Markets+ will not provide the “well connected and integrated market footprint of diverse loads and resources” needed to deliver the maximum benefits for BPA customers.

“BPA’s decision eschews objective analysis and chooses which factors it elevates based on whether they support its preferred outcome. This is not consistent with sound business principles,” City Light said.

Oregon-based EWEB said it agreed with BPA about the need for independent market governance but contended that issue should not be the “sole factor” in the agency’s decision and “must be carefully weighed alongside the critical elements of transmission connectivity and market footprint.”

EWEB expressed concern about what it said are “the inefficiencies associated with a smaller, disconnected market like SPP’s Markets+.”

Like City Light, EWEB encouraged BPA to continue participating in the WEIM over joining Markets+, giving the agency time “to observe the ongoing evolution of EDAM and its progress toward independent governance.”

“By waiting, BPA can make a more informed, strategic decision that not only aligns with its operational goals but also strengthens regional collaboration. This measured approach ensures that BPA chooses the best long-term market option for both its stakeholders and the broader region,” EWEB wrote.

‘Narrow Set of Interests’

The draft policy also found little support among environmental organizations, with many urging BPA to pause or withdraw its draft decision.

In a joint letter, Earthjustice, the Northwest Energy Coalition and Idaho Conservation League said the proposed decision violates the National Environmental Policy Act and the Pacific Northwest Electric Power Planning and Conservation Act.

The trio argued BPA failed to consider the environmental impacts of its choice in violation of NEPA, noting the agency has committed “up to $40,000,000 as part of the collateral for a bank loan to support the development of Markets+. The promise to pay these funds is irrevocable, and they will be forfeited if BPA withdraws from Markets+. This commitment of resources prior to any environmental review is contrary to NEPA.”

The groups argued BPA violated the latter act by ignoring the “substantial cost savings of a decision to join EDAM” and instead prioritizing Markets+’s governance design. They pointed to two production cost studies showing that EDAM could provide significant savings for BPA customers under certain scenarios. (See BPA Sticks to Markets+ Leaning Despite Study Showing EDAM Benefits.)

In urging BPA to withdraw its draft policy, the groups wrote that the agency’s “response to public input has been minimal, and its decision-making process has been opaque and appears more focused on catering to a narrow set of interests rather than the broader public good. BPA, however, has a legal duty to serve the best interests of the entire Pacific Northwest, including, among others, the region’s energy, environmental and economic interests.”

Other environmental groups similarly opposed the draft decision. Save Our Wild Salmon Coalition, Sierra Club, Oregon Clean Grid Collaborative and Renewable Northwest all opposed the draft decision in separate letters.

The Washington BlueGreen Alliance, a coalition of labor unions and environmental groups, said BPA did not “fully consider” how its decision would affect not just preference customers, but the Northwest region at large.

“We are concerned that the BPA draft decision to join Markets+ is based on an inadequate analysis of each day-ahead market’s governance structure and economic costs to the region, which will have significant consequences for our region’s climate policies and workers,” the group said.

They also argued the “fragmented nature” of the Markets+ footprint is likely to result in a less reliable system or require customers to pay more to ensure uninterrupted delivery.

“Substantial increases in BPA’s costs have a direct effect on industrial manufacturing growth and job creation in our states. These costs will likely be passed on to ratepayers, and the impact will be felt most acutely by large energy users, such as industrial and commercial ratepayers,” the group wrote.

Tribal Perspectives

Many of the region’s tribes had their own reason to oppose BPA’s decision and urge postponement, saying they were unable to provide informed — and legally required — consent because of the agency’s lack of “government-to-government consultation” with tribal representatives.

“The federal government’s trust responsibility obligates BPA to ensure that tribes are full partners in managing the lands and resources that are our ancestral inheritance,” the Snoqualmie Tribe in Washington wrote, adding that “tribal values, priorities and rights must be integrated into the” day-ahead market.

Washington’s Yakama Nation urged BPA to delay until it “has engaged in full in meaningful consultation” with the tribe to ensure that participation in a day-ahead market does not “negatively impact” the Yakama’s treaty-reserved resources and rights.

The Confederated Tribes of the Umatilla Indian Reservation expressed similar concerns, pointing to potential risks to its members’ fishing rights on the Columbia River from changes in BPA’s operations.

The Alliance for Tribal Clean Energy echoed those concerns, while also contending BPA’s decision was “rushed.”

“BPA’s accelerated timeline precludes the thorough evaluation of alternative market options that might better align with tribal interests and environmental considerations,” the alliance wrote.

Tech Views

Tech companies and data center developers, including Google, Amazon, Microsoft and Rivian, signed a letter by the Clean Energy Buyers Association asking BPA to postpone its decision.

The companies contended more analysis is needed to consider studies that show a “wide range of potential outcomes, especially the potential for increased systems costs, creates confusion and significant uncertainty for ratepayers.”

“Retail customers in Bonneville’s service territory deserve greater assurance that participation in a [day-ahead market] will not drive undue costs, ultimately borne by ratepayers,” the companies wrote.

They also wrote BPA should wait until the outcome of Pathways, while noting that staffing issues at BPA pose challenges. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)

Amazon, which has invested billions of dollars toward the development of data centers in Oregon, issued a separate letter. The company said BPA’s justification for its draft policy “is not sufficient to meet the important threshold of ratepayer protection, particularly in light of other market options available, some of which have been reported by Bonneville studies to save customers hundreds of millions compared to the Southwest Power Pool’s Markets+.”

The company said BPA should hold off on joining a day-ahead market and remain in CAISO’s WEIM while it evaluates its options.

‘Seamless’ Market

CAISO weighed in as well, noting the estimated $97 million in benefits BPA has earned since joining the WEIM in 2022 and pointing to that market’s contribution to increasingly coordinated transmission flows across the Northwest, which it said has resulted in $1.5 billion in estimated benefits for the entire region.

“The seamless real-time operational market created between the Pacific Northwest and other WEIM balancing areas in the West has also become an invaluable tool in supporting system reliability, especially during stressed system conditions, which have increased in frequency and intensity in recent years,” CAISO wrote.

CAISO also questioned BPA’s treatment of the governance issue in its draft, saying the document does “not fully present and consider the enhancements to the ISO’s market governance that will take effect upon implementation” of the Pathways Initiative’s “Step 1” changes to that governance.

The ISO said BPA’s draft also neglected to discuss “limitations” SPP has placed on the governance authority of the Markets+ Independent Panel, an issue important for “comparative governance analysis.”

“While the [Markets+] tariff contemplates that the SPP board will give significant deference to the MIP’s decisions, the SPP board nonetheless retains broad authority to overturn such decisions,” CAISO wrote.

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Trump Seeks to Keep Coal Plants Open, Attacks State Climate Policies

President Donald Trump signed a series of executive orders April 8 that seek to keep existing coal-fired power plants running, ease regulations and permitting for coal mining, and remove “unlawful and burdensome” state laws that impede the industry. 

The president also issued a proclamation that coal plants be exempt from the latest iteration of the Mercury and Air Toxics Standard, which the White House said will ensure they are not prematurely closed. 

“For four long years, Joe Biden and congressional Democrats tried to abolish the American coal industry,” Trump said at a White House ceremony flanked by coal miners. “They did everything in their power — while he was awake, which wasn’t much — shutting down dozens of coal plants, upending coal leases on federal lands, and putting thousands and thousands of coal miners out of work.” 

Trump ordered the secretary of energy to use Federal Power Act Section 202(c), which is meant to be used as a backstop to keep plants running for reliability even if that violates environmental rules, in a much broader way than previously used. 

The president also called on the Department of Justice to go after “unconstitutional” state laws that limit the use of domestic energy resources, including coal and other fossil fuels. 

The final order is titled “Reinvigorating America’s Beautiful Clean Coal Industry” and includes measures to open more federal land to coal mining. 

The White House’s fact sheets tied to the announcements cite the recent return to demand growth from the expansion of data centers, which are expected to drive up overall demand by 16% in the next five years. They also call coal “essential” to the power grid, making up 16% of total generation, which is down from 52.8% in 1990, according to the Energy Information Administration. 

Coal generation has been on a steady decline since 2007 when it produced 2,016 billion kWh, falling to just 675 billion kWh in 2023, according to EIA. 

“It is highly unlikely, in fact, probably zero probability, that anyone will ever build a new coal plant,” energy consultant Alison Silverstein said in an interview. 

Coal generation is more expensive to build than natural gas, which is facing stiff competition on its own from renewables in the markets. The best any policies can do would be to keep coal plants running longer, and that means going against decades of efforts to clean up the grid, Silverstein said. 

Silverstein wrote a report for the Department of Energy in Trump’s first term when then-Energy Secretary Rick Perry submitted a Notice of Proposed Rulemaking with FERC that would have had grid operators pay coal plants their full operating costs. Her report said that was not needed, and FERC voted the proposal down unanimously 5-0 after several of Trump’s appointees had taken office. 

FERC is not the focus of the current efforts, though some of the executive orders indicate the cabinet secretaries could consult with the agency as the policies are implemented. 

The executive order on “Strengthening the Reliability and Security of the United States Electric Grid” directs Energy Secretary Chris Wright to “streamline, systemize and expedite” the Department of Energy’s process for issuing orders under Section 202(c). It gives the secretary 30 days to review and analyze forecasted reserve margins for all regions of the bulk power system regulated by FERC to identify those with margins “below acceptable thresholds as identified by the secretary.” 

DOE will have to release that analysis in 90 days and then use it to identify at-risk plants of 50 MW or above. It then will use its 202(c) authority to prevent them from leaving the grid, or from converting fuel sources if that leads to a net reduction in generating capacity. 

Recent uses of Section 202(c) have focused on maintaining reliability in extreme weather, and in many cases it was in effect only for days, according to DOE. A famous case from 20 years ago kept a plant in Alexandria, Va., open to avoid blackouts in D.C., including the White House (EL05-145). 

One issue that will have to be addressed is what compensation coal plants required to stay online are due. Most of the existing coal fleet already is uncompetitive and most are inefficient, Silverstein said. 

“Keeping them running is costing the local utility ratepayers money because it is more expensive to buy coal production and to keep the coal plants running than it is to buy in the market from renewables or gas,” Silverstein said. “So, the thing that they are doing is essentially keeping these plants going by raising everybody’s costs.” 

“Protecting American Energy from State Overreach” directs the Department of Energy to go after state policies that “target or discriminate against out-of-state energy producers.” The order specifically calls out climate policies enacted by California, New York and Vermont. 

“These laws and policies also undermine federalism by projecting the regulatory preferences of a few states into all states,” the order says. “Americans must be permitted to heat their homes, fuel their cars and have peace of mind — free from policies that make energy more expensive and inevitably degrade quality of life.” 

The order calls on Attorney General Pam Bondi to identify all such state laws and to prioritize challenges to laws purporting to address climate change, environmental justice, carbon or greenhouse gas emissions, and funds to collect carbon penalties and taxes. “The attorney general shall expeditiously take all appropriate action to stop the enforcement” of such state laws and file a report in 60 days on those efforts, which will include recommendations for additional executive actions or legislative measures.” 

Reactions to the executive orders were mixed, with some saying they will help maintain reliability and others saying they are bad for the environment and consumers. 

National Rural Electric Cooperative Association CEO Jim Matheson and co-op executives from around the country were at the White House in support of Trump’s actions. NRECA members own at least part of 79 coal units with 21 GW of capacity, and 11 of them, totaling 3 GW, are scheduled to retire between now and 2030. 

“At a time when electricity demand is skyrocketing, we need to be adding more always-available energy to the grid, not shutting down power plants that have useful life left,” Matheson said in a statement. “Electric co-ops provide reliable power to communities across the country. Today’s announcements help drive home smart energy policies that will support efforts to keep the lights on at a price families and businesses can afford. We thank the administration for recognizing the continued importance of always-available resources in the nation’s energy mix.” 

Rep. Julie Fedorchak (R-N.D.), who was president of the National Association of Regulatory Utility Commissioners before assuming office this year, also praised the action, having introduced a resolution warning about growing demand and retiring plants April 7. 

“At a time when reliable baseload power is being shut down without adequate replacement, his executive orders are exactly what we need,” Fedorchak said. “With electricity demand from AI and data centers surging, the U.S. urgently needs always-available power — and that’s what coal provides, especially the mine-mouth coal power we produce in North Dakota.” 

Environmental Defense Fund Director Ted Kelly blasted the orders, saying that they could not overcome the market realities faced by coal. He also took issue with the use of FPA Section 202(c) and vowed to oppose the White House’s efforts. 

“That law is designed for, and limited to, sudden emergencies creating an immediate risk of blackouts or other grid instability, such as storms, wildfires or sudden major infrastructure failures,” Kelly said. “It is time-limited for the same reason, and it further limits any power generation that conflicts with environmental laws or regulations to the minimum hours needed to address the emergency. Changes to the power system over time, like load growth driven by data centers or power plant retirements driven by economics, are properly addressed by planning and action by utilities and their regulators — not by irrational and unlawful emergency actions.” 

Based on the market realities and likely challenges from EDF or Democratic state attorneys general, Silverstein predicted this second-term effort to bail out coal would wind up much like the failed NOPR from Trump’s first term. 

“This particular effort, I think, is going to have more grandstanding impact than actual impact,” Silverstein said. “I think it will affect a few coal plants and a few coal-mining and coal-plant communities, and it’s going to raise costs for everybody. But it’s hard to imagine any data center wanting to sign a contract with a 60- to 80-year-old coal plant.”