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December 11, 2025

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ISO-NE Monitor Discusses Market Trends, Energy Transition

BOSTON — The New England wholesale electricity markets performed competitively in 2024, while decreased imports and higher emissions compliance rates increased overall market costs, the ISO-NE Internal Market Monitor told the NEPOOL Participants Committee on Sept. 4. 

David Naughton, executive director of the IMM, discussed the group’s 2024 annual report, which originally was published in May. 

The IMM found that wholesale market costs totaled about $10.2 billion in 2024, up by about $1 billion from 2023. This increase largely stemmed from higher energy market prices, which were caused by greater emissions compliance costs and a significant drop in imports from Quebec, which caused the region to rely more heavily on higher-priced natural gas generation, Naughton said. (See Drought, Climate Drive Uncertainty on New England Imports from Québec.) 

Regional Greenhouse Gas Initiative (RGGI) costs increased by about 55% in 2024 compared to 2023, he noted, adding that this increase was offset partly by a 61% decline in Massachusetts’ cap-and-trade program. Overall, carbon compliance costs totaled $509 million for New England generators, Naughton said. This translated to $910 million in added wholesale market costs, as higher marginal resource costs increased the clearing price paid to all participants. 

He noted that the New England states reinvest most of the RGGI proceeds in energy efficiency programs, which help mitigate the cost impacts of carbon prices. 

“These energy efficiency programs saved approximately 17.5 TWh in energy, or roughly $757 million in wholesale energy market costs based on the 2024 LMP,” the IMM wrote in its annual report. 

In 2025, wholesale costs are on track for a significant year-over-year increase, largely from low winter temperatures and periods of extreme heat in the summer, Naughton said. 

He noted that market revenues in 2024 were lower than the cost of entry for most new resources.  

“Market-based revenues in 2024 were below the going-forward costs of new entrant gas-fired generators,” Naughton said. Market revenues for wind and solar resources also were well below the CONE, and these resources remain heavily reliant on state programs, he added. 

Naughton also noted that, while combined cycle plants generally earn more from the capacity and ancillary service markets than in the capacity market, fossil peaker plants are increasingly reliant on capacity market revenues. 

2024 net market revenues for fossil generators | ISO-NE

“These observations indicate that some older, less efficient units could face exit decisions if current market conditions persist, especially when faced with large capital and fixed operating expenses,” the IMM wrote in its report. 

Naughton said the IMM has seen “gradual” impacts of the clean energy transition so far on supply and demand. Average solar output in the region doubled between 2020 and 2024, but wind output remained stagnant during this period. 

Behind-the-meter solar growth has led to a growing duck curve in the region, with mid-day demand frequently dropping below nighttime levels. This has caused growing morning and evening ramp requirements and is beginning to present increased arbitrage opportunities for energy storage resources, Naughton said. 

While the saturation of the storage market has led to declining regulation revenues, energy market revenues have started to tick up for storage resources, he said. 

Recommendations

Naughton also discusses the IMM’s recommended market changes, which include a proposal to subject exports to pay-for-performance (PFP) penalties during capacity scarcity events. 

PFP payments are intended to incentivize resource performance during capacity shortages. While imports receive the PFP rate and LMP, “exporting-only participants are only charged the LMP,” Naughton said, adding that this “over-incentivizes procuring imports” instead of limiting exports. 

He said participants that both import and export power during a scarcity event are subject to PFP netting rules, but there could be a “gaming opportunity” for related companies to schedule imports and exports during a scarcity event and profit without delivering actual energy. 

To fix this issue, the Monitor has recommended that ISO-NE “apply the PFP rate symmetrically to exports, aligning financial incentives and ensuring that external transactions — whether imports or reduced exports — are valued equally for their contribution to system reliability.” 

Net market revenues for battery storage resources | ISO-NE

Responding to the proposal, some stakeholders expressed a concern about applying the PFP to capacity-backed exports and asked ISO-NE to exempt them from performance penalties. 

The Monitor has recommended that ISO-NE update its bidding software “to allow low-cost resources to more easily submit real-time specific offers” and change the external interface clearing rules “to reduce incentives for strategic virtual bidding and incentivize participants to submit more accurate, cost-reflective offers closer to the operating day.” 

Asset-condition Review

During the MC meeting, ISO-NE COO Vamsi Chadalavada discussed the RTO’s work to establish an asset-condition reviewer role.  

The RTO has agreed to pursue this role at the urging of states and consumer advocates and with the agreement of the transmission owners. It has stressed it will not take on a regulatory function investigating the prudence of investments. Instead, its role would be aimed at increasing transparency into projects and could, hypothetically, provide information that would aid stakeholders in prudence challenges with FERC. (See ISO-NE Open to Asset Condition Review Role amid Rising Costs.) 

Chadalavada said ISO-NE’s work is complicated by the fact that no similar role exists elsewhere in the U.S., requiring the RTO to develop these capabilities from scratch. Once developed, the role could serve as an example for the rest of the country, he added. 

He noted that ISO-NE has hired Electrical Consultants Inc. to “help develop a framework for a new asset-condition reviewer role,” as well as to “review selected asset-condition projects in the interim review cycle, through the end of 2026.” 

ISO-NE stillis working to determine which projects it will include in this interim review process generally but will focus on high-cost or abnormal projects, he said. 

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Tri-State Seeks FERC Approval for Data Center Load Tariff

Tri-State Generation and Transmission is seeking FERC’s approval for a new tariff designed to manage the heavy volume of data center load expected to materialize in its member utilities’ service territories over the next decade (ER25-3316). 

The filing is part of a growing trend among utilities and states in crafting policies to protect ratepayers from the financial — and reliability — risks stemming from the voracious energy demands of new artificial intelligence data centers. (See related story, Large-Load Tariffs Touted as Alternative to ‘Side Deals’.) 

The proposal is the product of “months of collaboration with members and stakeholders,” the Colorado-based cooperative said in an Aug. 29 press release. 

“The proposed tariff is designed to establish a repeatable and fair process for incorporating high-impact loads onto the Tri-State system without adverse impacts to reliability or affordability,” Tri-State said. “The process would allow Tri-State members to respond in a consistent manner to requests for services from heavy energy users, such as data centers.” 

“We’re in the business of providing electricity, and we are committed to doing it in a way that can meet the needs both of new loads and Tri-State members,” said Lisa Tiffin, Tri-State’s senior vice president of energy management. “This approach allows us to grow responsibly and limits the potential for stranded assets that could result in financial risk to Tri-State and our members.”   

Tri-State is a power supply cooperative that serves electric distribution cooperatives and public power districts across four states. It said in its filing with FERC that new load requests from data centers among its members would, over the next 10 years, more than double its current system peak demand of 2.5 GW. 

In the filing, Tri-State noted that data centers “support local economic development, improve the efficient utilization of utility resources and provide steady revenue streams when fully integrated into a service provider’s system.”  

But it also warned that integrating such large loads also “carries risks,” including the need to build new transmission lines and generation, and the potential for increasing interconnection queue backlogs and delays in procuring needed resources. 

“Large load interconnections also present serious reliability and cost-shifting risks for a utility’s customers,” Tri-State added. 

Tri-State’s existing Electric Resource Planning (ERP) process, designed for a more measured rate of native load growth, is not equipped to handle those risks and the expected pace of new demand from what the co-op calls high-impact load (HIL) projects, it explained in the filing. 

“HIL projects are more speculative than utility members’ prior requests for new or modified delivery points, or native load growth in general. HILs also require accelerated and significant transmission upgrades that do not fall neatly into the existing ERP process,” Tri-State said. 

‘Avoid Socializing the Risk’

Tri-State’s proposed High Impact Load Tariff (HILT) would provide an alternative planning approach for integrating those loads into its system. 

According to the filing, the “guiding principles” for the HILT are: “(1) facilitating economic development across Tri-State’s utility members’ systems at an unprecedented level and pace; (2) limiting the risk of stranded assets resulting from high-impact load integration, which could create financial risk for Tri-State and its utility members; and (3) continuing to meet all resource planning and associated regulatory requirements.” 

Modeled on similar tariffs filed by other U.S. utilities, the Tri-State HILT would establish a biennial planning cycle for customer loads rated at 45 MW or higher. 

“This separate HIL planning cycle process is necessary because HILs are of a size that require significant generation capacity additions or procurement of long-term [power purchase agreements], which necessitates proper planning. Ratepayers may suffer financial consequences if capacity additions are completed only for a HIL to not materialize,” Tri-State wrote. 

Each planning cycle would begin with a “kickoff” meeting among Tri-State, co-op members and potential HIL customers, where participants will “set forth the requirements and timing for a HIL participation package [prepared by the utility member], a process for verifying the participation package components are met and a HIL evaluation process.” 

Intended to ensure that only non-speculative projects are presented to Tri-State for study, the participation package would include:  

    • a completed member project request form; 
    • evidence that the HIL customer has at least 90% site control over its project location; 
    • payment of a nonrefundable HIL evaluation fee; 
    • a certified engineering diagram of the project’s expected load and property acreage; 
    • an executed member-customer high-impact load (MCHIL) agreement; and 
    • a high-impact load agreement (HILA) to be executed between the utility member and Tri-State. 

For HIL requests under 80 MW, the evaluation fee would start at $35,000 plus $1,000/MW, increasing to $150,000 for projects between 80 and 200 MW, and $250,000 for projects above 200 MW — levels Tri-State said are consistent with the megawatt deposit thresholds under its large generator interconnection procedures.

Tri-State said the evaluation process would focus on “reliability, economic and environmental criteria, as well as transmission metrics.” 

“The reliability review will ensure the HIL will not have an adverse impact on the reliable operation of Tri-State’s system, including compliance with Level I (base metrics) and Level II (extreme weather events) reliability metrics. The economic criteria focus on whether the HIL project is economically priced so as to minimize Tri-State’s system costs, and reduce or maintain Tri-State’s rate requirements,” the co-op said. 

The proposed HILA would include “minimum billing demand and energy floors” intended to ensure that, regardless of whether a HIL customer’s load grows as forecast, Tri-State is compensated for system upgrades sufficiently enough to avoid shifting costs to other customers. 

The HILA also would stipulate that a HIL customer provide a minimum security deposit of $2.7 million/MW to offset the risk that “the HIL customer begins commercial operations late [or] ceases operations before the expiration of the HILA term or the HIL does not operate at the expected level (or at all). In short, the security requirement enables Tri-State to avoid socializing the risk of the HIL customer’s under- or nonperformance across Tri-State’s entire membership.” 

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Large-load Tariffs Touted as Alternative to ‘Side Deals’

As regulators grapple with rate design for large-load electricity customers such as data centers, some experts are pointing out the transparency benefits of tariffs compared to special contracts between the utility and customer.

“We don’t like these side deals,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “We think putting in place data center tariffs is better. It’s more transparent. It encourages robust participation in the process in developing these tariffs.”

Peskoe was a speaker during a Sept. 2 New Mexico Public Regulation Commission (PRC) workshop focused on large-load rate design. He gave an overview of a paper released in March on “How Utility Ratepayers Are Paying for Big Tech’s Power.”

Peskoe and co-author Eliza Martin reviewed 40 state utility commission proceedings regarding special contracts with data centers. They found that regulators often “reflexively” grant a utility’s request to keep the proposal confidential, and then “frequently approve special contracts in short and conclusory orders.” That’s in contrast to rate cases, which draw robust stakeholder engagement, according to the researchers.

Utility tariffs typically detail the price, conditions and terms of electricity service to customers and must be approved by regulators. In contrast, special contracts often are a bilateral agreement negotiated by the utility and the large customer, according to Natalie Frick, an energy policy researcher in the Energy Markets and Policy Department at Lawrence Berkeley National Laboratory.

“One of the big complaints about special contracts is that there’s a lack of transparency,” Frick said in a presentation to the PRC. “They’re often confidential, and so there’s less public scrutiny about them.”

Frick cited as an example an approved special agreement between Meta and Duke Energy Indiana.

“You don’t know how much capacity was being procured, you don’t know where it’s being procured [from], you don’t know what the demand fee or energy charge was,” she said. Frick noted that a consumer advocate was able to review the confidential information and found the deal didn’t increase costs for other customers.

Grid Readiness Proceeding

The Sept. 2 workshop was part of the commission’s proceeding on grid readiness and economic development.

“Data centers are a big topic,” said Commissioner Pat O’Connell, noting that the centers create challenges for the electric industry. “On balance, the need for data centers is real, and having them in the United States is valuable. So it’s a problem that’s worth solving.”

The commission is considering whether a large-load tariff could help address some of the issues.

“For me, it’s a lot about a fair allocation of cost to ratepayers, and a fair opportunity for large customers to interconnect and start receiving power from the utility,” said commission Chair Gabriel Aguilera. “A tariff — would it make it easier for a large customer to know what to expect?”

Aguilera said one option would be to form a stakeholder group to work on a proposed large-load tariff and associated agreements, focusing first on minimum requirements.

Frick and other Berkeley Lab researchers released a technical brief in January titled “Electricity Rate Designs for Large Loads: Evolving Practices and Opportunities.” The Brattle Group and U.S. Department of Energy helped with the research.

The report examined 11 large-load tariffs across the U.S. The minimum size to be eligible for the tariff varied, according to Frick’s presentation. In the case of Black Hills Power’s Economic Flexible Load Service, the minimum is 10 MW, while We Energies’ very large customer tariff has a minimum of 500 MW aggregated.

Some tariffs include an exit fee for ending service early. Ohio Power’s data center tariff settlement agreement proposed an exit fee of three years of minimum charges.

Frick said most of the tariffs have a ramping schedule, in which customers consume an increasing amount of their capacity over time.

In some tariffs, large-load customers may resize the load they plan to take, without penalty, if they find out before a certain deadline that they need less than they expected.

And sometimes tariffs and special contracts are used together, she said.

What’s the Goal?

In Nevada, when a large customer wants to take service under one of NV Energy’s large-load tariffs, the utility files an energy supply agreement (ESA) with the Public Utilities Commission of Nevada, said Karen Olesky, an economist with the PUCN’s regulatory operations staff.

The tariff states what should be in the ESA and in the ESA application, while providing some flexibility, Olesky said. Customers might have different energy needs — such as a data center versus a sports stadium — or different renewable energy goals, she said.

NV Energy’s large customer tariffs include the clean transition tariff, which the PUCN approved in March. It’s a framework developed in partnership with Google that will allow the utility’s existing large-load customers to receive power from new clean energy resources. (See Nevada Regulators Give Nod to NV Energy Clean Transition Tariff.)

The clean transition tariff was modeled on NV Energy’s Large Customer Market Price Energy tariff, which is available only to new customers.

Olesky said regulators should start by considering what they want to accomplish with a large-load customer tariff. That might be attracting new load to the system, lowering rates for large customers or helping a large customer meet renewable energy goals that are beyond renewable portfolio standard requirements.

Determining the tariff’s purpose will help regulators decide the acceptable level of subsidy from other customers, she said. “Is it zero?” Olesky said. “Or is the ultimate goal to bring new load at all costs, so having non-participating customers pay something for this is OK?”

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MISO: Market Platform Replacement will be Overbudget, Stretch into 2028

MISO said its nine-year effort to replace its market platform will exceed original budget contingencies and will not be completed until 2028, three years later than it previously predicted.

Chief Digital and Information Officer Nirav Shah said at a Sept. 4 meetup of the MISO Board of Directors’ Technology Committee that the RTO now expects the full integration of a new, real-time market clearing engine to extend into 2028.

In early 2024, MISO expected to have all projects associated with its new, modular market platform fully operational in late 2025. When MISO announced the project in 2017, it estimated it could migrate to the new modular computer system by 2023. (See New MISO Day-ahead Market Engine to Emerge Soon After Delay and MISO Sets Sights on 2025 Completion for New Market Platform.)

Shah said the overall cost of the platform overhaul has increased to about $175 million “due to the complexity of completing the real-time market clearing engine.” He said he would have more details on the higher costs of the project later in 2025. MISO originally allotted $130 million for the platform swap with a 25% contingency.

“I look back to 2017, and we’re in a very different place. A lot has changed,” Shah explained. He said technology functions differently now than when MISO announced the replacement project nine years ago. He also said FERC has released several orders with new requirements in that time frame, such as real-time ambient-adjusted line ratings under Order 881.

Shah said that overall, requirements on the market platform replacement are 11% higher than when MISO first gauged them.

“It’s a pretty disappointing miss this late in the project,” said Director Todd Raba, who added that “one of these days,” he’d like to see an IT project end on time and on budget.

Director Theresa Wise said the market platform replacement can be thought of as “a series of projects over time,” with the final projects having vastly different parameters than MISO originally anticipated. Wise said the last two projects are significantly larger with more requirements.

“I think we’re clouding things together,” Wise said in defense of the project’s progress.

Shah said vendors originally estimated the look-ahead commitment component of the project to be about $7 million in 2017. The effort now is predicted to cost about $16 million. He also said the new unit dispatch system has gone from an $8 million estimate to more than $18 million.

MISO CEO John Bear said the RTO probably should have “recast” and repriced the remaining elements of the platform replacement around 2021 to capture rising technological complexities and inflation.

“We didn’t do that, and I want to apologize for that. … Time is not your friend on these projects,” Bear said.

Bear, however, stood by the project even with the late-stage additional costs.

“If you step back from this … the value from the project is still there, even with the increases. The benefits overall are going to be enormous,” Bear said.

For nearly a decade, MISO leadership has said that the current, monolithic market platform — built using technology from the 1990s — is poised to become so obsolete that it won’t be able to clear the day-ahead market or accommodate the more scattered, numerous generation assets that the fleet transition has introduced. (See MISO Makes Case for $130M Market Platform Upgrade.)

Director Erik Takayesu asked if the vendors on the market platform replacement are taking responsibility for some overages. The replacement is being completed with vendors General Electric and Siemens.

“We absolutely are pushing back on the vendors,” Shah said. He said that, for instance, MISO refused to take on additional costs of “poor architecture decisions” that necessitated a redesign on some of the look-ahead commitment components.

“It absolutely is making them uncomfortable, but that’s the right thing for our stakeholders,” Shah said.

MISO estimated it will take until 2026 for the look-ahead commitment software to enter final testing and parallel operations. By 2027, the RTO estimates it would be able to test its new unit dispatch system and enter it into parallel operations.

Through the remainder of 2025, MISO plans to begin testing the look-ahead commitment software and launch its new one-stop model manager so it can cease operations of its old, siloed modeling systems. Shah said MISO had to work through some data quality issues as it migrated data to the new management system. The RTO’s model manager project aims for one system of record for all planning and operations models to eliminate redundant data entry and review.

MISO also said the technology to use real-time AARs is in the testing stages for the remainder of 2025, with production still on track for 2026.

Over 2024, the RTO entered its new day-ahead market clearing engine into standalone production and retired its legacy day-ahead market.

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Senators Focus on FERC’s Independence at Swett, LaCerte Confirmation Hearing

Laura Swett and David LaCerte took questions on FERC’s independence during their confirmation hearing before the Senate Energy and Natural Resources Committee as the country debates how much control the president should have over the federal bureaucracy.

Swett and LaCerte were nominated by President Donald Trump to replace former Chair Mark Christie and former Commissioner Willie Phillips. Trump has asserted broad authority over the entire executive branch, including independent agencies such as FERC and the Federal Reserve. (See FERC’s Independence Likely Coming to an End with Christie’s Exit.) Trump’s attempts to fire several agency officials have set off numerous legal battles.

Committee Chair Mike Lee (R-Utah) said at the Sept. 4 hearing that the confirmation process will allow senators to hear about how the two “view the ongoing legal debate about the status of so-called ‘independent agencies’ and what that means for accountability to the law and to the American people.”

Lee said he’s skeptical of the concept of agency independence and has made it clear he would welcome the Supreme Court overturning Humphrey’s Executor v. United States, the 1935 case in which the court found that it was constitutional for Congress to pass laws limiting the president’s ability to fire members of independent agencies.

Democrats on the committee were much more critical of the possible change.

“The commission was designed to serve no president, no political party and no political agendas,” Ranking Member Martin Heinrich (D-N.M.) said. “Its job is to serve the public interest fairly and impartially, guided by our laws and the Constitution, not by political whims from the White House. The independence of our independent public institutions, from the Federal Reserve to the Smithsonian Institution, is under attack by this administration, and destroying the independence of the Federal Energy Regulatory Commission would do irreparable damage to public confidence in the commission’s decision-making, to regulatory stability and to our energy security.”

So far, the Trump administration has tried to control other independent agencies more than FERC, but it was widely reported that the administration pressured Phillips to resign earlier this year, which he did. (See Commissioner Willie Phillips Announces his Resignation from FERC.)

“If I have the honor of being confirmed, I will do everything in my power to honor the law and the facts of every single matter before me squarely within the confines of the laws that you, Congress, granted FERC,” said Swett, an energy attorney at Vinson & Elkins. Many FERC watchers expect her to be named chair upon her confirmation.

Swett listed three goals for her tenure on FERC: maintaining reliability; meeting the rising demand from artificial intelligence and data centers to ensure the U.S. leads on that technology; and maximizing the commission’s ability to facilitate infrastructure development.

Swett has been a staffer at FERC and has litigated before the commission, but LaCerte has little experience with the agency — though he has worked on independent regulatory agencies and is familiar with issues surrounding LNG.

“I think my background, especially as a government executive, and my experience as an environmental attorney provide strong qualifications and a fresh perspective on these issues challenging the FERC,” said LaCerte, a senior adviser to the director of the Office of Personnel Management. “The outstanding career staff cannot do this alone; as the committee has noted, FERC is most functional with a fully seated board of complementary commissioners prepared to work together, along with stakeholders.”

Lee asked LaCerte how his background prepares him for a role on the commission when he has comparatively little experience as an economic regulator of electricity and natural gas.

“I think that the most important qualification I have is that I can bring a common-sense approach to get problems solved,” LaCerte answered. “And I’ve proven that to the president of the United States. I have an outstanding set of experiences in safety, in cyber and in a multitude of issues that can help FERC.”

When asked later on about his qualifications, LaCerte argued the fact he has never litigated before FERC could be viewed as a positive, because “regulatory capture” is a legitimate concern.

Lee then asked the nominees for their views on Humphrey’s Executor. Both said they would follow the law.

“And of course, I will follow the law and honor the law in everything that I do and consider the merits of every single issue of law and the facts before me, irrespective of where the litigation comes out and the length of my term,” Swett said.

Heinrich brought up the Trump administration’s executive order seeking to review major decisions at independent agencies and asked why maintaining FERC independence is “critical.” (See Trump Claims Authority over Independent Agencies in Executive Order.)

Congress created the modern iteration of FERC with the Department of Energy Organization Act, which calls for its independence and provides that none of its work is reviewable by anyone at the department, Swett said.

“And thus, as a lawyer who has been practicing FERC law for 15 years, I will always go back to the statute, and that is exactly what Congress directed, and I will not exceed that jurisdiction,” she added.

The Administrative Procedure Act (APA) also governs how FERC works, and Sen. Catherine Cortez Masto (D-Nev.) argued that nothing in the law allows for the White House to review decisions from independent agencies.

“There’s no requirement by the president to review anything that we have set laws for a regulatory agency to do, but that’s what he has put in this executive order, and that’s my concern,” Cortez Masto said.

Ultimately, Cortez Masto noted the issue of the legality of independent agencies is before the courts. Before gaveling the hearing to a close, Lee noted that the APA also does not specifically bar White House review of agency decisions.

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Revolution Wind Sues to Lift Federal Stop-work Order

Revolution Wind is seeking an emergency injunction against the federal stop-work order slapped on its offshore wind project. 

The Bureau of Ocean Energy Management’s Aug. 22 order was arbitrary and capricious, violated the due process clause of the Fifth Amendment and is beyond statutory authority, attorneys argued in a complaint filed Sept. 4 in the U.S. District Court for the District of Columbia (1:25-cv-2999). 

The project off the southern New England Coast would send 704 MW at peak output to Connecticut and Rhode Island. BOEM approved it two years to the day before the stop-work order, and construction is 80% complete. Developers say they have spent or committed more than $5 billion so far on Revolution Wind and had expected a first-half 2026 commercial operation date. 

Also Sept. 4, the attorneys general of Connecticut and Rhode Island announced a lawsuit in U.S. District Court for the District of Rhode Island seeking to overturn the stop-work order. 

Developer Ørsted said in a news release that while Revolution Wind would seek to work collaboratively with the administration and other stakeholders for a prompt resolution, litigation is necessary due to the substantial harm the stoppage inflicts on the project. 

The new litigation is the latest step in what largely has been a one-sided battle over U.S. offshore wind energy development that began a few hours after the inauguration of President Donald Trump, an outspoken opponent of the technology. 

Trump’s executive actions and his Cabinet’s multitude of policy adjustments have made it unlikely any new construction will start during his term, but he has been more ambiguous about the five projects already under construction in U.S. waters. 

A previous stop-work order against Equinor’s Empire Wind in April was widely seen as an attempt not to kill the project but to twist New York’s arm to reconsider previously rejected gas pipeline proposals. Equinor lost millions of dollars in the monthlong stoppage; it threatened to take the administration to court but never did. 

Some have speculated the Revolution stoppage is Trump’s attempt to twist the arm of Denmark, which owns a majority of Ørsted and also controls Greenland, which Trump covets. 

But if there is such an ulterior motive, it has not been stated. Connecticut Gov. Ned Lamont (D) has said he thinks there is one but needs to find out what it might be. 

The stop-work order references national security interests, and Interior Secretary Doug Burgum later offered a vague explanation in a CNN interview about the wind power array interfering with defense against submarine and aerial drone attacks.

Revolution Wind occupies a seabed lease awarded in September 2013. Ørsted and its partners — first Eversource, now a consortium led by Skyborn Renewables — spent years preparing the project. 

The complaint states that every conceivable aspect of construction was reviewed by 15 state and federal agencies (including the Department of Defense) during three presidential administrations, resulting in more than 20 local, state and federal permits and approvals. 

The stop work order does not accuse Revolution of violating any law or condition of approval, the complaint states, and is unlawful, lacks evidentiary basis and was issued without statutory authority. 

The attorneys general, meanwhile, say the stop-work order did not identify any violation of law or imminent threat to safety. 

“Revolution Wind is fully permitted, nearly complete and months from providing enough American-made, clean, affordable energy to power 350,000 homes,” Connecticut Attorney General William Tong said. “Now, with zero justification, Trump wants to mothball the project, send workers home and saddle Connecticut families with millions of dollars in higher energy costs. This kind of erratic and reckless governing is blatantly illegal, and we’re suing to stop it.” 

Rhode Island Attorney General Peter Neronha cited the Trump administration’s “all-out assault” on wind energy: “Just yesterday, we learned of reports that the administration is pulling in staff from several different unrelated federal agencies, including Health and Human Services, to do its bidding. Does this sound like a federal government that is prioritizing the American people? This is bizarre, this is unlawful, this is potentially devastating, and we won’t stand by and watch it happen.” 

National trade group Oceantic Network does not comment on active litigation, so it had nothing to say Sept. 4 about Revolution Wind’s court filing, but it reinforced its longstanding message about the importance of offshore wind in general and Revolution Wind specifically to the American economy. 

Various media outlets have placed the project cost at $4 billion or $6 billion. Ørsted will not provide an exact cost but said in the Sept. 4 court papers it has cost $5 billion so far and said Aug. 25 that the combined investment in its two active U.S. offshore wind projects — Revolution and Sunrise — is expected to be in the $16 billion range. 

Oceantic pointed out the secondary benefits of all this: 183 Revolution Wind supply contracts for 179 companies in 34 states, with over $1.4 billion in related investments and 2,500-plus American jobs supported. 

The renewable energy industry has been making similar statements about the sector’s importance to the grid and to the economy since Election Day, but that has had minimal effect — Trump and his Cabinet and his congressional allies have loosed a flurry of actions to stymie solar and especially wind development. 

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CISA, International Partners Publish SBOM Guide for Industry

Seeking to help address software supply chain vulnerabilities, the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and international partners released a document Sept. 3 highlighting the benefits of software bills of materials (SBOMs) for both the private and public sectors.

CISA developed the report, “A Shared Vision of Software Bill of Materials for Cybersecurity,” alongside the National Security Agency and the agency’s counterparts from Australia, Canada, the Czech Republic, Slovakia, France, Germany, India, Italy, Japan, the Netherlands, Poland and South Korea. The organizations said their goal was to “inform producers, choosers (i.e. procuring organizations) and operators of software about the advantages of integrating SBOM generation, analysis and sharing into security processes and practices.”

Cybersecurity professionals, including within the ERO Enterprise, have increasingly promoted SBOMs as a solution to a major perceived weakness in modern software development. (See ReliabilityFirst Plugs SBOMs as Essential Cyber Tools.) Rather than being written from scratch, software products today often comprise multiple “components, modules and libraries from open source and proprietary” sources, the guide said. Transparency about these components and their origins is “fundamental for a more secure software ecosystem.”

This is the role of an SBOM, which CISA defined as “a formal record of the details and supply chain relationships of various components used in building software.” The document is similar in scope to a draft guide that CISA released for public comment Aug. 22. That document laid out minimum elements for SBOMs to be generated or requested by federal agencies. (See CISA Seeks Comments on New SBOM Guidance.)

The new guide also includes those elements, such as the expectation that SBOMs use a common format to ensure they are machine-processable, and “contain enough information about the open-source and proprietary components in the software to correlate with other data sources.”

Along with these, the document gives some of the benefits of SBOMs for organizations. CISA said the information provided in SBOMs can improve users’ vulnerability and supply chain management, software development processes and their license management.

To illustrate the potential improvements in vulnerability management, CISA pointed to Log4Shell, a vulnerability in the Log4j software library from Apache that was discovered in December 2021 to contain a weakness that remote actors could use to take control of affected systems.

“Because Log4j was usually used as a transitive dependency (a dependency of other dependencies), it was not always easy to identify,” CISA said. “Organizations without SBOM capability often had to engage in time-consuming manual searches and risked remaining vulnerable. Organizations with SBOMs were able to report a relatively straightforward and efficient response.”

Another illustration showed how the presence of an SBOM reduced average time needed for organizations to identify and respond to a vulnerability. Without an SBOM, CISA said, “each actor is dependent on upstream [software component] suppliers for notification that the vulnerability impacts their software.” But when everyone in the supply chain has an SBOM, organizations can determine for themselves if they are using a compromised product.

The benefits of SBOMs are not limited to producers and users, CISA said: National cybersecurity organizations such as CISA and its peers can also use their information to track their countries’ overall cyber vulnerability, issue warnings and update policymakers.

“The ever evolving cyber threats facing government and industry underscore the critical importance of securing [the] software supply chain and its components. Widespread adoption of [SBOMs] is an indispensable milestone in advancing secure-by-design software, fortifying resilience, and measurably reducing risk and cost,” acting CISA Director Madhu Gottumukkala said in a statement. “This guide exemplifies and underscores the power of international collaboration to deliver tangible outcomes that strengthen security and build trust.”

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SPP, Members Developing 765-kV Transmission Overlay Plan

SPP has hinted to members that its 2025 transmission planning assessment will be another large one — larger, even, than last year’s record $7.65 billion package. 

One of the drivers is a draft 765-kV overlay that staff and members have been engaged with. It builds on SPP’s first 765-kV project that was approved as part of the 2024 assessment, Southwestern Public Service’s 354-mile transmission line crossing the New Mexico-Texas border. (See SPP Stakeholders Endorse Record $7.65B Tx Plan.) 

Casey Cathey, the RTO’s vice president of engineering, shared the overlay during a Sept. 3 education session with the Board of Directors and Regional State Committee. 

“What we have done is a preliminary look based on the [Integrated Transmission Planning] loads that the members have provided us,” Cathey said. 

The draft overlay extends from SPS’ Potter-Crossroads-Phantom line into Oklahoma, where much of the state would be encircled. Another 765-kV line would shoot off to the Southeast and into Louisiana, the site of two load shed events in April. (See SPP Addresses 3rd Load Shed Since March 31.) 

Looking ahead, the 2026 ITP is considering a 765-kV radial line that connects Kansas with North Dakota. One option would close the loop on the western side of the footprint. 

“The 2026 plan is going to be a much more detailed engineering analysis, so it may not look exactly like this next year,” Cathey said. 

Pointing to large loads “peppered throughout” the map, he said that will “necessitate a version of a 765 footprint.” 

“I’m giving some caveats here because there’s a lot of engineering connection points that we may need to change from a reliability perspective,” Cathey said. “However, we are seeing the need for some version of what this looks like moving forward.” 

One reason the time is now ripe for 765-kV transmission in SPP’s footprint is the 345-kV build that members have undertaken in recent years. Cathey said the 345-kV backbone gives staff options that didn’t exist 15 years ago to sustain the transfers necessary should a 765 line be lost. 

SPP has increased its 765-kV line costs from $4.2 million/mile to $5.8 million/mile, comparable to ERCOT’s and MISO’s projections for their 765-kV projects. 

“This is consistent. We’ve gotten some recent feedback from our membership that this is the right way to go and then that the costs are making more sense,” Cathey said. “We don’t have 765 in this region, but it’s been built before. We need to recognize that some things are going to come up. This is going to be pricey. We need to make sure that we’re going into it with eyes wide open.” 

The SPS project was awarded in February with an estimated cost of $1.69 billion. SPS filed a revised cost estimate of $3.62 billion in June, more than double the earlier projection and easily outside the variance bandwidth of +/30% that can lead to a re-evaluation. SPP has said the project still is viable, despite its cost. (See SPP Board Sets Aside 765-kV Costs, Large Load Policy.) 

The RTO has scheduled an education session on the 2025 ITP for the Markets and Operations Policy Committee meeting Sept. 23. The assessment and its portfolio will be brought before MOPC, state regulators and the board in October and November for their approvals. 

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West Must Step up Gas-electric Coordination, WECC Panelists Say

Coordination between the gas and electric industries is becoming increasingly crucial to meet demand and tackle extreme weather events, panelists participating in a WECC webinar said Sept. 3. 

Representatives from the Pacific Northwest Utilities Conference Committee (PNUCC), Williams, Arizona Public Service and Portland General Electric discussed coordination between the gas and electric sectors. 

The Northwest cold snap over the 2024 Martin Luther King Jr. holiday weekend prompted stakeholders to consider ways to improve coordination between the two sectors, said Crystal Ball, PNUCC’s executive director. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

The holiday weekend saw record-low temperatures along with historically high peak demand, prompting five different balancing authority areas (BAAs) to declare energy emergency alerts. 

Though the Pacific Northwest relies heavily on the Columbia River hydro system, the cold snap occurred during a low-water year, Ball noted. It also coincided with a fault that caused Washington’s Jackson Prairie natural gas storage facility to sharply reduce its sendout, prompting pipeline operator Williams to declare a force majeure that cut deliveries to interruptible customers, including some power generators.  

“We recognize that natural gas is the region’s second-largest power source behind hydro, and these two systems are very interdependent, and we will continue to depend on natural gas,” Ball said. 

To meet the mounting large-load challenges from data centers and the transportation sector, stakeholders must work together, not just on transmission and generation, but also focus on expanding the gas system, according to Ball. 

“We need policymakers, regulators, utilities to understand that situation,” she said. “There’s evidence that demand in our region is growing. But right now, this region is dangerously close to an energy supply shortage. And so I think that my advice to policymakers and other stakeholders is to learn about what these reliability risks are and to come together to think about how the region can maintain reliability.” 

For PGE, the January 2024 event meant there wasn’t any headroom in the utility’s systems, according to Aaron Rodehorst, manager of term trading at PGE. 

“We’re fully using our pipelines. We’re fully using our transmission systems,” Rodehorst said. “There’s a high degree of need for coordination.” 

Rodehorst said he works closely with balancing authority staff “to make sure they know everything I know that they can then also be coordinating with their peers.” 

“I’ve been building a contingency plan at Portland General Electric for four or five years now, and every year it gets better, and it gets better also when I start to share it more broadly and get to think about what pieces I’m not putting into that plan,” he noted. 

‘No More Wiggle Room’

Carolyn Ebner, commercial services lead at Williams, said, “our system is fully subscribed.” 

Williams owns the nearly 4,000-mile bi-directional Northwest Pipeline. The pipeline crosses Washington, Oregon, Idaho, Wyoming, Utah and Colorado, according to the company’s website. 

“We have no more wiggle room,” Ebner said. “And Northwest Pipeline is not unique.” 

Ebner said the company will continue to have conversations with the electric sector, “both confidential and in these group platforms, [and] we’re going to continue to prepare options for growth and additional storage on our gas system.” 

Meanwhile, in Arizona, APS had a peak demand of about 8,500 MW in 2025, but the utility predicts peak demand will reach 13,000 MW by 2038, said Jason Hartzell, manager of fuels and contracts at APS. 

APS has had “positive” discussions with Arizona’s commissioners and has gained support for natural gas expansion through public forums facilitated through APS, Hartzell noted.  

To keep up with customer demand, APS has signed an agreement with Energy Transfer Partners to build a new pipeline from the Permian Basin to Arizona to support new gas-fired power plants, he added. 

“We would be one of the shippers of that pipeline,” Hartzell said. “So, we’re only one of the Arizona utilities that has seen this additional need for natural gas.” 

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BOEM Plans to Vacate New England Wind Project Approval

The Trump administration is moving to close the door on U.S. offshore wind development by remanding approvals for all projects not already under construction.

Federal attorneys filed a motion in the U.S. District Court for D.C. on Sept. 3 saying the U.S. Bureau of Ocean Energy Management plans to vacate the permit it issued to New England Wind during the Biden administration.

In late August, federal attorneys made similar comments about the SouthCoast Wind project off the New England coast, as well as about US Wind’s plans off the Maryland coast. And in March, EPA put a hold on an air permit for Atlantic Shores, at least temporarily blocking the New Jersey project from any start of construction.

Those four projects were the late movers among the 11 approved during the Biden administration. One of the 11 is completed; one was canceled by the developer; and five are in some stage of construction.

Numerous plans at earlier stages of development are on indefinite hold amid the clampdown President Donald Trump has ordered on the offshore wind sector, because of the restrictions themselves or from investors being driven away by the heightened risk and uncertainty that has resulted.

The recent motions were filed in three cases where wind power opponents had sued various federal agencies challenging regulatory approvals that allowed the three projects to move forward. In separate motions, Department of Justice attorneys asked the courts to delay the cases because the federal government is going to do essentially what the plaintiffs were seeking.

Federal attorneys said the government is planning to remand and vacate BOEM’s approval of the construction and operations plan for the Maryland offshore wind projects no later than Sept. 12 (24-cv-03111); move for voluntary remand of the SouthCoast approval by Sept. 18 (1:25-cv-00906); and remand and vacate New England Wind’s approval (1:25-cv-01678) no later than Oct. 10. The EPA action against Atlantic Shores on March 14 was a voluntary remand. (See EPA Puts Hold on Atlantic Shores OSW Permit.)

With Trump’s flat rejection of wind power, it is questionable when or if the approvals would be reinstated once remanded.

In the most recent New England offshore wind solicitation, SouthCoast and New England Wind were selected to feed 1,868 MW to Massachusetts and 200 MW to Rhode Island. (See New England OSW Contracts Delayed Again.)

Coupled with the BOEM’s stop-work order on Revolution Wind — an 80% complete project that would send 704 MW to Connecticut and Rhode Island — the pending actions represent a clear threat to New England’s clean energy ambitions.

“New England needs this energy,” Gov. Maura Healey (D) said Sept. 3. “Having already undergone years of expert review, these projects are primed to lower costs and improve reliability. There is absolutely no need for the Trump administration to reopen permitting processes and deny jobs, investment and energy to the states.”

ISO-NE had warned Aug. 25 that delaying Revolution Wind would increase reliability risks for the New England grid. (See ISO-NE Warns Halting Revolution Wind Boosts Reliability Risk.) On Sept. 3, it pointed to remarks by CEO Gordon van Welie about the importance the offshore wind sector holds for the region.

“The region is counting on the entry of resources in the form of large quantities of offshore wind to maintain resource adequacy,” van Welie commented to FERC in May (AD25-7). Solar panels and short-duration battery storage, he added, would not be an adequate replacement for the giant marine turbines.

Nick Krakoff, a senior attorney with the Conservation Law Foundation, told NetZero Insider that remanding and vacating the construction and operations plans for SouthCoast and New England Wind is a move that can be challenged in court by the developers and or the states involved, but the concept of victory is not clear-cut.

“There’s certainly legal avenues,” he said. “I think the bigger question is, what happens to industry? The Trump administration is just actually sabotaging an entire industry.”

Trump’s strategy has proved quite viable so far: Multiple offshore wind development efforts have been placed on hold since his election, Atlantic Shores among them. (See Developer Shelves Atlantic Shores, Seeks to Cancel ORECs.)

Those that remain face a regulatory limbo as the administration floods the zone with new hurdles and limitations. Projects that are under active construction can incur huge cost overruns because of delays.

All of this creates an untenable business environment.

“The longer this drags out, the more difficult it becomes for the developers financially,” Krakoff said. “I think it’s just another example of this administration’s disdain for the rule of law.”

The systematic attempt to kill an entire industry is unprecedented, he added. “You kind of expect this in other countries, but not this country.”

Trade group Oceantic Network criticized the administration’s stated intention to remand and vacate permits that were issued after years of review. “The unlawful and escalating actions by the Trump administration against fully permitted offshore wind projects up and down the East Coast represent one of the largest, economically devastating assaults on U.S. workers, businesses and energy in generations,” it said.

“Halting construction and revoking permits on approved projects after years of thorough agency review will raise electricity prices for millions across the country, jeopardize billions of dollars in private investment, threaten our national shipbuilding, steel and manufacturing supply chains, and undermine our nation’s energy security.”