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A federal judge has ruled that Ørsted can resume the construction of its nearly complete, 704-megawatt Revolution Wind project off the coast of Rhode Island.
The decision on Monday comes after the Trump administration issued stop-work orders to all five of the offshore wind projects under development in the U.S. in late December, the culmination of President Donald Trump’s yearlong war against the renewable energy source.
Revolution Wind, a $6.2 billion project that is nearly 90% complete, was hit with an earlier federal stop-work order in August from the Bureau of Ocean Energy Management, a division of the Interior Department. A federal judge ruled in favor of Ørsted in September, allowing the project to move forward until December’s order, which cited unspecified issues of “national security.”
On Monday, the Danish developer said it will “resume construction work as soon as possible” while its complaint against the Trump administration is heard by the courts.
Judge Royce Lamberth of the U.S. District Court for the District of Columbia, who issued the injunction, said from the bench on Monday that the bureau’s August suspension order was “the height of arbitrary and capricious” and that the December order’s vague claims of national security risks did “not constitute a sufficient explanation for the bureau’s decision to entirely stop work on the Revolution Wind project.” He noted that the government’s argument for halting construction was “unreasonable and seemingly unjustified.”
Each offshore wind project has been repeatedly vetted by the Department of Defense since being proposed, and developers said they were blindsided by the Trump administration’s latest security concerns.
Ørsted and two other offshore-wind developers, Equinor and Dominion Energy Virginia, all sued to vacate the Trump administration’s 90-day construction freeze from December. Ørsted’s court hearing was the first, and judges are set to consider the fate of the other in-progress offshore wind projects this week.
On Wednesday, a court could decide on Equinor’s 810-MW Empire Wind project, which also previously received and defeated a stop-work order. A hearing for Dominion Energy’s massive 2.6-gigawatt Coastal Virginia Offshore Wind project is scheduled for Friday. In addition to energy developers, the states of Connecticut, New York, and Rhode Island have all sued to get the projects going again.
The stakes are high: In total, the five offshore wind farms affected by the Trump administration’s December order would bring nearly 6 GW of capacity to the grid, or enough to power roughly 2.5 million homes across the East Coast.
The U.S. can’t afford to lose any of these projects. Energy demand is climbing across the nation, causing household utility bills to soar. More power plants are needed to keep bills from rising even further — especially in regions swamped with power-hungry data centers, like Virginia.
In addition, grid operators have been banking on the arrival of these large-scale offshore wind projects, several of which are more than halfway complete. In August, ISO-New England issued an unprecedented warning that the Trump administration’s first pause on Revolution Wind created “unpredictable risks” that could “undermine the power grid’s reliability and the region’s economy now and in the future.”
At least one project could be abandoned imminently. Equinor, which already lost nearly $1 billion because of the first stop-work order on Empire Wind, says the beleaguered project faces “likely termination” if it can’t continue work by this Friday.
Meanwhile, industry groups applauded Monday’s decision.
Kat Burnham, the New England policy lead for Advanced Energy United, said the D.C. court “rightly saw through a politically motivated stop-work order that would have caused real harm: driving up costs, delaying power for Rhode Island and Connecticut, and putting good-paying jobs at risk.” In a statement, she said the decision is “good news for workers, ratepayers, and anyone who recognizes the need for a fair energy market.”
The latest skirmish over offshore wind comes after a year of assault from the Trump administration. Trump has gummed up the build-out of onshore wind and solar power, too — but no energy source has been targeted like offshore wind.
The impact of Trump’s war on the sector is profound.
When he was reelected in 2024, BloombergNEF expected 39 GW of offshore wind capacity to come online in America by 2035. The research group hedged that number to 21.5 GW if Trump managed to repeal wind tax credits during his term. He did. As of October, BNEF expected just 6 GW to get online by 2035 — a number that will be even lower if any of the in-progress projects buckle under the weight of the latest order.
Out in the fertile yet water-constrained farmlands of California’s western Central Valley, a massive solar, battery, and power grid project that could provide a quarter of the state’s clean energy needs by 2035 has taken a critical step forward.
In December, the board of directors of the Westlands Water District, the agency that manages water delivery to more than 600,000 acres in California’s agricultural heartland, approved the Valley Clean Infrastructure Plan. VCIP calls for building up to 21 gigawatts of solar energy and an equivalent amount of battery storage across up to 136,000 acres, along with a series of high-voltage transmission lines to connect the electricity generated to the state’s grid.
That would be the largest solar and battery project in the country, and it will take up to a decade to be completed. But Patrick Mealoy, a partner and chief operating officer of Golden State Clean Energy, the company developing the master plan in partnership with the district, said it’s expected to move quickly, with the first construction work potentially happening within the next two years.
Golden State Clean Energy will carry out only a small part of the project, Mealoy said. It will mostly seek third-party solar and battery developers, with individual installations ranging in size from 100 to 1,150 megawatts.
Mealoy, a 30-year solar veteran, codeveloped Westlands Solar Park, the first major solar farm in the district. When fully completed, that project will be one of the largest in the Central Valley and produce 2.7 gigawatts — a fraction of VCIP’s scope.
The VCIP is designed to manage the multiple challenges that can stymie piecemeal solar and battery projects, such as winning environmental approvals, securing buy-in from landowners and communities, and interconnecting to the state’s congested transmission grid, Mealoy said.
“We’re doing the transmission studies, the environmental impact studies, and outreach to communities, all at the same time, to make sure there are no showstoppers.”
The VCIP is as much about preserving the region’s agriculture industry as it is about generating clean electrons, said Allison Febbo, the district’s general manager. That’s because the plan will allow the district’s more than 700 growers to redirect increasingly limited water supplies from land slated for clean energy development to land that remains under cultivation.
“The real benefit to us is that it gives our growers another crop to grow, which is the sun,” she said. “Our growers have this issue: ‘I have 100 acres of land but only enough water to irrigate 50 of those acres. What do I do with the remainder of those acres?’”
For decades, California’s Sacramento–San Joaquin River Delta has delivered water via the Central Valley Project’s system to irrigate the Westland Water District, the largest water district in the country. But in recent years, restrictions brought on by environmental and endangered species regulations for the delta have forced Westlands to fallow an increasing amount of farmland, expanding to more than one-third of its total acreage. And under the state’s Sustainable Groundwater Management Act, farmers will soon face stringent restrictions on how much water they can pump from the region’s long-stressed aquifers.
As more and more land has been left uncultivated, farm employment and property tax revenues have declined in the region. “The schools can’t be supported, the businesses can’t be supported,” Febbo said. “This is a way to maintain economic viability and support our communities.”
Mealoy said the VCIP could revitalize the region’s economy. “The cost of building solar is well north of $1 million per megawatt, probably closer to $1.5 million,” he said. Spread across 21 gigawatts of planned development, “that’s billions and billions of dollars that could be built on fallowed ag land, creating jobs and creating an enormous tax base for Fresno County,” which encompasses the land being set aside for development.
The economic benefits would extend beyond the region. An analysis commissioned by Golden State Clean Energy last year found that the clean energy and transmission congestion relief the plan would deliver could yield annual electricity cost savings of about $850 million and reduce the state’s power-sector carbon emissions by 15% through 2050.
The plan will also help reduce the grid congestion that’s created yearslong interconnection delays for large-scale solar and battery projects throughout the state, Mealoy said. In 2024, state lawmakers passed Assembly Bill 2661, a law that allows the Westlands Water District to develop its own transmission grid to get solar to market.
The project’s transmission infrastructure will be constructed under a project labor agreement using 100% union labor. That has won it the backing of the International Brotherhood of Electrical Workers Local 1245, which represents workers at Pacific Gas & Electric, the state’s largest utility.
Westland Water District’s approval of VCIP’s programmatic environmental impact report last month will allow the next big phases of the project to move ahead, Febbo said.
“With this master-planned approach, we’ll have one set of guidance, one set of rules. We’ll be able to handle how land is managed, how pests are managed, dust control — all of those things can be dealt with on a large scale.”
The project should deliver other benefits to the surrounding communities as well. Westlands Water District is bound by state law to develop community benefits agreements to provide funding for job training, environmental remediation, economic development, and other community needs for the roughly 15,000 people living nearby.
Those residents don’t want energy extraction to come at their expense, said José Antonio Ramírez, city manager of the town of Livingston and acting director of Rural Communities Rising, a newly formed collaborative of unincorporated communities. An earlier endeavor, the Darden Clean Energy Project, to be built on land to be purchased from Westlands Water District, has been criticized for having an inadequate community benefits plan.
Febbo said the district is “committed to a community benefit program, so tax revenues and other revenues will be spent on the communities that need it,” but that this work has only just begun.
Ramírez said his group is pressing for the unincorporated communities it represents to have a say in how that plan is shaped. “A lot of people out here are just making ends meet on a day-by-day scenario,” he said. “I don’t think our communities know the opportunities before them — and that these opportunities can go south if they don’t speak for themselves.”
Nearly 10 years after Massachusetts announced plans to buy 1.2 gigawatts of carbon-free hydropower from Canada, the clean electrons are finally set to start flowing into the state.
As soon as this Friday, the New England Clean Energy Connect transmission line could begin commercial operations.
The 145-mile project, extending from the Canadian border to the southern Maine city of Lewiston, will function as something like an enormous extension cord, plugging the New England grid into a supply of electricity generated by energy giant Hydro-Québec. The new supply is expected to save the average residential customer in Massachusetts $18 to $20 per year and move the state closer to its goal of net-zero emissions by 2050.
“This is a significant moment for clean energy in New England,” said Phelps Turner, director of clean grid for the Conservation Law Foundation.
Avangrid, the developer of the transmission line, told Maine utility regulators earlier this month that operations are scheduled to begin on Jan. 16. Work is underway to meet that target.
“Teams are busy on both sides of the U.S.-Canada border,” said Hydro-Québec spokesperson Lynn St-Laurent. “We have been actively testing the equipment for the past several weeks.”
Following a tumultuous year for clean energy projects, the completion of the controversial transmission line is both a rare triumph and a case study in the challenges of balancing decarbonization and the preservation of wild lands. It’s also an uncommon example of transmission getting built in the U.S., where it has proven difficult to construct the massive power lines needed to deliver new electricity supply to population centers.
The project has its roots in a 2016 Massachusetts law that called for the state to procure 1.2 gigawatts of Canadian hydropower, or other renewables, and 1.6 gigawatts of offshore wind energy. The first idea for importing power from the north involved working with a planned 192-mile transmission line through New Hampshire. However, the project was scuttled in 2019 by public outcry against the prospect of chopping a path through some of the state’s treasured forests.
Massachusetts then looked east, to Maine, to find a route for the transmission line. Similar objections quickly arose, with opponents in the state filing a series of legal challenges. In 2021, Maine voters approved a ballot referendum effectively blocking the project. Work froze until August 2023, a few months after a jury unanimously ruled the project could move forward.
The delays spiked the project’s price tag. Before the line could start providing power, the developer, state regulators, and utilities had to come to an agreement about how those costs would be covered. In early 2025, they settled on terms that increased the price utilities would pay by a total of about $521 million, but ensured consumers would still see savings.
“The project faced many challenges over many years, and it survived all of them,” Turner said.
In addition to the modest monthly savings expected for Massachusetts utility customers, the influx of hydropower should keep rates down for consumers throughout New England by pouring lower-cost electricity into the market that will put downward pressure on prices, right at a time when rising energy bills have become a major issue, Turner said.
Questions remain, however, about how much new power the project will actually bring to the New England grid.
Hydro-Québec already sends power into the region on a separate transmission line, though these exports have decreased in recent years, even stopping almost entirely for a period in 2025. It’s possible that meeting its commitment to deliver along the New England Clean Energy Connect line will mean Hydro-Québec chooses to send less power along other pathways, said Dan Dolan, president of regional trade group the New England Power Generators Association. The net increase in clean power may be lower than anticipated.
“The change in flows over the last several years, particularly in 2025, do not leave me optimistic that Canadian hydro is here to save the day,” Dolan said.
I spent much of 2024 writing about the ambitious plans that U.S. steelmakers had to clean up the coal-reliant industry. But by the start of 2025, it was fast becoming clear that those green-steel dreams were in serious trouble.
Under the Biden administration, two big companies had proposed pioneering projects for cleaner steelmaking that were slated to receive $1 billion in federal support and would serve the growing market for lower-carbon metal. The industry seemed poised to begin a new chapter in the storied history of American iron and steel.
The manufacturer SSAB planned to produce iron — the key ingredient in steel — using green hydrogen in Mississippi. Then early last January, I saw the Swedish company had quietly withdrawn from award negotiations with the U.S. Department of Energy following the demise of its would-be hydrogen supplier, Hy Stor Energy. Soon after, President Donald Trump took office for a second time, moving swiftly to rescind grants and dismantle federal programs meant to advance clean energy and curb industrial emissions.
It wasn’t long before Cleveland-Cliffs, the other award recipient, shelved its own initiative for a hydrogen-ready ironmaking plant in Ohio. Today, the company is working with the Trump administration to develop a new scope for the project, one that preserves the use of fossil fuels. And SSAB recently told me that it’s not planning to revive any hydrogen-based projects in the United States.
Green hydrogen, which is made with renewable energy, has long been considered the Holy Grail for decarbonizing heavy industries because it can be used to replace fossil fuels in existing technologies and manufacturing methods. But now the U.S. green hydrogen boom itself has collapsed, taking the steel industry’s ambitions down with it.
At the dawn of 2026, America’s steel producers have no major green hydrogen initiatives slated to start this decade. Supplies of the low-carbon fuel remain scarce and expensive, and there’s no serious, coordinated attempt by the U.S. government to help resolve these stubborn barriers to cleaner steelmaking.
But while it may seem as if the industry has given up on decarbonizing U.S. steel production, the reality is much more nuanced.
Despite the high-profile retreats, manufacturers are still steadily making progress to clean up the country’s nearly 2-century-old industry. Legacy companies are investing in new steel-recycling mills, and startups are building facilities and raising private funding to scale novel technologies. Tech giants are boosting demand for cleaner construction materials as they work to limit the climate impact of the data center boom.
So what should we expect in the year ahead? There is no one clear path forward in the transition to greener steelmaking but rather many winding roads, with some heading toward progress and others looping back to the past. Here are three broad developments I’ll be keeping an eye on.
America’s modern steel era began in the late 19th century, fueled by scorching blast furnaces that use coke — a purified form of coal — to transform iron ore into molten iron, which is then turned into steel. This is still the main way that virgin, or “primary,” steel is made today, and it’s responsible for the bulk of the industry’s carbon emissions and toxic air pollution.
In recent decades, U.S. manufacturers have largely shifted to making “secondary” steel by recycling scrap metal in electric arc furnaces. But a dozen blast furnaces still operate in a handful of states, and their owners say they’re committed to keeping the facilities running well into the future.
U.S. Steel, which is now a subsidiary of Japan’s Nippon Steel, is set to “reline” its largest blast furnace in Gary, Indiana — a major maintenance project that could extend the aging furnace’s operating life by up to 20 years. In late December, U.S. Steel’s board of directors approved $350 million for the undertaking. The company also announced that it will restart operations at an idled blast furnace in southern Illinois to meet rising demand for domestic steel.
Cleveland-Cliffs, which relined one of its blast furnaces in Cleveland in 2022, plans to make similar upgrades at two other mills. The company will reline a blast furnace in Burns Harbor, Indiana, in 2027 and do the same in Middletown, Ohio — the site of its previous hydrogen project — “in the next four to five years,” according to CEO Lourenco Goncalves.
“Reality is back. La-la land is gone,” he said about the change of plans during an earnings call last May.
The manufacturers argue that propping up existing infrastructure is the better choice economically for maintaining and expanding their steelmaking capacity, versus building a new furnace or adopting other technologies. In the long run, however, those coal-fueled furnaces could become big liabilities as automakers, data center developers, and other key customers look to suppliers that offer less-carbon-intensive metal.
“The real challenge, from a technology perspective, is that there’s not really a path for a blast furnace to make the [low-carbon] products that are increasingly being demanded in the market,” said Kaitlyn Ramirez, a senior associate in RMI’s Climate-Aligned Industries Program. “There’s no solution that’s going to be cost-competitive to do that.” She added that the relining decisions represent a “window of opportunity” for steel producers to pivot away from coal instead.
Even as the two steel giants throw a lifeline to a few old dirty furnaces, they and other companies are still making investments to expand lower-carbon production of the ubiquitous, sturdy metal.
Nippon Steel, for its part, recently announced plans to build a $4 billion plant somewhere in the U.S. with two new electric arc furnaces, which typically combine a little bit of iron with a lot of scrap metal. These facilities can curb carbon emissions by 75%, compared to traditional steel mills, because they require using dramatically less coal, a figure that will grow as the nation’s grid increasingly runs on clean energy, according to industry reports.
Its subsidiary U.S. Steel already operates a sprawling steel-recycling operation in Osceola, Arkansas. I visited the Big River Steel site in late 2023, when U.S. Steel was building a second multibillion-dollar plant to make steel specifically for electric vehicle motors, solar panels, and power generators and transformers. Right next door was a field of flattened dirt where Entergy’s 250-megawatt solar farm was soon to be installed.
U.S. Steel finished the construction last year, and the company plans to buy enough clean electricity from the completed solar project to cover 40% of the second plant’s operations. Major steel recyclers like Nucor and Steel Dynamics have also struck deals with clean energy developers in other states to help reduce the emissions associated with running their power-hungry furnaces.
U.S. Steel is also set to construct a “direct reduced iron” facility at the Big River Steel site as it works to lead the industry in “advanced, sustainable steel production,” spokesperson Amanda Malkowski told the Arkansas news site Talk Business & Politics.
Neither Nippon Steel nor its subsidiary has given many specifics about the new ironmaking project. But most DRI facilities operating today use fossil gas to remove oxygen from iron ore, which yields lumps of iron that are fed into electric arc furnaces. This process emits about half as much CO2 as a coal-fired blast furnace. Using green hydrogen can curb overall emissions even further, by up to 90%, experts say.
Based on what’s happened in recent years, I’d be surprised if Nippon Steel plans to source green hydrogen for the project. But another major steelmaker claims to be committed to using the fuel down the road. Hyundai Motor Group says it plans to build a $6 billion steel plant in Louisiana by 2029 that will include a DRI facility and an electric arc furnace. The Korean automaker reportedly intends to start producing green hydrogen at the facility in 2034, though it hasn’t said much publicly about how it will manage such a feat.
Industrial giants aren’t the only ones working to clean up U.S. steelmaking. A handful of well-funded startups are steadily advancing newer ways of making the high-strength metal without using coal.
Last year, Boston Metal said it gotten one step closer to commercializing its “molten oxide electrolysis” technology after it fired up an industrial-size reactor at its facility in Massachusetts. Electra unveiled the site of its first demonstration plant in Colorado, where the company will produce iron with electrochemical devices powered by renewables. And in Texas, the startup Hertha Metals is turning iron ore directly into steel using a high-temperature, single-step process that currently runs on fossil gas but could switch to green hydrogen whenever supplies become commercially available, Hertha’s CEO Laureen Meroueh told me.
These novel efforts are drawing investment from not just global mining giants and metals manufacturers but also companies that use lots of steel — and see the material as a major source of their own supply chain emissions. Meta, for example, has agreed to buy certificates from Electra that will allow the tech company to count the emissions reductions associated with each ton of Electra’s clean iron toward Meta’s climate targets.
“Many of the long-term-focused large companies are looking at sustainability goals that last 10 to 20 years,” said Greg Matlock, the Americas metals and mining tax leader at accounting firm Ernst & Young. “Regardless of what the current political landscape is, I do think there’s absolutely still an appetite [for industrial decarbonization], and it’s a global appetite.”
The European Union is driving much of that global momentum. On Jan. 1, the 27-member bloc began implementing a carbon border tariff, which charges fees on imports of steel, aluminum, and other industrial products made in dirtier facilities abroad. The idea is to level the playing field for European manufacturers that invest in cleaner and potentially costlier facilities, while also encouraging other countries to regulate their own industrial CO2 emissions.
The carbon tariff won’t directly affect U.S. steelmakers all that much, given that they export only a tiny amount of metal to EU-member countries. But the policy’s ripple effects are already transforming the broader industry and putting pressure on all steel producers to modernize and clean up. Countries such as Brazil and Turkey have introduced domestic carbon-pricing policies in response to the EU’s moves. China has started shipping steel made using hydrogen to Italy, which experts say could set the stage for boosting Chinese green-steel exports.
“We’re moving toward a global standard … for lower-carbon steel, so American companies will be well positioned to compete in [global] markets if they continue to decarbonize,” said Angela Anderson, director of industrial innovation for the World Resources Institute. “It’s not likely that those trends are going to just dry up or reverse anytime soon.”
The U.S. has a chance to be at the cutting edge of cleaner steelmaking. Right now, the question seems to be not if we’ll take it, but when — and how far we’ll fall behind the rest of the world in the low-carbon industrial revolution.
Voters worried about rising electricity prices and the onslaught of power-hungry data centers helped Democrats earn a governing trifecta in Virginia last year.
Now, as state lawmakers prepare for a breakneck, 60-day legislative session that begins this Wednesday, clean energy is emerging as a key strategy for dealing with those challenges.
“Oftentimes, I go into a legislative session sort of just guessing what people are going to care about,” said Kendl Kobbervig, advocacy and communications director for the nonprofit Clean Virginia. Not this year, she said. “No. 1 is affordability, and second is data center reform.”
The concerns come as Virginia, the world’s data center capital, is at a crossroads on its quest for 100% clean energy. The commitment began in earnest in 2020, when the state enacted a measure requiring its two investor-owned utilities — Dominion Energy and Appalachian Power Co. — to convert to carbon-free electricity by midcentury. The law also prevents new construction of fossil fuel–burning plants, with some exceptions.
But the landscape has changed dramatically over the last five years, with Dominion now projecting enormous electricity demand from the 663 data centers in the state, and counting. The company has used those predictions to justify building a spate of new gas plants over the next decade, starting with a 944-megawatt complex in Chesterfield County, just southwest of Richmond. Though regulators are taking a second look at the controversial new plant, they’ve mostly blessed the company’s plans. At the same time, Dominion warns that President Donald Trump’s move to halt construction of its Coastal Virginia Offshore Wind Project, with a projected 2.6 gigawatts of capacity, could constrain supply.
These demand pressures are one reason Virginians face rising energy bills.
Dominion, the state’s largest utility, won approval last November for a roughly 9% increase in residential rates over the next two years in a ruling that advocates say didn’t do enough to ensure that data centers pay their fair share of costs. Customers of Appalachian Power, in the southwest corner of the state, have already seen a spike in their bills, driven in substantial part by the escalating price of gas and coal.
Republicans and even some Democrats have said the way to cost-effectively meet ballooning power needs is to back away from the clean energy transition and the 2020 law, the Virginia Clean Economy Act. But multiple Democratic lawmakers are pushing bills this year that do just the opposite in an effort to save consumers money and increase electricity generation.
“The name of the game this session is affordability,” Democrat Del. Phil Hernandez of Norfolk said at a news conference last week.
One proposal to lower costs, offered by Hernandez and Sen. Schuyler VanValkenburg of Henrico, is dubbed the Facilitating Access to Surplus Transmission, or FAST, Act.
The bill is made possible by a new rule at PJM Interconnection, the multistate entity that manages Virginia’s grid: Facing lengthy backlogs for new grid hookups, PJM said last year it could connect some sources on an expedited basis so long as they didn’t trigger meaningful upgrades to the transmission grid.
“There are miles and miles of our current transmission infrastructure that are not being used at nearly their full capacity,” said Jim Purekal, a director at Advanced Energy United who heads the organization’s legislative work in Virginia. “A traditional peaker plant only operates at various points around the year. The rest of the time, it’s essentially dormant.”
The FAST Act, Hernandez said, “will lay out a process to help get these new energy projects up and running.”
The PJM surplus interconnection rule is a permission structure, not a mandate. And utilities may be tempted to use the regulation to build expensive new fossil fuel plants. The bill would set up a study of how much headroom is on the grid and create a procedure to allow only the most cost-effective resources to utilize it.
“Let’s make sure that if you’re going to be using this capacity,” Purekal said, “you’re using the most affordable assets on the commercial market today: solar, onshore wind, and battery storage.”
Advanced Energy United expects 2 to 3 gigawatts of such resources could be colocated with existing power plants of all types within four years. That’s about two times faster than it has taken a project to get through PJM’s queue in recent years.
“We believe this could be one of the fastest, lowest-cost ways to add power to the grid,” Hernandez said.
A complementary effort, to be introduced by Sen. Lamont Bagby of Richmond and Del. Rip Sullivan of Fairfax, would increase grid battery targets in the 2020 law and help ensure energy storage projects are cost-effective for ratepayers.
With Hernandez, the lawmakers promoted it at last week’s press event behind a podium sign that read, “Energy Storage Keeps Electricity Affordable.” One reason that’s true, Sullivan noted at the conference, is that batteries can charge when electricity prices are low and supply is abundant — as on a mild, sunny afternoon — and discharge when demand is high and hourly prices go up. “We can store energy when it’s cheap,” he said, adding that “this is the best energy storage bill in the country.”
The storage and surplus interconnection bills aren’t the only pieces of legislation on Democrats’ affordability agenda.
Indeed, incoming Del. Lily Franklin of southwest Virginia is among those seeking to bring costs down for customers of Appalachian Power, in part by reining in transmission and fuel charges that typically get less scrutiny in rate cases.
Likewise, Sullivan and Sen. Scott Surovell of Fairfax will proffer legislation to lay the groundwork for a ratemaking scheme that would align utilities’ profits with their performance on clean energy, efficiency, and affordability. Among others, the measure was recommended last month by the influential Commission on Electric Utility Regulation, which Surovell chairs.
The stamp of approval may help the measure’s chances in the legislature this year, as should its lead patron. “Sen. Surovell is the Senate majority leader,” Kobbervig said. “So when he says yes to things, you think, ‘OK, this has legs!’”
The other thorny problem at the top of lawmakers’ energy agenda is the explosive growth of data centers in the state. According to Dominion, the facilities could account for an eyepopping 51% of its electricity sales by 2035, though such figures are notoriously slippery.
“There’s a lot of uncertainty in this market. There’s a lot of speculative load,” said Nate Benforado, senior attorney at the Southern Environmental Law Center. “At the same time, that is an astounding number.”
Environmental advocates’ plan to confront the challenges posed by data centers includes sticks such as increasing transparency on utility projections and ensuring that residential customers aren’t unfairly burdened with increased costs. But Sullivan and Sen. Creigh Deeds of Charlottesville also want to reform a sizable carrot: the generous tax incentives that lured Amazon, Google, and their ilk to the state in the first place.
“It’s by far Virginia’s largest tax break, and it’s going to some very large companies,” Benforado said. That’s part of why its conditions should include investments in renewables and efficiency.
“We want to only give a tax incentive to data centers that are accelerating the clean energy transition — and certainly not hurting that transition.”
Several of the measures Democrats plan in 2026 cleared the General Assembly last year, only to be vetoed by outgoing Gov. Glenn Youngkin, a Republican.
But on Jan. 17, Youngkin will be replaced by Gov.-elect Abigail Spanberger, a Democrat who campaigned on affordability and data center growth, and has already championed the bill to increase the state’s battery storage targets, among other measures.
“I recognize the complexity of our current challenges and threats posed by the future demands, but the answer is not to sit so our problems only get worse,” Spanberger said at a news conference last month about her energy agenda, according to the Virginia Mercury.
Still, Republicans have sought for years to weaken or repeal the 2020 Clean Economy Act, and the onslaught of data centers, community concern over large-scale solar farms, and the Trump administration’s anti-renewables stance are breathing new life into their arguments.
At the same time, powerful Democrats, including Surovell and House of Delegates Speaker Don Scott of Portsmouth, haven’t ruled out relaxing the law’s prohibitions on new gas plants, according to Inside Climate News. Dominion has asserted that such plants are needed to keep the lights on in the face of new demand.
Clean energy advocates plan to forcefully rebut those claims in the General Assembly and the public square.
“It is incumbent on us to be pushing back on the concepts that gas is clean, that gas is affordable, that it’s the only way to have a reliable grid,” said Benforado. “They are simply not true.”
December 18, 2025 – Today, Climate TRACE reported that global greenhouse gas (GHG) emissions for the month of October 2025 totaled 5.03 billion tonnes CO₂e. This represents an increase of 0.40% vs. October 2024. Total global year-to-date emissions are 50.31 billion tonnes CO₂e. This is 0.55% higher than 2024's year-to-date total. Global methane emissions in October 2025 were 33.83 million tonnes CH₄, an increase of 0.07% vs. October 2024.
Data tables summarizing GHG and primary particulate matter (PM2.5) emissions totals by sector and country, and GHG emissions for the top 100 urban areas for October 2025 are available for download here.
Greenhouse Gas Emissions by Country: October 2025
Climate TRACE's preliminary estimate of October 2025 emissions in China, the world's top emitting country, is 1.42 billion tonnes CO₂e, an increase of 8.46 million tonnes of CO₂e, or 0.60% vs. October 2024.
Of the other top five emitting countries:
Greenhouse Gas Emissions by Sector: October 2025
Greenhouse gas emissions increased in October 2025 vs. October 2024 in power, transportation, and waste, and did not decrease in any major sectors. Transportation saw the greatest change in emissions year over year, with emissions increasing by 1.13% as compared to October 2024.
Greenhouse Gas Emissions by City: October 2025
The urban areas with the highest total GHG emissions in October 2025 were Shanghai, China; Tokyo, Japan; Houston, United States; New York, United States; and Los Angeles, United States.
The urban areas with the greatest increases in absolute emissions in October 2025 as compared to October 2024 were Ramagundam, India; Obra, India; Newcastle, Australia; Toranagallu, India; and Owensboro, United States. Those with the largest absolute emissions declines between this October and last October were Waidhan, India; Korba, India; Anpara, India; Rotterdam [The Hague], Netherlands; and UNNAMED, India.
The urban areas with the greatest increases in emissions as a percentage of their total emissions were Butibori, India; Uruguaiana, Brazil; Shitang, China; Obra, India; and Shostka, Ukraine. Those with the greatest decreases by percentage were Heilbronn, Germany; UNNAMED, India; Santaldih, India; Petropavlovsk-Kamchatsky, Russia; and Alotau, Papua New Guinea.
RELEASE NOTES
Revisions to existing Climate TRACE data are common and expected. They allow us to take the most up-to-date and accurate information into account. As new information becomes available, Climate TRACE will update its emissions totals (potentially including historical estimates) to reflect new data inputs, methodologies, and revisions.
With the addition of October 2025 data, the Climate TRACE database is now updated to version V5.2.0. This release expands asset coverage to include 245 additional power plants (globally) and 2,287 additional cattle operations (all in Japan). It includes non-greenhouse gas emissions for petrochemical steam cracking facilities in Asia Pacific and the Middle East. The waste sector has updated modeling for its landfill emissions: emissions are now modeled natively for each month, where previously, annual estimates were disaggregated into monthly estimates. The release also includes data fixes within transportation and waste sectors.
A detailed description of data updates is available in our changelog here.
To learn more about what is included in our monthly data releases and for frequently asked questions, click here.
All methodologies for Climate TRACE data estimates are available to view and download here.
For any further technical questions about data updates, please contact: coalition@ClimateTRACE.org.
To sign up for monthly updates from Climate TRACE, click here.
Emissions data for November 2025 are scheduled for release on January 29, 2026.
About Climate TRACE
The Climate TRACE coalition was formed by a group of AI specialists, data scientists, researchers, and nongovernmental organizations. Current members include Carbon Yield; Carnegie Mellon University's CREATE Lab; CTrees; Duke University's Nicholas Institute for Energy, Environment & Sustainability; Earth Genome; Former Vice President Al Gore; Global Energy Monitor; Global Fishing Watch/emLab; Johns Hopkins University Applied Physics Lab; OceanMind; RMI; TransitionZero; and WattTime. Climate TRACE is also supported by more than 100 other contributing organizations and researchers, including key data and analysis contributors: Arboretica, Michigan State University, Ode Partners, Open Supply Hub, Saint Louis University's Remote Sensing Lab, and University of Malaysia Terengganu. For more information about the coalition and a list of contributors, click here.
Media Contacts
Fae Jencks and Nikki Arnone for Climate TRACE media@climatetrace.org
This analysis and news roundup come from the Canary Media Weekly newsletter. Sign up to get it every Friday.
President Donald Trump’s sweeping freeze on offshore wind construction is starting to hurt his own party’s energy ambitions.
Just days before Christmas, the Trump administration halted work on all five large-scale offshore wind farms under construction in the U.S, citing unspecified national security concerns. The order may have come as a shock to the project developers, who received letters from the Interior Department only after Fox News publicly reported on the move, as Canary Media’s Clare Fieseler reported at the time.
All but one of the targeted developers have since sued the Trump administration. Danish developer Ørsted filed two separate suits over pauses to its nearly complete Revolution Wind — which the Interior already halted for a month last fall — and to Sunrise Wind. In another lawsuit, Equinor warned that the freeze would result in the “likely termination” of its Empire Wind project off New York, which also suffered a monthlong stop-work order last spring. And Dominion Energy is asking a judge to let construction resume on the utility’s Virginia project, once considered safe because it had the backing of the state’s outgoing Republican governor.
The halts are also sparking backlash on Capitol Hill that could derail some of the White House’s other energy plans. In the weeks leading up to the holidays, Congress had taken up what seemed like the millionth round of negotiations to reform energy-project permitting. Reforms are essential to Republicans’ goal of speeding fossil-fuel construction, and this time around, they’d actually made progress with the House’s passage of the SPEED Act, which had support from a handful of Democrats.
That bill requires 60 votes to clear the Senate, but with Republicans holding just 53 seats, it would need significant Democratic support. That won’t happen while the Interior’s stop-work order remains in place, two high-ranking Senate Democrats say.
“The illegal attacks on fully permitted renewable energy projects must be reversed if there is to be any chance that permitting talks resume,” Sens. Sheldon Whitehouse (D-R.I.) and Martin Heinrich (D-N.M.) said in a late December statement calling out the offshore wind halts. “There is no path to permitting reform if this administration refuses to follow the law.”
Congress reconvened this week, but Whitehouse affirmed that permitting talks won’t go anywhere until offshore wind construction is free to proceed.
Venezuela is dominating the energy discussion
While the Trump administration used allegations of narcoterrorism to justify its invasion of Venezuela and seizure of leader Nicolás Maduro, pretty much every conversation since has revolved around the country’s oil resources. In his first news conference after Maduro’s capture, President Donald Trump said the U.S. would “run” Venezuela and control its oil production, and he has been pressuring American oil companies to reinvest in the South American nation.
But it’s not just oil that the White House is eyeing. An administration official told Latitude Media that Trump and the private sector may also target Venezuela’s critical mineral resources, though experts warn that little reliable data exists on those deposits and that the country’s mining sectors are in disarray.
More delayed coal-plant retirements
The U.S Department of Energy issued a wave of orders in the waning days of 2025 to keep coal power plants running past their retirement dates. The first targeted a plant in Centralia, Washington, which its owner had been planning to close since 2011. Next up came orders to keep two Indiana coal plants open until at least late March. And just before year’s end came another, this one targeting Unit 1 at Colorado’s Craig power plant.
Both the Craig facility and one of the units in Indiana have been out of commission due to mechanical failures since earlier in 2025, meaning their owners will now have to shoulder potentially huge repair costs to comply with the federal mandate, Canary Media’s Jeff St. John reports.
And the U.S. EPA may soon throw another lifeline to coal power. The agency plans to let 11 plants dump toxic coal ash into unlined pits years after current federal rules allow, Canary Media’s Kari Lydersen reports. Without the extension, those plants would likely shutter.
A just transition? As the European Union shifts off coal, advocates and leaders are working to ensure Poland’s powerhouse mining region isn’t left behind. (Canary Media)
It’s electrifying: The rising cost of natural gas and growing popularity of heat pumps and induction cooking indicate a bright future ahead for building electrification in the U.S. (Canary Media)
State of the emergency: In the year since Trump declared a national emergency on energy, experts say an actual electricity-supply crisis has emerged, and the White House is discouraging renewable energy development that could help solve it. (Canary Media)
A new EV champion: Tesla’s sales fell year-over-year in 2025, finishing at 1.64 million deliveries, putting the company’s sales totals behind emerging Chinese company BYD, which sold 2.26 million EVs. (AFP)
Back from the dead: Nearly obsolete fossil-fuel-fired peaker plants are being forced back into service thanks to rising electricity demand from AI data centers. (Reuters)
Solar’s bigger in Texas: Data shows that solar arrays provided more power to Texas’ standalone grid in 2025 than did coal-fired power plants, marking the first time that has happened. (Houston Chronicle)
The Environmental Protection Agency plans to let 11 coal plants dump toxic coal ash into unlined pits until 2031 — a full decade later than allowed under current federal rules.
The move tosses a lifeline to the polluting power plants. If the facilities were barred from dumping ash into unlined pits, they would be forced to close, since they can’t operate if they don’t have a place to dispose of the ash, and the companies say finding alternative locations for disposal would be impossible.
These 11 plants have already circumvented the 2021 deadline to close such pits, through a 2020 extension offer from the first Trump administration. By filing applications for that extension through 2028, the plants were allowed to keep running even though the EPA has yet to rule on the applications.
On January 6, the EPA held a virtual public hearing on its proposal to give the plants an additional three years to stop dumping coal ash in unlined pits. Attorneys, advocates, and people who live near the plants called the plan illegal, a threat to public health, and another tactic by the Trump administration to prolong the lives of polluting coal plants.
In recent months, the Department of Energy has ordered coal plants scheduled for retirement to continue operating, saying their electricity is needed — an argument the EPA echoed in its proposal. Some state regulators, grid operators, and energy experts have pushed back on the notion that it is necessary to force these power plants to stay online. At the hearing, critics of the EPA’s proposed extension said reliability concerns are outside the agency’s coal ash mandate to protect human health and the environment.
“If the proposal is not finalized, the plants would have to close their [coal ash] impoundments and cease burning coal by 2028,” said Lisa Evans, a senior attorney for the environmental law firm Earthjustice. But under the proposed extension, “the plants will continue to burn coal, thus creating additional air pollution,” and contamination from coal ash.
Coal ash dumped in unlined pits can leach into groundwater, potentially contaminating drinking water wells with carcinogens and other dangerous elements. In 2018, the federal D.C. Circuit Court of Appeals ruled that the 2015 federal regulation on Coal Combustion Residuals (CCR) must be strengthened to better deal with such sites. The ruling led to an April 2021 deadline to start closing unlined coal ash ponds.
Through a 2020 extension offer from the first Trump administration, the EPA invited power companies to apply for the extension through 2028 if they had no other way to deal with the ash and were otherwise in compliance with the rules for disposal.
The EPA made a final decision in only one case, denying an extension to the troubled James M. Gavin plant in Ohio in 2022. But any company that filed an application has been able to keep its plant running while the EPA considers the case, something critics say is an obvious loophole.
The latest proposal would let three such plants in Illinois, two in Louisiana, two in Texas, and one each in Indiana, Ohio, Utah, and Wyoming operate until 2031.
“That [2021] deadline was established to stop ongoing contamination and protect communities,” said Cate Caldwell, senior policy manager of the Illinois Environmental Council, which represents 130 groups in the state. “By expanding a loophole created during the first Trump administration, EPA would allow coal plants to delay closure for at least three more years and potentially much longer.”
The EPA’s previous and proposed regulations say that an extension for unlined pits can be granted only if the site is in compliance with the federal coal ash rules, including those involving cleaning up groundwater contamination.
At the hearing, experts argued that the 11 plants are not in compliance. Groundwater monitoring data that the companies are required to provide shows that all the sites eligible for the extension have elevated levels of contaminants linked to coal ash.
“EPA never reviewed these demonstrations,” Evans said. “If they did, I am confident that they would likely find that each of the plants are ineligible for an extension.”
In the virtual hearing, Indra Frank, coal ash adviser to the citizens group Hoosier Environmental Council, told the EPA that the R.M. Schahfer plant in Indiana is violating the coal ash rules by failing to file the required groundwater monitoring reports and other documents for a retired coal ash pond, which she and Earthjustice attorneys discovered in reviewing maps and images of the site.
“That impoundment is subject to the federal CCR rule, but it has not met any of the requirements of the rule. To qualify for the extension offered in 2020, utilities were required to be in full compliance,” Frank said at the hearing. “Since Schahfer was not in compliance, Schahfer did not qualify for the extension in 2020 and should not receive the additional proposed extension.”
Schahfer’s two coal-fired units were scheduled to close in December, but the Department of Energy ordered the plant to keep running — though one unit has actually been offline since July in need of repairs. In an August email to the EPA, an official with the plant’s parent company said the coal ash extension would be necessary to justify spending money to get the plant back online.
Locals are dismayed that Schahfer may continue to run and say that no more coal ash should be placed in its unlined pond. Arsenic, molybdenum, cobalt, and radium have been found in groundwater near the pond, and the coal ash is held back by a dam with a high hazard rating, meaning its failure would be likely to cause death.
“We just see this proposed rule as a downright unlawful, reckless attempt by the Trump EPA to let polluters keep polluting,” said Ashley Williams, executive director of the advocacy organization Just Transition Northwest Indiana. She called the coal ash at the Schahfer site a “largely silent crisis that we’ve had to continue to sound the alarms on.”
Colette Morrow, a professor at an Indiana public university, told the EPA during the hearing that she suffers from an autoimmune disease and fears for her health if the Schahfer plant is allowed to keep running.
“This is unconscionable that the U.S government would put its own people at risk to such a high degree, only in order to enhance profits of these utility providers,” Morrow said.
Retired chemistry teacher Mary Ellen DeClue said she was shocked to learn about the contaminants that could be leaching into Illinoisans’ drinking water — since many rural residents tap private wells.
“This is not acceptable,” she said, imploring the EPA not to “rubber-stamp” the extension.
The three Illinois plants seeking the extension — Kincaid, Newton, and Baldwin — are owned by Texas-based Vistra Corp. The plants have already benefited from leniency under the Trump administration: Last year the company accepted the administration’s offer of an extension on complying with federal air pollutant limits.
Illinois is one of the states with the highest number of coal ash sites, according to data filed by power companies. Illinois coal plants will have to shut down by 2030 under state law, but each extra year of operation places residents at risk, local advocates say.
“Many of these communities rely on groundwater for drinking water and lack the resources to address widespread contamination on their own,” Caldwell of the Illinois Environmental Council told the EPA. “The agency should not be asking coal companies how long they would like to continue dumping toxic waste. It should be enforcing closure requirements that are already long overdue.”
2025 was, to put it very mildly, an eventful year for the U.S. power sector. The rise of data centers drove soaring electricity demand, debates about energy affordability hit a fever pitch, and the Trump administration went to unprecedented — and legally dubious — lengths to prop up coal and stymie renewables.
Yet despite the excitement, the broader electricity mix looked about the same as ever. Natural gas provided by far the biggest share of the country’s electricity, followed by nuclear, followed by coal, per U.S. Energy Information Administration data released in December.
The story gets more interesting, however, when you zoom in. Last year, solar panels produced 31.1% more electricity than in 2024, while coal-fired power plants generated 12% more megawatt-hours, according to EIA data crunched by Michael Thomas at Distilled. Natural gas generation, meanwhile, fell by nearly 3%.
Overall, power demand ticked up by 2.6% — a seismic number for a sector that has been stagnant for over a decade.
Solar’s growth is easy enough to explain: We need more power, and no source of electricity is quicker or cheaper to deploy. The rise of cost-effective battery storage has made solar even more attractive. In fact, despite the considerable roadblocks created by the Trump administration last year, solar and batteries together accounted for more than 80% of new energy capacity added to the grid between last January and November.
The dynamics around coal and gas are a bit wonkier.
Yes, as Thomas points out, President Donald Trump made a show of celebrating “beautiful, clean coal” last year. His administration also used emergency powers to order a number of aging, expensive-to-run coal plants to stay open on the eve of their planned closures. But it’s not as if Trump isn’t also supportive of the U.S.’s natural gas industry. So why the rise for one and the fall for the other?
It boils down to market forces. Gas prices spiked last year, and so did electricity demand. That bolstered the financials for some coal plants, resulting in more coal generation — and, as Thomas points out, a dirtier grid. Power-sector emissions jumped by 4.4% from 2024 to 2025, per Thomas, a significant leap and the second year in a row of rising emissions after years of consistent declines. The EIA expects coal-fired power to shrink this year, however, as more renewables come online and once again erode the economic case for burning the dirty fuel.
And despite coal’s brief resurgence, it wasn’t all positive for the fossil fuel in 2025. In fact, a separate metric may be a better indicator of its long-term outlook: For the second year in a row, wind and solar together produced more U.S. electricity than did coal.
The Trump administration’s campaign to force aging coal plants to keep running has entered a new phase: ordering broken-down units to come back online. Repairing those polluting plants could take months and cost tens of millions of dollars — all just to comply with legally questionable stay-open mandates that last only 90 days at a time.
In December, the Department of Energy ordered four coal plants — two in Indiana and one each in Colorado and Washington state — that were set to retire by year’s end to continue generating power for 90 days. Two of them have units that have been out of commission because of mechanical failure: Colorado’s Craig Generating Station Unit 1 has been down for three weeks and Indiana’s R.M. Schahfer Unit 18 has sat idle since July.
This means the utilities that own those plants must now race to bring them into working order, even though they’ve long ago deemed the facilities uneconomical to operate. Customers already grappling with skyrocketing electricity rates are likely to shoulder the costs of fixing and running the equipment. Complicating matters further is that the required repairs may not even be feasible to complete within the 90-day window covered by the DOE orders.
“Coal plants — and in particular the plants DOE has targeted — are these clunky old jalopies that, out of nowhere, just fail,” said Michael Lenoff, a senior attorney at nonprofit law firm Earthjustice, one of several environmental groups challenging the must-run orders. “DOE forcing these things to be available, and in some instances to run, actually creates reliability risk to the grid.”
The Trump administration claims that keeping the plants online is the only way to prevent blackouts in the near future. Last month’s must-run orders, as well as earlier ones forcing a Michigan coal plant and an oil- and gas-fired plant in Pennsylvania to stay open, were issued under Section 202(c) of the Federal Power Act, which lets the DOE compel power plants to operate to forestall immediate energy emergencies.
Critics say the Trump administration has weaponized this authority to prop up the U.S. coal industry, which provided about half the country’s generation capacity in 2001 but now supplies about 15%. None of the plants that the DOE has forced to stay open is needed for near-term reliability, according to the utilities, state regulators, and regional authorities responsible for maintaining a functioning grid. And despite its claims of an energy crisis, the federal government is throwing up roadblocks to wind, solar, and battery projects that are a fast and cheap way to add electrons to the grid.
The costs of the Trump administration’s coal interventions are mounting. The Sierra Club estimates that the price tag of keeping those six power plants running under the DOE’s orders has added up to more than $158 million as of this week.
And utilities that have to repair units before starting to generate power again will face a new set of costs.
In Indiana, Schahfer’s Unit 18 has been offline since July because of a damaged turbine. Vincent Parisi, president of Northern Indiana Power Service Co., the utility that owns and operates the plant, told Indiana state regulators in December, “It can take six months or longer for us to ultimately be able to get that unit back to where it would need to be to operate for an extended period of time.” Parisi did not provide cost estimates for those repairs or for extending operations at the Schahfer plant, and a NIPSCO spokesperson declined to provide an estimate to Canary Media.
In Colorado, Craig Unit 1 has been offline since Dec. 19 because of mechanical failure, according to Tri-State Generation and Transmission Association, the electric cooperative that operates and holds a partial ownership stake in the plant. “As a not-for-profit cooperative, our membership will bear the costs of compliance with this order unless we can identify a method to share costs with those in the region,” Tri-State CEO Duane Highley said in a December press release. “There is not a clear path for doing so, but we will continue to evaluate our options.”
Tri-State spokesperson Mark Stutz said the co-op and its partners don’t have firm cost estimates for repairs or for compliance with the order, “which will likely require additional investments in operations, maintenance, and potentially fuel supply.”
Consultancy Grid Strategies has estimated that keeping Craig 1 running for 90 days would cost at least $20 million, and that running it for a year could add up to $85 million to $150 million. Those costs do not include repairs of the equipment that failed and caused it to go offline.
Fixing up coal plants to comply with the DOE mandates could also put utilities in a legal bind. State attorneys general and environmental groups are already challenging many of the agency’s Section 202(c) orders, saying those orders are based on false premises and violate the law’s strictures for the agency to use its authority only to prevent immediate grid emergencies.
These arguments may soon see their day in federal court. In December, a coalition of environmental groups, including Earthjustice, filed a legal brief with the federal D.C. Circuit Court of Appeals challenging the DOE’s use of Section 202(c) authority to force the J.H. Campbell coal plant in Michigan to keep running. The brief asks the court to “put an end to the Department’s continued abuse of its authority, which has imposed millions of dollars in unnecessary costs and pollution on residents of Michigan and the Midwest.”
Nor does the DOE have authority to order utilities to undertake repairs or alterations to power plants under Section 202(c), Earthjustice, Sierra Club, and Indiana-based environmental and consumer advocates argued in a December letter to NIPSCO. The groups warned the utility that they plan to legally challenge any repair costs it tries to pass on to customers.
“The authority does not exist within Section 202(c) for DOE to force upgrades or major investments in energy-generating facilities. The authority only extends to operational choices,” said Greg Wannier, senior attorney for the Sierra Club. “I do think that at some point, regulated utilities do bear some responsibility for not taking illegal actions to comply with illegal orders.”
NIPSCO spokesperson Joshauna Nash told Canary Media that compliance with the DOE’s order is “mandatory.” The utility is “carefully reviewing the details of this order to assess its impact on our employees, customers, and company to ensure compliance,” Nash said. “While this development alters the timeline for decommissioning this station, our long-term plan to transition to a more sustainable energy future remains unchanged.”
The Trump administration seems set to continue using Section 202(c) authority. The DOE has issued three consecutive 90-day must-run orders for both the J.H. Campbell plant and the Eddystone plant in Pennsylvania. It has also issued a report that appears to lay the groundwork for justifying federal action to prevent any fossil-fueled plant from closing, citing data that critics say has been cherry-picked and misrepresented to paint a false picture of a power grid on the verge of collapse.
If the DOE continues to prevent fossil-fuel plants from closing, the costs could reach into the billions of dollars. Grid Strategies has estimated that forcing the continued operations of the nearly 35 gigawatts’ worth of large fossil-fueled power plants scheduled to retire between now and the end of 2028 could add up to $4.8 billion over that period.
Financial concerns aside, forcing utilities to react to successive 90-day emergency orders amounts to “sticking a wrench in the spokes of how utilities and their state regulators have planned their systems,” said Brendan Pierpont, director of electricity at think tank Energy Innovation.
The utilities under DOE must-run orders have developed plans to retire workers at those plants or move them to other jobs, he said. They’ve ended long-term coal-delivery contracts and procured alternative resources to make up for the lost power from the shuttering units. Some plan to convert the facilities to run on fossil gas, as is the case with the Schahfer plant and the coal plant in Washington state. Those projects will likely be delayed if the coal units must keep running, he said.
Earthjustice’s Lenoff agreed that the DOE’s intrusion into those plans is “creating uncertainty that harms investment, raises costs, and disrupts orderly planning by experts and authorities who know what they’re doing. The Department of Energy has shown that it is just blundering into markets and processes that it doesn’t understand with flimsy arguments that don’t withstand scrutiny. And other people are bearing the costs.”
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