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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.”
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.”
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy and the environment. Sign up for their newsletter here.
Venezuela has the world’s largest oil reserves, but the South American country’s heavy oil deposits also stand out for another reason; on a barrel-for-barrel basis, they pack the most climate pollution.
Following the capture of Venezuelan President Nicolás Maduro by U.S. forces, President Donald Trump said, in a social media post on Tuesday, that the country would turn over 30 to 50 million barrels of high quality crude oil to the U.S. However, Trump himself previously stated that Venezuela’s oil is “the dirtiest, worst oil probably anywhere in the world.”
Venezuela’s “extra-heavy” crude is a thick, tar-like substance that typically must be heated to bring it to the surface and diluted with other chemicals before it can move through pipelines.
“It takes a lot of energy to heat the stuff and get it out of the ground and then get it to move and flow, and then turn it into normal products,” said Deborah Gordon, senior principal in the Climate Intelligence Program and head of the Oil and Gas Solutions Initiative for RMI, a nonprofit focused on clean energy. “And every energy input means a lot of emissions.”
Greenhouse gas emissions from heavy crude oil production, refining and use are, on average, 1.5 times higher than those of light crude oil, according to a 2018 study published in the journal Environmental Research Letters. The study, co-authored by Gordon, assessed the climate impact of 75 different crude oils worldwide.
Heavy crudes are also low quality oils that require more refining, which further increases the energy used to bring the fuel to market and its associated emissions, said Adam Brandt, an energy science engineering professor at Stanford University and the lead author of the study.
Oil from Venezuela, the majority of which is extra-heavy crude, has the second-highest carbon intensity of oil from any country, a policy paper published in 2018 by Brandt, Gordon and others in the journal Science concluded.
An updated analysis by RMI’s oil and gas climate index, based on 2024 data, found that oil from Venezuela had the highest carbon intensity among 55 leading oil-producing countries.
“Just because this hydrocarbon exists doesn’t mean that it should be marketed or taken out of the ground,” said Gordon, who is the author of No Standard Oil, a book that looks at the varying climate impacts of different crude oils. “If there is demand, there are far better places to go than Venezuela.”
Leaks and intentional venting of methane gas associated with oil production in the country contribute to its outsized climate impact. Methane is a potent greenhouse gas. On a pound-for-pound basis, it is more than 80 times worse for the climate than CO2 over a 20-year period.
Venezuelan oil had the second-highest methane intensity among leading oil producing countries in 2023, according to the International Energy Agency. The country’s high leak rate is due in part to ongoing oil and gas sanctions, which have led to poor resource management, Gordon said.
A lack of proper maintenance has also led to frequent oil spills. Venezuela’s state-owned oil company Petróleos de Venezuela, S.A., reported more than 46,000 oil spills between 2010 and 2016. The company hasn’t reported any spills since then. However, in 2020, the head of Venezuela’s Unitary Federation of Petroleum and Gas Workers, a labor union, estimated that oil spills occur almost daily in some states.
Despite Trump’s pledge to open Venezuela’s oil reserves to U.S. companies, that may not result in increased production.
Simply maintaining current production levels in Venezuela would require $53 billion in new energy infrastructure investments according to an analysis released Tuesday by Rystad Energy, an independent energy research and business intelligence company headquartered in Oslo, Norway.
Kirk Edwards, president of Latigo Petroleum, an independent oil and gas producer based in Odessa, Texas, called the U.S. government’s recent actions in Venezuela a “nothing burger” for oil markets.
“This is not ‘drop a rig and up comes the bubbling crude,’” Edwards wrote on LinkedIn. “Any real turnaround would require $50–100 billion of sustained investment, modern infrastructure, and years of political stability.”
Edwards said companies are unlikely to make that investment given current low oil prices.
Gordon said Venezuela’s oil and gas sector will continue to have an outsized climate impact, whether production increases or remains in its current state of disrepair.
“They’re just basically throwing stuff into the air,” Gordon said of current methane emissions.
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy and the environment. Sign up for their newsletter here.
U.S. energy markets and policy are heading toward the equivalent of a multicar pileup in 2026.
The key factors are consumer frustration with rising energy prices, Trump administration policies that are making the problem worse despite promises to make it better and a growing awareness that investment in AI data centers is part of a bubble that could pop at any time.
I asked seven experts for their outlook on what we’ll be talking about in 2026 and almost all of them touched on this set of intertwined problems. Call it a crisis or a disaster. Or just call it terrible politics for the party in power ahead of November’s midterm elections.
Robbie Orvis, senior director for modeling at the think tank Energy Innovation, said he expects energy affordability to be the major issue of the year. He pointed to the rising wholesale price of natural gas and how that is likely to translate into higher utility bills, since gas is the country’s leading fuel for power plants and home heating.
“I don’t anticipate that people’s home energy bills are going to go down anytime soon,” he said.
The country’s benchmark price of natural gas has risen from an average of $2.19 per billion BTUs in 2024 to forecasts of $3.19 in 2025 (full-year figures for 2025 are not yet available) and $4.01 in 2026, according to the Energy Information Administration’s short-term outlook.
Gas prices are rising for many reasons, including an increase in exports of liquified natural gas, mainly to Europe, and growing demand from U.S. gas-fired power plants.
Orvis also highlighted the Trump administration’s policy of requiring old coal plants to remain online, even when their owners would otherwise have closed them for economic reasons. The administration has done this several times, citing the need to maintain the grid’s reliability during periods of high demand.
The result is that utilities are forced to operate plants they wanted to close, which are dirtier and more expensive than readily available alternatives.
Meanwhile, the least-expensive option for new power plants in most of the world is utility-scale solar. Even if we include the cost of batteries to allow solar to be stored for nighttime use, solar is a low-cost leader, as shown by research that includes a report last month from energy think tank Ember.
The federal government could respond to rising prices by rapidly building new power plants. But the country’s permitting system, supply chains and recent policy decisions are harming the ability to provide relief.
Some of these problems predate the Trump administration. But President Donald Trump has made things worse with executive orders that add restrictions on the development of wind and solar power, including a stop-work order in December that halted construction on five offshore wind projects.
Michael Webber, a professor of engineering and public affairs who studies energy at the University of Texas at Austin, puts this problem in the form of a question:
“Do we return to normal for permitting energy projects or will every project have to price in the risk that the president might impulsively cancel it?” he asked in an email.
He said this risk is a cost driver for developers that will be enough to stop some marginal projects and drive up rates for consumers.
Our crystal balls are not super precise on some topics. For example, several people said the investment in AI data centers and forecasts of rising electricity demand to power them are part of an investment bubble. But it’s unclear if this market will face its reckoning in 2026 or later.
The larger problem is that AI companies are spending tens of billions of dollars to build gigantic, energy-sucking data centers, often without clear plans for how these projects are going to make money.
“There’s a bubble, and what’s going to end up happening is there’s going to be a consolidation,” said Stephen A. Smith, executive director of the Southern Alliance for Clean Energy, an advocacy group based in Knoxville, Tenn.
In a consolidation, the companies with the weakest business plans will go bust and the companies with viable plans and ample cash reserves will pick over the wreckage.
One of the main questions, Smith said, is how much consumers will need to cover the costs of unwise investments to power data centers.
The worst-case scenario would be if utilities make substantial investments to meet data center demand and the demand doesn’t fully materialize, leaving the costs to be paid by households and other consumers.
Some states, including Indiana and Ohio, have adopted rules to try to make data center developers assume much of this risk. But much of the country has yet to thoroughly explore what happens to utilities and their consumers in a data center bust.
State utility commissions have helped set the table for the affordability crisis by approving rate increases and spending that push the limits of what ratepayers can afford.
Commissioners, along with governors and members of state legislatures, “are finally taking heed of their policy missteps,” said Kent Chandler, senior fellow for the think tank R Street Institute and former chairman of the Kentucky Public Service Commission.
Chandler expects that some state-level discussions will focus on introducing competition in areas where utilities now have local monopolies, with the hope that market forces can help contain costs.
At the same time, states and regions that already allow competition in electricity and natural gas markets may go in the opposite direction and explore giving utilities more leeway to build power plants and pass costs on to consumers.
If this sounds disjointed, that’s because it is. The larger point is that officials will respond to frustration with rising prices by wanting to be seen as taking action.
The decision by Congress and Trump to eliminate consumer tax credits for electric vehicles will cast a pall on at least the first half of 2026 and maybe longer. The credit phaseout in the One Big Beautiful Bill Act last summer led to a sudden surge in EV purchases before the incentives expired at the end of September, followed by an expected drop-off in sales.
“We’re going to see sales be a bit more tepid,” said Mryia Williams, executive director of Drive Electric Columbus in Ohio.
The problem is that potential buyers “are not sure what’s going on with anything,” she said.
Automakers have some high-profile EVs coming this year, including the redesigned Chevrolet Bolt and the new Rivian R2. But some companies also are reducing and redirecting their funding for EVs, including Ford, which discontinued the F-150 Lightning pickup as a fully electric model and is replacing it with a gas-electric hybrid.
Williams has concerns that eliminating tax credits sends the wrong message to automakers and consumers at a time when other countries are moving ahead of the United States in building the vehicles of the future. That said, she remains confident that the world will make a near-complete shift to EVs, even if U.S. policymakers decide they want to move more slowly.
It’s normal for the party that’s not in power to gain seats in Congress in the first midterm election after a presidential election. And, considering that Republicans’ majority in the U.S. House is fewer than five seats, it would surprise nobody if Democrats win control of the chamber.
The larger questions are about the scope of Democrats’ gains, including whether the party will pick up enough seats to gain control of the U.S. Senate and make substantial progress in governor’s offices and state legislative chambers.
A big part of the answer will depend on how effectively Democrats communicate their agenda in terms of voters’ affordability concerns, said Caroline Spears, founder and executive director of Climate Cabinet, an advocacy group that supports pro-climate candidates in state and local races.
“Voters are angry about rising prices, and we have an undercurrent of instability in the economy that has become more of a feature rather than a bug in the last few years,” she said.
Spears’ organization is focusing on states such as Arizona, Michigan, Minnesota and Pennsylvania, where flipping just a few seats could make a big difference on climate and energy policy.
She highlights Arizona as a state with a huge upside in terms of Democrats being close to having enough control to unlock more of the economic benefits of solar power.
“The extreme anti-clean energy legislation we’re seeing out of the sunniest state in the country is just astonishing,” she said.
To underscore this point, she noted that Massachusetts has more solar power jobs than Arizona, a fact that should be upsetting to Arizonans.
Now it’s time for the closer: Amory Lovins, an engineer and cofounder of RMI, has done about as much as anyone to foster research and advocacy about energy efficiency and conservation.
I saved him for last because the discussion of rising energy demand should, and could, turn into one about the need for greater efficiency.
Efficiency can take many forms, including batteries with higher energy density, solar panels that can capture more sunlight and computer servers that require less electricity to perform the same tasks.
He expects to see progress in 2026 but thinks more about how actual progress compares to what could be achieved with the right investment, research and policy support.
The obstacles aren’t technical or economic, he said. They’re mainly cultural and institutional.
“This is not low-hanging fruit that you harvest and then it gets scarce and expensive,” he said. “This fruit has fallen off the tree and is mushing up around our ankles, rotting faster than we can harvest more.”
He didn’t discuss efficiency in partisan terms, but I will. We have a president who has taken steps to weaken government requirements that products become more efficient, casting this as a matter of consumer choice. Trump said in his “Unleashing American Energy” executive order that he is safeguarding “the American people’s freedom to choose from a variety of goods and appliances” including lightbulbs, dishwashers, washing machines, gas stoves, water heaters, toilets and shower heads.
While Trump said this is a consumer-friendly action that will save money, decades of research on efficiency standards show the opposite to be true. The Trump administration has said its actions on the standards will save $11 billion, but this is based on an estimate of the cost of the rules that doesn’t include savings on utility bills. If we consider the costs and benefits, the standards have a net savings of $43 billion, according to an analysis from the Appliance Standards Awareness Project.
So, in an election year amid an energy affordability crisis, one side is actively hostile to energy affordability.
Other stories about the energy transition to take note of this week:
Offshore Wind Developers Seek Quick Court Resolution to Allow Construction to Resume: Ørsted and Equinor, two of the companies building offshore wind farms, have gone to court to seek permission to resume construction of two large projects that were stopped by a Trump administration order, as Diana DiGangi reports for Utility Dive. This is in addition to Dominion Energy’s request that a court allow it to resume work on a separate offshore wind farm, which will be the subject of a hearing next week. Interior Secretary Doug Burgum had ordered a stop to construction last month, saying there is new evidence that offshore wind could pose national security risks, but he didn’t go into detail about the risks.
Negotiations on Permitting Reform Hit a New Roadblock: The Trump administration’s stop-work order for offshore wind has made Senate Democrats pause negotiations on a measure that would streamline the federal process for approving construction of new energy projects, according to Sen. Shelden Whitehouse, D-R.I., as reported by Kelsey Brugger of E&E News. Members of both parties have been working on this proposal, but there remain some major sticking points, including the fact that House Republicans want the legislation to favor fossil fuel projects and Democrats are asking for limits on the Trump administration’s ability to pick and choose which projects happen.
EVs Take a Back Seat at Consumer Electronics Show: The Consumer Electronics Show, taking place now in Las Vegas, has become a showcase for new EV models and technologies in recent years. But this year, automakers are not planning any major debuts of new EVs, signaling a shift in emphasis for manufacturers in response to the Trump administration cutting incentives for the vehicles, as Abhirup Roy reports for Reuters. Instead, much of the emphasis this year is on AI, robotics and self-driving vehicle technologies.
Inside Clean Energy is ICN’s weekly bulletin of news and analysis about the energy transition. Send news tips and questions to dan.gearino@insideclimatenews.org.
Five and a half months. That’s all the time Donald Trump needed to crush the only major climate law the United States ever managed to pass. It was swift work, using a sledgehammer and not a scalpel, and now the energy transition will have to make do with the fragments of the law that remain.
The words bleak and dispiriting come to mind. How else to describe the fact that the U.S. entered the year implementing an ambitious if inadequate decarbonization law, and is now exiting 2025 with that law all but repealed?
But there were also some reasons to be hopeful about the energy transition this year — if you knew where to look.
Let’s start with the numbers. During a year full of headline-grabbing destruction of U.S. clean energy policy, renewables still led the way. Through November, a whopping 92% of all new electricity capacity built in the U.S. came in the form of solar, batteries, and wind power. Electric vehicle sales hit a record, too — nearly 440,000 in the third quarter of the year — though the surge was driven in large part by consumers rushing to buy EVs before the disappearance of a federal tax credit axed by Trump.
There were also intriguing moments of alignment between Trump’s “energy dominance” agenda and the transition away from fossil fuels. Geothermal and nuclear are two sources of carbon-free energy that the administration has, for whatever reasons, deemed desirable. So while the One Big Beautiful Bill Act eviscerated much of President Joe Biden’s Inflation Reduction Act, it spared tax credits for geothermal systems. And Trump has not only preserved Biden-era funding for nuclear projects but expanded it — possibly by orders of magnitude if an $80 billion plan for partially state-owned nuclear reactors actually happens.
The most important thing we saw this year is that Trump simply can’t stop the energy transition. Sure, he can slow it. He already has. But try as the administration might, there are forces at play bigger and more stubborn even than politics.
To be specific: Electricity demand is growing quickly in the U.S., and clean energy is the least expensive and most readily available way to keep pace.
The Trump administration would certainly prefer to meet rising demand with coal and gas, but in many cases it’s simply impractical.
Coal is increasingly the most expensive form of electricity. Gas, for better or for worse, certainly will help meet some of this new demand — but it faces very real supply-chain constraints. Gas turbines are sold out among major manufacturers, with wait times stretching as long as seven years.
When the country is clamoring for more electrons and voters are increasingly upset about rising power bills, and the only thing that can be built quickly is solar and storage, renewables will simply have to be built. (They’ll just cost more than they would have without Trump.)
So while it hasn’t been a good year for clean energy in the U.S., the transition now has enough momentum that even a terrible year amounts to more of a slowdown than a derailment. It’s a matter of inertia.
When Donald Trump won the presidential election last November, it wasn’t totally clear how serious he was about dismantling offshore wind. Sure, he liked to rant about turbines making the whales crazy, and there was the infamous legal fight over a wind farm off the coast of his golf course in Scotland. But would he really try to cut down an entire energy sector? Did he even have the power to do so?
The answers, as we found out in this decisive and devastating year, are yes and pretty much.
On his first day in office, Trump issued an executive order that froze offshore wind permitting and ordered the Interior Department to review the projects it had already approved. The move immediately gummed up any developments that didn’t have federal permits, but the upshot was murkier for the nine projects with approvals in hand. (In mid-December, a federal court struck down that executive order.)
The first already-permitted undertaking to crumble was the Atlantic Shores installation in New Jersey. In late January, Shell — one of the two developers — announced it was pulling out. Then New Jersey backed away from buying power from the turbines. Weeks later came the sea salt in the wound: The Environmental Protection Agency revoked a Clean Air Act permit for Atlantic Shores.
Trump’s war on offshore wind escalated from there, threatening the viability of a reliable form of electricity even as the president declared an “energy emergency” in the United States.
The administration halted work on New York’s 810-megawatt Empire Wind 1 project in April; construction resumed after about a month and nearly $1 billion in costs for the developer. The budget law passed by Republicans in July killed tax credits for wind farms that don’t come online ASAP. The 704-megawatt Revolution Wind installation near Rhode Island got a stop-work order, too; that one was also lifted after about a month. The Transportation Department yanked funding for a bunch of infrastructure projects related to offshore wind in September. Then Trump told a half-dozen agencies to root around for reasons to oppose installing turbines out at sea.
Just for good measure, the administration is still trying — and sometimes failing — to revoke permits for approved but earlier-stage installations that would likely struggle to begin construction anyway, given the, uh, inhospitable climate.
The clearest way to understand the carnage is to look at the numbers.
When Trump was elected last November, BloombergNEF expected the U.S. to build 39 gigawatts of offshore wind by 2035. The research group hedged that number to 21.5 gigawatts if Trump managed to repeal wind tax credits during his term. (Reminder: He did.)
BNEF now expects just 6 gigawatts to be built by 2035 — an amount equivalent to the capacity of the five wind farms currently under construction, as well as America’s only completed large-scale project, New York’s South Fork. Should Trump’s late-December pause on all of these in-progress wind farms result in cancellations, the number will be even lower.
The energy source, long considered a cornerstone of grid-reliability and decarbonization plans in the Northeast, was already in a fragile place before Trump took office for the second time. Inflation and pandemic-era supply-chain thorniness had scrambled economics. Local opposition, both astroturfed and real, was on the rise. Major projects from major developers had already fallen apart.
Trump’s all-out war would have been difficult for any industry to survive. But for a nascent one that was already in deep water — and which is uniquely dependent on federal permitting — it was all but impossible.
The question now is whether the Trump 2.0 era will prove to be a four-year blip or the start of longer-term doldrums for the sector in America.
“Electricity is the new price of eggs.”
The memorable quote from Charles Hua of consumer advocacy group PowerLines sums up the current conversation on energy affordability, which defined federal, state, and local policy and politics this year.
Americans are in the midst of a broader cost of living crisis, spurred by the first real bout of inflation in decades. Electricity bills have become a major driver of that worrisome trend, with costs rising at more than twice the rate of inflation over the last year, largely because it’s expensive to maintain, expand, and repair the grid.
Now, President Donald Trump’s policies are making the bad situation worse — despite his frequent promises to bring down costs. On his first day in office, Trump declared an “energy emergency,” saying Americans faced an “active threat” from high energy prices and that the country needed an “affordable and reliable domestic supply of energy” to curb them.
“Reliable” is code for coal and gas in the Trump administration’s book. The U.S. Department of Energy has used the “emergency” to keep fossil-fueled power plants open past their retirement dates and to prop up the dying coal industry, at great expense to ratepayers. A Michigan coal plant that was supposed to shutter in May instead racked up $650,000 each day in costs for ratepayers after the DOE ordered it to keep running. That number will only grow as the plant runs through the winter.
Meanwhile, the administration has retaliated against cheaper and quicker ways to get more power online: namely, renewables and battery storage. The One Big Beautiful Bill Act, which Trump signed in July, scraps tax credits for solar and wind deployment as well as incentives for home energy improvements. The result? Fewer cheap clean energy projects will be built, and by 2035 the average American household will pay $170 more each year for energy than they do now, according to the think tank Energy Innovation.
It’s not just electricity. Natural gas prices are expected to rise this winter as well, and a delay in the distribution of federal home heating assistance, spurred by the government shutdown, will only exacerbate the challenge for families. More cuts to federal programs that help households reduce their energy usage and bills, including Energy Star and the Weatherization Assistance Program, could still be on the way.
The urgency of the energy affordability situation is starting to shape politics at the state and local level, too.
Throughout the year, blue-state lawmakers have invoked affordability both to bash the Trump administration for stymieing renewables — and to excuse their own backtracking from climate goals. That dichotomy has been especially apparent in New York, which in July passed a groundbreaking ban on new gas hookups that was expected to lower families’ energy usage and bills, but then paused its implementation just a few months later. In November, New York also authorized a gas pipeline project it had rejected three times before. Democratic Gov. Kathy Hochul has cited affordability concerns for her decisions.
Affordability also factored in on Election Day.
New Jersey’s Democratic Gov.-elect Mikie Sherrill campaigned on the promise of building out more clean energy, including offshore wind, to curb rising prices. In Virginia, Democratic Gov.-elect Abigail Spanberger and Democratic state legislators ran their successful campaigns on the promise of curbing power prices in the data center capital of the world. And in Georgia, where rates are rising fast, two Democrats who promised a focus on affordability and “clean, reliable energy” unseated Republican incumbents on the regulatory commission that oversees ratemaking for the state’s utilities.
The problem is likely to dominate the conversation again next year, exacerbated by concerns about data centers gobbling up power and Trump administration policies making it hard to build new electricity generation. Consumer advocates have called for officials to take bold action — including reducing utility profit rates and finally making it possible to build transmission lines — to alleviate the rising prices. We’ll see if any of those solutions actually come to fruition in 2026.
Disclosure: Charles Hua is a member of Canary Media’s board of directors. The board has no influence over Canary Media’s reporting.
Rooftop solar and home batteries are way more expensive in the U.S. than in most countries, largely due to slow and burdensome local permitting and utility interconnection processes.
But there are tools installers can use to bring down these so-called “soft costs,” which make up about two-thirds of the price of installing solar, batteries, and EV chargers in the U.S.
One of the most effective such tools is called the meter socket adapter — and major home-electrification companies are increasingly making use of it. Over the past few years, companies including Tesla, ConnectDER, and Enphase have won approval from a growing number of utilities to use these devices to circumvent complex electrical work that can add days of labor and thousands of dollars in costs to installations.
Recent regulatory momentum in California, the largest home solar market, is also boosting the tech, which takes the form of a metal ring that’s inserted between utility meters and the meter boxes that connect homes to the grid. Inside each meter socket adapter is all the technology needed to connect, protect, monitor, and control solar, batteries, EV chargers, and other electrical devices.
Using tools like these to decrease soft costs is increasingly important as utility bills climb nationwide and regulatory headwinds threaten to make solar more expensive. Federal tax credits for home electrification expire at the end of this year, and several states have pared back compensation programs for solar owners.
Meter socket adapters are also a no-brainer for installers to use, according to Marcelo Macedo, who previously worked at SolarCity and Tesla and now runs his own installation company, Coastside Clean Energy. He said they can turn a multi-day job into a simple, half-day, plug-and-play exercise, largely because they help standardize projects.
“You can supervise more people doing more work faster, and most importantly, more predictably,” he said. “You can more reliably close out jobs on a tighter time frame with fewer hiccups. Your time to cash flow is more predictable. That leads to saying yes to more jobs, and being able to get more jobs done in a month.”
Meter socket adapters can generate serious — if highly varied — savings.
So says Colby Hastings, senior director of residential energy at Tesla, whose meter socket adapter device called the Backup Switch has been approved for use by dozens of utilities across the country, including Green Mountain Power in Vermont, Commonwealth Edison in Chicago, and all of the biggest utilities in the solar-rich states of Arizona and California.
Where utilities have cleared their use, “the Backup Switch can save thousands of dollars on a typical installation in both material and labor,” she said.
Exact figures depend on the particulars of household meter design and configuration and what equipment is being installed. On average, the Backup Switch can deliver savings of about $335 in hardware costs and about $360 in labor costs per storage installation, according to a report Tesla published this summer. More complicated projects can see greater savings, Hastings said. And Tesla Cybertruck owners get the added benefit of being able to use the Backup Switch to connect their EV battery for home backup power.
Most of those savings come from avoiding the need to relocate key household circuits into a different electrical panel for battery backup, Hastings said. A separate remote energy meter will still be necessary for homes that only want to back up a subset of their circuits. But for whole-home backup setups using a Backup Switch alongside a Powerwall battery, installation can be as quick as “a few hours,” she said, compared to more than a day needed to install equipment and run conduits if a battery is installed without the Backup Switch.
To be clear, meter socket adapters aren’t helpful for every home that wants to go solar. But for those adding solar and storage or an EV charger, it’s more likely than not that they can speed things up and shave some cost.
Home design also matters. Meter socket adapters are particularly useful for homes with meter boxes located right above the circuit breakers. These “meter-main combos” are more common in warmer climates, including California, the country’s top home solar and battery market.
Meter-main combos can make it particularly hard to install home energy tech through the electrical panel, said Raghu Belur, chief product officer at solar microinverter and battery vendor Enphase. Their tight configuration leaves no room for the microgrid controllers that automatically isolate homes when the grid goes down, or the current transformers that can measure power flows on home circuits.
Meter socket adapters simplify things because they integrate all of these devices into a single unit. Enphase has its own meter socket adapter now approved by nearly 50 U.S. utilities.
“It has a powerful 200-amp switch inside it to isolate the home during outages,” Belur said of the device. “That dramatically reduces the balance-of-system costs” and can “save thousands of dollars in labor.”
Meter socket adapters are also far more elegant systems, said John Bergh, CEO of Bay Area solar installation company Cobalt Power Systems. He likened the custom-designed webs of electrical conduits, transfer switches, junction boxes, and electrical sub-panels typically required to install batteries to a “wall of spaghetti” on a home.
“If you think about one crew having to take three to four days to install a battery system with a traditional transfer switch or system controller or gateway, versus a crew that can now do multiple installations in one day with a Backup Switch and Powerwall 3, it’s much more scalable,” he said. That means getting “more clean energy installed faster, which is what we’re all looking for.”
But for meter socket adapters to put a real dent in soft costs, more utilities will have to let installers use them — and getting utilities comfortable with third-party devices that plug into their meters has been a long slog.
Whit Fulton, CEO of ConnectDER, knows just how long it has taken. He launched his meter-socket-adapter company in 2011, and won his first utility project in 2015 with Green Mountain Power, which is in the vanguard in deploying solar-charged batteries in households. Similar utility-led projects have followed in Arizona, Hawaii, and New York.
But it wasn’t until more recently that ConnectDER has been able to supply a meter socket adapter for use by solar and battery installers. “It’s been a crawl-walk-run approach,” Fulton said, driven as much by policymaker pressure as by utility acceptance.
One big win came in 2021, when Colorado state lawmakers passed a law that required utility Xcel Energy to allow customers to use meter socket adapters to connect solar systems. “Xcel adopted it, and it worked pretty well,” he said. “From there, we were off to the races,” with utilities in 25 states serving a collective 30 million households now allowing some use of ConnectDER’s meter socket adapter designed for installation with home solar systems.
A separate ConnectDER meter socket adapter designed for installation with EV chargers has also been approved for use by 21 utilities in 14 states, he said.
This summer, ConnectDER launched its latest product, dubbed IslandDER, built specifically to simplify whole-home battery backup systems that are an increasingly common add-on for homes installing solar or looking for alternatives to fossil-fueled generators, Fulton noted. IslandDER is being used by partners including Lunar Energy, FranklinWH, SolarEdge, and EcoFlow, with test installations in 12 states and larger-scale deployments expected next year, he said.
Getting approvals for these devices is not easy. Utilities are cautious by nature. For Tesla to notch its dozens of approvals, Hastings said it took years and “hundreds, if not thousands, of meetings.”
At the same time, California regulators helped push utilities to accept meter socket adapters with a decision this summer that “created a regulatory framework by which the utilities have to review products like these, and create an avenue for approval,” said Kyle Breuning, director of applications and fleet analytics for Lunar Energy, a home-battery and energy-controls startup.
Ultimately, Hastings would like Tesla’s Backup Switch to be an option for installers across the country. Right now, only about 40% of the projects installed today that could use a Backup Switch are allowed to do so, she said.
“It’s safe, it’s reliable, it’s field-tested. It has gone through extensive processes with many utilities,” she said. “I can’t think of any good reason not to approve it.”
A correction was made on Dec. 22, 2025: This story originally misstated Kyle Breuning’s title. He is now director of application and fleet analytics for Lunar Energy, not senior manager of applications engineering.
Two years ago, Massachusetts regulators created a framework for phasing out the use of natural gas in buildings — a groundbreaking move for the state’s decarbonization efforts. Today, however, momentum has slowed as gas companies clash with lawmakers, regulators, and advocates on a fundamental question: Are utilities legally obligated to provide gas service to any consumer who wants it?
The debate may seem arcane, but at stake is the speed and scope of Massachusetts’ clean energy transition — and one of the nation’s first major attempts at a managed shift away from gas.
National Grid, Eversource, and other gas utilities say the answer is a resounding yes. The ability of residents and businesses to choose gas service is a “fundamental right,” said Eversource spokesperson Olessa Stepanova: “We cannot force them off that service.”
On the other side of the argument, advocates contend that safeguarding public health and fighting climate change are urgent benefits that outweigh individual customers’ personal preferences for one kind of fuel. The obligation, in their view, is to provide functional heating — not a specific source. The utilities, they say, are looking for ways to delay an inevitable upheaval in their industry rather than collaborating on a smooth transition.
“They see this as an existential threat to their business model, and they are digging in. They’re not at the table,” said James Van Nostrand, who chaired the Massachusetts Department of Public Utilities when it issued the 2023 order, and who is now policy director at The Future of Heat Initiative.
Massachusetts has long been a leader in pushing for a transition away from using natural gas and other fossil fuels to heat buildings and to fuel stoves and dryers.
In October 2020, the state was one of the first in the nation to launch a “Future of Gas” investigation, a process examining how gas companies can play a role in the clean energy transition and what that should look like. In December 2023, the state Department of Public Utilities wrapped up the investigation with a 137-page report that spelled out a clear vision of stopping the expansion of gas service and decommissioning some portions of the infrastructure, but largely left it to lawmakers, regulators, and utilities to enact the principles outlined.
The future laid out in the document goes like this: Rather than automatically investing in new gas infrastructure or replacing aging pipes, utilities will look for opportunities to deploy “non-gas pipeline alternatives” — like geothermal networks, air-source heat pumps, energy efficiency, or demand response — that can meet customers’ needs. Gas utilities will proactively coordinate with electric utilities to ensure the poles and wires can accommodate, say, switching dozens of houses in an area to heat pumps. The order also calls for utilities to undertake demonstration projects to test out the process of transitioning neighborhood-scale portions of the gas system to electrified heat or thermal networks.
The order called for gas utilities to submit plans detailing how they would assess whether an area could be equally or better served by a non-gas option. They did so in April 2025, but there is a catch: Utilities insist that they need customers to agree to participate in any such alternatives.
“It’s very hard to accomplish any decommissioning if you have to have that 100% buy-in from all the customers,” Van Nostrand said.
At the heart of the utilities’ argument is the legal concept of “obligation to serve.” The idea, a common principle in utilities regulation, is that a gas utility can’t just cut off customers it is already serving; if you want to keep gas, you get to. Requiring customers to modify their equipment would infringe on their constitutional property rights, the gas utilities argue.
The Mass Coalition for Sustainable Energy, a coalition of business groups, labor unions, and professional associations, has its own concerns about accelerating a transition away from natural gas. The group argues that pushing customers from gas to electric heat could increase energy bills and possibly compromise grid reliability.
Advocates, however, say the utilities are seizing on the idea of obligation to serve to justify dragging their feet on a transition they don’t want to see happen.
“If policymakers are trying to do something utilities don’t like, delay is always a tool they will use to resist it,” said Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation.
What’s more, according to advocates, lawmakers, and the state attorney general’s office, is that the utilities are wrong on the law. They argue that utilities are allowed to withdraw gas service in certain circumstances, such as lack of payment or for reasons of health, safety, and other purposes defined in law. A climate law passed in 2024, they say, provides such a definition by specifically identifying the reduction of greenhouse gas emissions as a factor that may be considered when deciding whether gas service can be discontinued. It also specifies that regulators must consider whether “adequate substitutes” are available for heating and cooking.
Furthermore, the utilities’ argument about the importance of consumer choice ignores the fact that their position takes away choice from the households who would want to join a geothermal network, said Amy Boyd Rabin, vice president of policy and regulatory affairs for the Environmental League of Massachusetts.
“I want customers to be able to move into the future and not be weighted down by having to continue to pay for a fossil fuel infrastructure that they didn’t ask for and they don’t want,” she said.
The Department of Public Utilities is currently in the process of asking utilities for more details about their arguments and considering feedback from other stakeholders. Advocates expect that regulators will ultimately disagree with utilities’ understanding of the obligation to serve, sending the question to court.
Though Massachusetts was among the first to start formally planning a transition off gas, the utilities’ resistance means the process is moving too slowly, advocates said. And substantial progress is unlikely to occur until the question of what obligation to serve really entails is settled.
“That’s a very important legal question that underpins any attempt to move forward in a meaningful way on gas transition,” Peale Sloan said.
The Trump administration’s determination to keep fossil-fueled power plants running beyond their scheduled closure dates is creating uncertainty about the fate of two Indiana coal facilities set to retire by the end of this year.
Northern Indiana Public Service Company’s 722-megawatt R.M. Schahfer plant, in the small town of Wheatfield, is supposed to close this month. So is CenterPoint Energy’s 90-megawatt F.B. Culley 2, along the Ohio River in southern Indiana.
But the utilities explained to state regulators during a December 2 biannual hearing on reliability that they are preparing for potential Trump administration orders to keep the units operating, and some fear such mandates could come any day.
Already this year, the Department of Energy has forced a coal plant in Michigan and an oil and gas plant in Pennsylvania to operate past scheduled retirement dates.
The Trump administration has said coal plants need to stay open to address energy shortages. The Federal Power Act allows the government to temporarily order power plants to operate in case of such an emergency. Indiana Gov. Mike Braun (R) issued an executive order in April echoing the president’s concerns and promising to evaluate and “consider extending the life” of every coal plant in the state.
Community leaders say keeping Schahfer or Culley online will mean unacceptable and unnecessary health risks and costs.
Braun’s executive order notes that 9 gigawatts of coal-fired power are scheduled to retire between 2025 and 2038 in Indiana.
“Now we’re concerned about every single coal plant in the state [scheduled for] retiring,” said Ben Inskeep, program director of the Citizens Action Coalition, which represents consumers statewide. “Utilities are facing extreme pressure to keep coal plants open from the political powers that be.”
At the recent reliability hearing, NIPSCO CEO and chief operating officer Vince Parisi told regulators that he was taking steps to be ready for an emergency order to keep running Schahfer, including checking on coal supply and equipment needed to make major repairs to one of the plant’s units, which has been offline since July.
In June, the Indiana Utility Regulatory Commission approved a settlement agreement stating the Schahfer plant will close this year. Utility spokesperson Jessica Cantarelli affirmed to Canary Media that “absent a directive to stay open, NIPSCO is on track to retire R.M. Schahfer’s remaining two coal units by the end of 2025.”
But documents show that NIPSCO has not only prepared to run the plant longer but also sought a means to do so.
Fred Gomos, senior director of environmental policy and sustainability at NIPSCO’s parent company, NiSource, emailed the Environmental Protection Agency in early August asking for an extension on a deadline to stop dumping toxic coal ash in an unlined waste pond. Later that month, Gomos followed up with the EPA and mentioned that the company had met with Department of Energy officials about the issue.
Gomos said the coal ash extension was necessary for the company to “justify” capital investments to keep the plant operating. On November 25, the EPA proposed granting the extension to Schahfer and 10 other plants nationwide. Twelve plants had previously requested exceptions to a 2021 deadline to stop putting waste in unlined repositories, which often leak contaminants into groundwater; one was denied. The other requests were never granted, but their filings allowed the plants to put ash in unlined ponds through October 2028. The EPA’s recent proposal, which is open for public comment through January 7, 2026, would allow the 11 plants to dump coal ash in unlined ponds through October 2031.
Cantarelli said Schahfer’s “retirement has not been impacted by EPA’s proposal to extend coal ash–related compliance deadlines,” and did not respond to a question about Gomos’ email seeking the extension.
The EPA proposal noted, “NIPSCO has stated that RM Schahfer would operate its coal-fired boilers until 2028 if the proposed rule change was finalized.” A correction issued December 1 clarified that NIPSCO said it “could potentially operate coal-fired boilers until 2028.”
Three coal plants in Illinois, two in Louisiana, two in Texas, and one each in Ohio, Utah, and Wyoming would also be covered by the coal ash extension.
Earthjustice senior attorney Lisa Evans explained that while a rule under the first Trump administration created the extension through 2028, the EPA never ruled on the plants’ requests. In her view, that makes the proposed extension to 2031 an illegal way that the Trump administration is trying to prolong the life of coal plants.
“The rule did not just give extensions to coal plants to operate unlined surface impoundments with no strings attached,” Evans said. “The plants had to meet specific criteria to be able to continue to operate those unlined impoundments. The Trump administration has not evaluated their compliance and whether they have adequately remediated groundwater contamination.”
Monitoring data reported by NIPSCO shows molybdenum, arsenic, and other contaminants at high levels in groundwater near the Schahfer plant’s unlined pond.
“EPA has to make sure these utilities are operating in a way that’s protective of health and the environment,” Evans said. “They’ve thrown that out the window for the purported reason of throwing more energy into the grid.”
Three times this year, the Trump administration has ordered the J.H. Campbell coal plant in Michigan to keep running for stretches of 90 days past its planned retirement, most recently on November 18. The extension has cost ratepayers $615,000 per day, even as studies show that no energy-shortage emergency exists.
The federal National Energy Regulatory Commission has found that there is an adequate supply of electricity this winter to power the grid that covers Michigan and Indiana.
NERC’s recent reliability report found “limited risk” in the Midcontinent Independent System Operator’s grid, adding that the grid operator has procured more energy than required.
Data centers for AI are expected to steeply increase electricity demand in coming years, but experts say aging coal plants are not the way to meet that demand. The Schahfer and Culley plants, for example, are hardly well suited to provide significant reliable power.
The Culley plant is CenterPoint’s “smallest and most inefficient coal unit,” the company noted in a 2025 planning summary. Shane Bradford, vice president of CenterPoint’s Indiana Electric, told regulators in the December 2 hearing that the company had enough coal to continue running the plant if forced to.
“We are very concerned this unit could be the target of a [Federal Power Act] 202(c) order this month, given the very assertive stance the Trump and Braun administrations are taking on preventing any coal plant from retiring,” Inskeep said about Culley.
The Schahfer unit that has been offline since July 9 because of turbine problems will need to be “rebuilt” over about six months in order to keep operating, Parisi told regulators. Schahfer’s other coal unit also had outages for hundreds of hours over the summer, caused by leaks in boiler equipment, said David Saffran, NIPSCO generation business systems administrator in the operations management reporting.
“This is the coal plant DOE says must stay on even though it’s not been very reliable and will cost ratepayers to go back online?” said Inskeep. “Shouldn’t this be a natural one to retire?”
A correction was made on Dec. 15, 2025: The 2020 EPA rule extension was created under the first Trump administration, not the Biden administration.
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