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The Trump administration has extended its order to keep a Michigan coal-fired power plant running until November, well past its planned closure in the spring. It’s the latest move in a push to force dirty, expensive power plants to keep operating, which experts warn could saddle Americans with billions of dollars in unnecessary electricity costs.
Just days before the J.H. Campbell plant was set to shutter in May, the administration ordered it to stay open for 90 days — an unprecedented federal intervention in state-regulated utility operations. That order has already cost Midwest utility customers millions, and Michigan’s top utility regulator estimates that keeping the aging plant open longer could burden consumers with more than $100 million in unnecessary costs.
The Department of Energy’s Wednesday extension adds weight to concerns from states, environmental advocates, and clean-energy industry groups that the administration intends to wield emergency powers meant to address true threats to grid reliability to prevent any fossil-fueled power plant from closing nationwide. Doing so would cost consumers between $3 billion and nearly $6 billion per year by the end of President Donald Trump’s term, per an August report from consultancy Grid Strategies.
“The order purports to override the considered judgment and careful work of many federal, state, and regional bodies who actually have authority to keep the lights on,” Michael Lenoff, senior attorney for nonprofit Earthjustice, said in a Thursday statement.
Lenoff is leading litigation against the DOE’s initial order from May. Michigan’s Attorney General Dana Nessel has also challenged that order in court, after the agency failed to respond to requests from environmental groups and eight state utility commissions seeking a rehearing of the decision.
To keep fossil-fueled plants running, the Trump administration is taking advantage of Section 202(c) of the Federal Power Act, which gives the DOE the authority to take temporary action to address nearterm grid-reliability emergencies. But many groups say there is no such crisis: Wednesday’s order from Energy Secretary Chris Wright, a former gas industry executive and well-known denier of the climate-change crisis, “points to no evidence of an imminent emergency requiring Campbell to keep racking up the bills paid by customers in Michigan and nearby states,” Lenoff said.
“Despite already forcing the plant to run for 90 days, [Wright] points to not a single instance where the plant was needed to keep the lights on,” Lenoff said.
Consumers Energy, the utility that owns J.H. Campbell, reported in late July that it cost $29 million to operate the plant in the first five weeks of the DOE’s stay-open order.
“The coal-fired J.H. Campbell plant has reached the end of its life. Michigan cannot afford to let political interference prolong its operation,” Justin Carpenter, policy director for the Michigan Energy Innovation Business Council, said in a Thursday statement. “So-called temporary extensions only keep an unnecessary, inefficient plant alive, extending its pollution and high costs.”
Later in May, the DOE also used its Section 202(c) authority to order the Eddystone oil- and gas-burning plant in Pennsylvania to stay open through the summer. It was set to close this year too, and, as with the J.H. Campbell plant, utility regulators and regional grid operators had determined that shutting it down would not threaten grid reliability. The DOE’s 90-day order for the Eddystone plant is set to expire in late August.
Lawmakers, advocates, and industry experts are increasingly concerned that the Trump administration intends to apply its Section 202(c) authority more broadly. In particular, critics fear a DOE report issued in July will be used to justify future orders — even though its methodology is severely flawed.
The document was written to comply with an April executive order from Trump that tasks the agency with taking unilateral authority over power-plant closures, circumventing decades-old structures that utilities, state and federal regulators, and regional grid operators follow to determine when power plants can close or when they must stay open.
Earlier this month, clean-energy trade groups and nine Democrat-led states filed rehearing requests with the DOE asking it to redo the July grid-reliability report. They argue the study uses cherry-picked data and flawed assumptions to declare that the U.S. faces a hundredfold increase in grid blackout risks absent federal intervention in power plant operations.
Running aging power plants is expensive for utility customers, both in terms of direct costs on energy bills and the indirect costs of crowding out new, cheaper renewables. Utilities and independent energy developers will build less solar, batteries, and wind power if those plants stay online.
The DOE’s moves come as electricity prices are rising at more than twice the rate of inflation across the country. Wright and Trump have falsely claimed that renewable energy is to blame for that trend.
“By illegally extending this sham emergency order, Donald Trump and Chris Wright are costing hardworking Americans more money every single day for a coal plant that is unnecessary, deadly, and extremely expensive,” Laurie Williams, director of the Sierra Club’s Beyond Coal Campaign, said in a Thursday statement. “While Donald Trump and Chris Wright decry this made-up ‘energy emergency,’ they are simultaneously limiting our access to cheap, reliable, renewable energy.”
While China leads the world in both the production and adoption of clean energy tech like solar and EVs, the country has been slower to tackle decarbonizing heavy industry. That is starting to change.
In July, the Chinese state-owned steelmaker HBIS Group agreed to sell more than 10,000 metric tons of green steel to a buyer in Italy. The agreement set a deadline for delivery by the end of August. That same week, Australian Prime Minister Anthony Albanese visited China and pledged to work together to build out the green steel industry.
Meanwhile, in the U.S., steel producers are backing away from earlier commitments to produce green steel. Just before President Donald Trump’s inauguration in January, the Swedish steelmaker SSAB pulled out of negotiations for $500 million in federal funding to back a project to make iron with green hydrogen. In June, Cleveland-Cliffs abandoned its own green steel effort in Middletown, Ohio, after the Trump administration pressed the steelmaker to use a $500 million Biden-era grant to ramp up coal-fired iron production. Nippon Steel pledged to modernize U.S. Steel after securing Trump’s support for a $15 billion acquisition of its American rival in June, but the Japanese giant’s reputation as a “coal company that also makes steel” suggests the merger could extend the life of blast furnaces in Indiana and Pennsylvania.
“A lot of the rhetoric around competitiveness with China makes it seem like we think we must not fall behind. Stories like this make clear we already are behind,” said Marcela Mulholland, a former official at the Department of Energy’s Office of Clean Energy Demonstrations who now leads advocacy at the nonpartisan climate group Clean Tomorrow. “It is happening. The green steel example is just one of many.”
China produces a staggering amount of steel each year — more than 1 billion metric tons. About 90% is made with a two-stop process that relies on coal. First, iron is smelted from ore in a coal-fired blast furnace. Then the iron is transformed into steel in a basic oxygen furnace. About 10% of the country’s steel is made with an electric arc furnace, a process that – if powered by green electricity – is much cleaner, but depends on a steady supply of scrap metal as a feedstock. (The U.S. has a decided advantage with this particular technology since most of the steel that the nation produces uses scrap metal in EAFs.)
China has yet to widely implement the technology known as direct reduction of iron, or DRI, which typically relies on natural gas to produce iron but which can also use hydrogen. The country’s supplies of the former fuel are limited, spurring it to experiment with ways to conduct DRI using the latter.
China has many small-scale pilot projects manufacturing steel with hydrogen, but most involve minimal volumes of the material. For example, the country’s No. 2 steelmaker, Angang Steel Co., is producing just 10,000 metric tons of iron from green-hydrogen-fueled DRI per year. HBIS is shipping that volume of steel to Italy this month alone. Only HBIS and another major producer, China Baowu Steel Group, are producing green steel with hydrogen in significant quantities, according to research published last month by the Helsinki-based nonprofit Centre for Research on Energy and Clean Air.
How clean the hydrogen is that China uses to make steel is a complicated question.
Hydrogen – the smallest molecule – is already widely used in industrial processes and offers a cleaner alternative to fossil fuels since it produces no carbon dioxide when burned. Yet the vast majority of the global supply of hydrogen is made through methods that use fossil fuels and generate planet-heating emissions. When made with electrolyzers powered by renewable energy, hydrogen produces almost no emissions at all, but production of this form – green hydrogen – is nascent and comes at a high premium. (DRI using green hydrogen paired with EAFs is the highest – but nearly nonexistent – standard for producing green steel.)
Headquartered in Hebei province, HBIS started experimenting with lower-carbon steel in part by using hydrogen captured from its coking plants, where coal is roasted at more than 1,110 degrees Fahrenheit to cook off contaminants and produce an industrial-grade fuel. Roughly 60% of the gas emitted during the process is hydrogen.
It’s unclear how much of the steel HBIS is shipping to Italy is made with iron that employs hydrogen produced from industrial waste processes rather than the green stuff made from electricity generated by nearby renewables. HBIS did not respond to a request for comment.
But David Fishman, a principal at the Shanghai-based energy consultancy The Lantau Group, said “there are quite a few” sources of hydrogen made with renewable power near HBIS’s facility in northern China. He noted that HBIS has a strategic partnership with the China National Petroleum Corp., which launched its first large-scale demonstration project to make green hydrogen in 2023.
The export deal may be a sign of China raising its ambitions for cleaner steel. The national government had set a target for 15% of steel coming from EAFs by the end of this year. But that steelmaking capacity has remained at 10% for more than a decade.
Part of the problem is that provincial steel targets are at odds with the policies set in Beijing. Though the national government opened China to imported scrap steel that could be used in EAFs, imports halved in 2024 compared to the previous year, according to the Centre for Research on Energy and Clean Air analysis. Ten provinces, meanwhile, ramped up production of coal-made steel in the first half of this year, bringing down prices and disincentivizing more costly green investments, said Xinyi Shen, the China team lead for the Finnish nonprofit, who authored the report.
But if China can deepen its stockpiles of scrap steel, the country could more quickly build out a lower-carbon steel industry using EAFs while it waits to improve technology on green hydrogen that can bring down costs of fully decarbonized steel, Shen said.
“This is a more promising way to produce low-carbon steel,” she said. “For hydrogen steelmaking, it depends on the progress of green power.”
The bottleneck, she said, is “always the feedstock for DRI.”
But two recent policy changes on renewable power could incentivize Chinese companies to use more of the nation’s vast solar and wind resources to generate green hydrogen.
The first, called the 430 policy, took effect on May 1 and requires that new distributed solar arrays — like those on buildings’ rooftops — first power the facility they are sited on before selling any surplus electricity onto the grid. The second, dubbed the 531 policy, eliminates the guaranteed “feed-in tariffs” that renewables projects long benefited from in China, and requires new solar and wind farms to sell electricity on the spot market.
Whether policies that direct renewable power away from the grid benefit hydrogen producers by making that power more available to them depends on the provincial-level strategies for the fuel, which vary, Shen said. But the emergence of overseas buyers willing to pay more for steel made with green hydrogen could drive the market, she said.
Starting next year, the European Union, of which Italy is a founding member, is set to fully implement its Carbon Border Adjustment Mechanism. The carbon tariff essentially levies an extra cost on imports made with more planet-heating pollution. That means China’s coal-fired steel is about to become less competitive. While China could ramp up scrap-based EAF steel, Shen said the quality of that product tends to be very low, making it unappealing for export. The Italy deal, according to the Boston Consulting Group, shows the levies are creating a market for truly green material.
“This development holds significant implications,” Nicole Voigt, the Boston Consulting Group’s global lead of metals, told Canary Media. “China’s commitment clearly highlights its intent to seize commercial opportunities in the green steel market, especially in Europe.”
It’ll take time for the cost to come down. But China “overall has a long-term direction for carbon neutrality,” Shen said. “This gives companies and investors confidence and certainty to invest into newer technologies.”
Under the previous administration, the U.S. pumped billions of dollars into green hydrogen and clean industrial projects, and made tax credits for renewables available into the 2030s. Even then, America hardly employed all the policy mechanisms at play in China. The federal clean-industry program where Mulholland worked supported a few dozen projects, almost all of which saw their funding yanked away by the Trump administration this spring. Last year alone, China had nearly twice the number of low-carbon industrial demonstration projects. This year, Beijing funded a second set of more than 100 new projects.
“The investment into these new technologies will need a long, stable policy environment,” Shen said. “Long-term, the political goal is there here in China.”
A correction was made on Aug. 18, 2025: A previous version of this story incorrectly stated that basic oxygen furnaces directly burn coal.
Massachusetts has taken another significant step toward its goal of a fossil-fuel-free future.
Last week, state regulators issued an order changing who pays when a new customer wants to connect to the gas system, shifting the burden from gas utility consumers as a whole to the household or organization that requests the hookup. Utilities have 30 days from the date of the order to file plans that reflect the new payment guidelines for consideration by regulators.
It may seem like a small change, but it’s actually a pretty big deal, advocates said.
“It means the expansion of the gas system will be much slower than it otherwise would’ve been,” said Mark Dyen, a climate activist working with advocacy groups Gas Transition Allies and 350 Mass. “It says, ‘If you want to add to that for your own benefit, you can pay for it.’”
Massachusetts has for years been at the forefront of efforts to transition away from natural gas. In December 2023, state utility regulators issued a sweeping order — the first of its kind in the country — that made clear the state’s goal is to move away from fossil-fuel use as it aims to reach net-zero carbon emissions by 2050. The 2023 order laid out a framework for how gas utilities will be expected to participate in this evolution.
Last week’s decision on who should pay for gas-line extensions is the latest effort to turn those principles into practice.
Under the old rules, a new customer that wants to hook up their building to gas generally does not have to pay out of pocket: The cost is spread out among all the utility’s customers over the course of several years on the assumption that the newcomer’s future fuel use will create enough revenue to cover the initial price, a practice known as “line-extension allowances.” In 2023, the average cost of such an installation was $9,000, for an annual total of more than $160 million statewide, according to an analysis filed in the case by research firm Groundwork Data.
“Existing customers are subsidizing these new customers,” said Kristin George Bagdanov, senior policy research manager for the nonprofit Building Decarbonization Coalition. “It’s a misalignment of who’s shouldering the costs.”
In their ruling last week, Massachusetts’ regulators agreed with this stance and also declared that the existing approach runs counter to the state’s climate goals by encouraging greater adoption of natural gas. Plus, they said, the current system increases the chance that customers will be left paying for unneeded infrastructure, as more homes and businesses leave the gas system for electricity.
Typically, utilities calculate a 10-year payback period for commercial connections and 20 years for residential. However, as more customers adopt energy-efficiency measures, switch to electric appliances, and even electrify completely, their gas usage — and therefore the revenue they generate for utilities — will drop, extending the payback period, argued Massachusetts Attorney General Andrea Campbell in an October filing to state utility regulators.
Currently, more than half of Massachusetts homes are heated with natural gas. However, between 2021 and 2024, about 90,000 households installed heat pumps using incentives from energy-efficiency program Mass Save; the true total, including installations that didn’t go through the incentive program, is likely higher. The state is aiming to get 500,000 households to adopt heat pumps between 2020 and 2030.
“It really doesn’t make sense for existing ratepayers to pay for people to join when we are actively transitioning people off the system,” said Sarah Krame, a senior attorney for the Sierra Club’s Environmental Law Program. “The economics of that don’t make sense anymore. We’re no longer in that world.”
Massachusetts joins a handful of other states addressing the issue of line-extension allowances. Over the past three years, these subsidies have been reduced or eliminated in six states, and another six and Washington, D.C., are now considering reforms, according to the Building Decarbonization Coalition. In 2022, California became the first to do away with the practice. In June of this year, Maryland utility regulators ended the allowances, and New York state legislators passed a bill that will do the same if it becomes law.
“This is definitely a trend we’re tracking,” George Bagdanov said. “It’s part of the larger movement to reevaluate business-as-usual gas system operations.”
A clarification was made on Aug. 14, 2025: This article has been updated to reflect that there will still be a round of comments taken on the new plans utilities must file.
As the Trump administration aims to bolster fossil fuels at the expense of clean energy expansion, new research shows the oil and gas sector has so far failed to become a major jobs creator for heavily fracked areas of northern Appalachia.
“To the degree that we allocate resources to help develop that industry, we’re diverting those resources from other industries that actually could deliver” more jobs and higher per-capita incomes, said Sean O’Leary, author of the recent report from the Ohio River Valley Institute.
The report uses the term “Frackalachia” to describe 30 top oil- and gas-producing counties in Ohio, Pennsylvania, and West Virginia. As a group, the counties have smaller populations and a net loss in the number of jobs compared to 2008, just before Appalachia’s shale-gas boom began.
The counties’ growth in per-capita income also has lagged behind the national average, even as their nominal gross domestic product nearly doubled, increasing their share of the country’s GDP by 6%. Basically, comparatively high economic output from the counties did not produce higher-than-average incomes for their residents.
“Despite immense economic growth as measured by GDP, Frackalachia is in a position of actually having lost jobs since the beginning of the natural-gas boom,” O’Leary said. In his view, the numbers contradict pro-industry pitches for more oil and gas development.
“Whatever else it is, the natural-gas boom is not an engine for economic prosperity,” O’Leary said. He thinks the gas industry is “structurally incapable” of delivering lasting growth in jobs and income for the people living in heavily fracked areas. The Frackalachia counties have also seen relatively few jobs from “downstream” industries, such as the production of plastics, he added.
Oil and gas development is “highly capital-intensive, but not very labor-intensive,” O’Leary explained. Most earnings go to shareholders, investors, and suppliers based far from where fossil fuels are extracted, so only a small share of project income stays in the community to stimulate more economic activity.
Completed wells don’t need many permanent employees, O’Leary said. And many people who work in drilling and fracking come from outside the local area.
Canary Media’s review of data from the Ohio Department of Job and Family Services is consistent with that observation. From 2012 through 2022, the agency issued annual reports about the economic impact of the state’s oil and gas industry, including data for both “core” jobs and “ancillary” industries, which support oil and gas development.
More than half of the new hires for the core industry jobs in 2021 came from outside Ohio, according to the state data. Even in ancillary industries, nearly four-tenths of new hires were from other states.
Meanwhile, the state holds clean energy companies to higher standards when it comes to sourcing local labor. Solar developers who want to qualify for certain property tax relief must provide at least 70% of a project’s jobs to Ohio residents.
Canary Media drilled further into the figures from the Ohio Department of Job and Family Services to see how employment numbers compare to those touted by fossil-fuel industry organizations.
As of 2024, the core shale-industry sectors employed almost 9,100 people. The net gain compared to 2012 was about 860 jobs. Employment in those sectors peaked in 2017 at about 16,400.
Roughly 199,000 people worked in the industry’s ancillary sectors in 2024, for a net gain of about 30,000 jobs compared to 2012. However, the Department of Job and Family Services’ reports note that those ancillary sectors support other industries as well, such as engineering services, iron and steel mills, and construction of highways, streets, and bridges.
The Ohio agency numbers fall short of the 204,000 new jobs that an industry-funded report forecast oil and gas businesses might create or support. That analysis was published in 2011, in the lead-up to the 2012 law that set up the state’s current regulatory scheme for drilling and fracking of horizontal wells.
The agency numbers are also far lower than the 79,000 direct and 375,000 total jobs the American Petroleum Institute cited in a 2021 report based on data from 2019.
A communications representative for the American Petroleum Institute declined to answer Canary Media’s questions about that report or the new research from the Ohio River Valley Institute.
A spokesperson for the Ohio Oil and Gas Association did not respond to a phone call and emails seeking comment for this story.
The cyclical boom-and-bust dynamics that often characterize oil and gas development also impact jobs, said Gilbert Michaud, an assistant professor of environmental policy at Loyola University Chicago. In contrast, utility-scale solar could be built out over time, to offer “opportunities for a more stable and consistent workforce,” he said.
An analysis prepared by Michaud and others in 2020 estimated that utility-scale solar development could provide tens of thousands of jobs over the course of a few decades if the state encouraged it. That study came out before Ohio lawmakers added extra hurdles for most utility-scale solar and wind projects in 2021.
Now federal policy has also shifted away from renewables and in favor of fossil fuels.
“While this might spur some jobs in oil and gas, it will also take jobs away from renewables, which can be built nearly anywhere, not just in places like eastern Ohio that have shale resources,” Michaud said. “It will threaten a big renewable energy pipeline that has developed over the past decade or two.”
Earlier this week, two low-carbon cement startups unveiled new partnerships with data-center developers and operators, which are looking at ways to curb the tech sector’s ballooning climate impact.
The separate announcements from Sublime Systems and Brimstone are a striking example of how businesses are pressing ahead with efforts to decarbonize essential polluting industries like cement making — even as the Trump administration guts federal programs meant to kick-start U.S. manufacturing of cleaner construction materials.
Both companies are developing novel ways of producing cement that don’t cook the planet in the process. Cement — the gluey powder mixed with sand, gravel, and water to form concrete — is responsible for roughly 8% of global carbon dioxide emissions. Nearly all cement is made today by heating carbon-rich limestone in fossil-fuel-burning kilns.
Sublime, an MIT spinout, said on Tuesday that it completed a “pilot pour” of its fossil-fuel-free cement at a data center campus in northern Virginia owned by Stack Infrastructure. Sublime’s approach involves electrically charging a bath of chemicals and calcium silicate rocks. In Virginia, the startup and its partners used the cement to make seven cubic yards of concrete mix, which was then spread over a high-traffic loading dock.
Demonstration projects like these are key to convincing the inherently cautious construction industry to embrace new approaches. “It gives us a proof point to then [do] larger-scale deployments in a few years,” Cory Waltrip, Sublime’s director of business development and strategy, told Canary Media.
Those future deployments could include facilities run by Microsoft. The tech giant recently signed a binding deal to purchase up to 622,500 metric tons of Sublime’s cement products — enough to build roughly 30 professional football stadiums — from the startup’s forthcoming manufacturing facilities. The agreement marks a massive step up for Sublime, which can currently make just 250 metric tons of cement per year at its pilot plant in Somerville, Massachusetts.
Brimstone, for its part, also announced on Tuesday that it signed a commercial agreement with Amazon. The deal allows Amazon, valued at $2 trillion, to reserve future supplies of Brimstone’s low-carbon cement, though the partners declined to provide more specific details.
Oakland, California–based Brimstone sources carbon-free rocks instead of limestone, then pulverizes those rocks and adds chemical agents to leach out valuable minerals. Certain compounds are heated in a rotary kiln to make industry-standard cement. What remains can be used as supplementary cementitious materials — which help bulk up cement mixes — or to make a key component of aluminum.
Cody Finke, Brimstone’s co-founder and CEO, said Amazon began testing Brimstone’s products about a year ago and found they worked just as well as the conventional materials used in Amazon’s buildings. Amazon will get its supply from Brimstone’s $378 million commercial demonstration plant, which is slated to be operating by the end of the decade, Finke said.
The announcements send an important signal that private-sector demand isn’t waning for cleaner construction products — despite the White House abandoning strategies and rescinding funding for using greener cement, steel, glass, and other materials in public buildings, roads, and bridges.
Melissa Hulting, director for industrial decarbonization at the Center for Climate and Energy Solutions, said she was “really excited” about the latest news from Sublime and Brimstone.
“In the absence of federal demand … it’s great to see that companies are stepping in and supporting procurement” of low-carbon cement, she said. “I’m hoping that we’ll see more companies, especially with the building up of these data centers, come in and fill that void.”
Still, green cement startups continue to face a sizable challenge in scaling up their pioneering manufacturing plants. The task is likely to be even harder now that the Department of Energy has clawed back crucial funding for industrial decarbonization initiatives.
In late May, the DOE said it was canceling over $3.7 billion in awards for two dozen projects aimed at decarbonizing everything from cement kilns and glassmaking furnaces to mac-and-cheese factories and whiskey distilleries. Sublime was slated to get up to $87 million to build its commercial-scale cement facility in Holyoke, Massachusetts. Brimstone had been awarded up to $189 million to finance the construction of its commercial plant, the site for which is still being decided.
Both Sublime and Brimstone said they’re in ongoing conversations with the DOE to try to appeal the decision. In the meantime, however, the startups are moving forward as planned with their manufacturing facilities.
Finke said Brimstone’s award cancellation felt like an “oversight, because critical materials are such an important topic for the Trump administration.” But he said that losing the federal funding doesn’t affect the company’s long-term strategy, which is focused on raising private capital. To date, the six-year-old startup has raised over $80 million from investors.
Sublime, meanwhile, has raised over $200 million since its founding in 2020, a figure that includes the DOE award. Leah Ellis, Sublime’s co-founder and CEO, said the startup remains on track to begin delivering cement to Microsoft and other customers from its Holyoke facility in 2028.
“We do think what we’re doing is aligned with the current administration’s priorities of creating jobs and investing in modernizing and onshoring manufacturing of important materials,” she said.
“Everything inside Sublime is going as well as we could hope,” Ellis added. “Nobody thought that scaling up a new cement technology would be easy, right? But that’s what we’re here for.”
New York just took a big leap toward zero-emissions buildings.
On July 25, the State Fire Prevention and Building Code Council approved an all-electric building standard, making New York the first state in the nation to prohibit gas and other fossil fuels in most new buildings. Legislators and climate advocates celebrated the move, which had been mandated under the pathbreaking 2023 All-Electric Buildings Act.
“I’m excited that we are finally tackling, statewide, our largest source of fossil-fuel emissions,” said state Assemblymember Emily Gallagher, who sponsored the 2023 legislation. Buildings account for 31% of the Empire State’s planet-warming pollution.
New York is forging ahead on building decarbonization at the same time the federal government is backtracking, yanking support for renewable power and home energy efficiency and providing the fossil-fuel industry with new subsidies.
The state’s rules will apply to new structures up to seven stories tall and, for commercial and industrial buildings, up to 100,000 square feet beginning Dec. 31, 2025. Buildings bigger than that will need to be built all-electric starting in 2029. The new code will spur installations of heat pumps and heat-pump water heaters — ultra-efficient electric appliances that are good for the planet and, typically, pocketbooks.
The council left room for exceptions, though, including new laboratories, crematoriums, restaurants, and large buildings whose owners can prove the grid isn’t ready to accommodate their sizable all-electric heating needs. Michael Hernandez, a policy director at electrification advocacy nonprofit Rewiring America, said he doesn’t think the exemptions will eat away at the code’s efficacy, however.
With the rules finalized, “I’m relieved,” Gallagher told Canary Media. Fossil-fuel interests — such as the utility front group, New Yorkers for Affordable Energy — “really worked overtime to try to stop this,” she said.
The new regulations come on the heels of a recent legal victory: On July 23, a federal district court in New York upheld the state’s ability to implement the All-Electric Buildings Act.
The groups challenging the law in court — including the New York State Builders Association, National Association of Home Builders, National Propane Gas Association, and a few local union chapters for plumbers and electricians — alleged that it’s preempted by the federal Energy Policy and Conservation Act, the same justification used to overturn Berkeley, California’s pioneering ban on gas hookups in new construction. The New York judge was unconvinced by this argument, noting that the Berkeley decision relied on “deficient interpretations” of terms like “energy use,” and is “simply not persuasive.”
Opponents of the standard haven’t quit, though. An industry coalition that includes many of the organizations that brought the lawsuit sent a letter on June 26 to U.S. Attorney General Pam Bondi requesting that the Department of Justice move to block the code from taking effect. Michael Fazio, lead author of the letter and the executive director of the New York State Builders Association, declined to comment on the request’s status to Canary Media.
The state’s new energy code is expected to raise the cost of residential construction but also lower energy bills substantially for homeowners and renters, making it cost-effective overall with a payback of 10 years or less, according to a report commissioned by the New York State Energy Research and Development Authority. Over 30 years, households are expected to save an average of about $5,000 due to a 17% reduction in energy use.
Other research indicates all-electric construction is typically less expensive than that for buildings equipped to burn gas or fuel oil. Electric-only projects allow developers to forgo installing costly fossil-fuel infrastructure alongside the electrical systems requisite in modern buildings. A 2022 analysis by the decarbonization nonprofit New Buildings Institute, for example, found that building an all-electric single-family home in New York costs about $8,000 less.
The all-electric code will improve air quality by reducing reliance on fossil-fuel-fired boilers, furnaces, water heaters, and stoves. These conventional appliances spew harmful byproducts such as carbon monoxide, particulate matter, benzene, nitrogen oxides, and more, which can cause respiratory and cardiovascular issues — to lethal effect. In 2017, fossil-fuel use from New York buildings caused $21.7 billion in health impacts and nearly 2,000 premature deaths, more than in any other state.
Gas stoves, typically the largest sources of exposure to indoor air pollutants, are linked to nearly one in five asthma cases in children in New York, according to a 2022 study. “Places like the Bronx have the highest rates of childhood asthma in the country,” said Jumaane Williams, public advocate of New York City, in a call with reporters on Friday. “We know this is a life-and-death situation.”
“Numerous studies … show that both air pollution and climate change disproportionately impact low-income communities and communities of color,” said Lonnie Portis, director of policy and legislative affairs at the community-based nonprofit WE ACT for Environmental Justice. The state’s all-electric building standard “is a significant step forward for environmental and climate justice.”
The new rules will not only get heat pumps into new construction but help boost adoption in existing homes, according to Jay Best, CEO of home energy-efficiency company Green Team Long Island.
“We’re always telling people about heat pumps … solutions that are going to save them money and make their homes more comfortable,” Best told Canary Media. “But people are apprehensive because it’s something they’re not used to,” despite heat pump units outselling gas furnaces nationally.
“The code … sets a bar; this is the minimum that the state says is legal to build,” Best said. That “changes people’s view of the technology.”
Alex Beauchamp, Northeast region director at Food & Water Watch, underscored that passing the All-Electric Buildings Act and getting it into the state code was a victory of David-and-Goliath proportions, with “fossil-fuel companies, plus the gas utilities, plus big real estate” rallied in opposition, he said.
“When New Yorkers come together … we can win even in the face of opponents with an almost-limitless budget,” he said. “That is how we won this bill. It’s also how we are going to continue the fight to get fossil fuels out of all the existing buildings in the state.”
The Trump administration just dealt another blow to U.S. environmental regulations — one that could allow more contamination of drinking water from toxic coal ash contamination.
The Environmental Protection Agency proposed on July 17 to extend deadlines for required reporting and groundwater monitoring at coal ash landfills and dumps.
Any delay of these rules would be harmful in its own right, experts say, and they fear the announcement is just the beginning of further efforts to undercut coal ash regulations. During his first term, President Donald Trump largely ignored federal coal ash rules that took effect in 2015. This time around, his administration is widely expected to roll them back.
Advocates suspect that updates made last year to include so-called legacy coal ash, which wasn’t covered by the original rules, and coal ash landfills are especially vulnerable. That’s why alarm bells have been ringing for advocates following the EPA’s latest move to delay enforcement of one key aspect of the updated rules: the regulation of dry coal ash dumps and landfills, known as coal combustion residual management units, or CCRMUs.
The EPA’s July 17 announcement included a direct final rule and a companion proposal that would extend deadlines for these CCRMUs.
The EPA said it wants to extend the deadline by one to two years for the “facility evaluation reports,” which companies have to file if they own coal ash that meets the definition of a CCRMU, and therefore makes the sites newly subject to regulation. The EPA also proposes extending the deadline to start groundwater monitoring at these sites for an additional 15 months, from May 2028 to August 2029. The direct final rule issued by EPA would extend the deadline for the facility report to February 2027.
As it stands, utilities and other owners of coal ash sites are required to report by February 2026 whether they have any coal ash in landfills, berms, dumps, or other dry repositories that would be considered CCRMUs newly subject to regulation under the updated rules.
“We assume what EPA did was give themselves time to make significant changes to the legacy coal ash rule,” said Lisa Evans, senior counsel at Earthjustice. “The amount of time given to utilities to comply with the CCRMU portion of the rules [was] extremely generous. The utilities were given years, and now they’re coming back for more, thinking this EPA will grant them more time.”
The initial coal ash rules took effect in 2015 and were heralded as a major step toward cleaning up the toxic coal ash located at more than 700 sites at over 300 power plants nationwide. But those rules did not cover coal ash that was used to fill in earth or build up berms, or was simply scattered about; nor did they cover ash at coal plants closed before the rules took effect.
The environmental law organization Earthjustice filed a lawsuit on behalf of environmental groups seeking to expand the 2015 rule’s coverage, and after a federal court decision in 2018, the updated rules were eventually adopted in May 2024. These updated rules cover CCRMUs as well as “legacy ponds” — coal ash stored in water at coal plants closed before 2015.
Under federal administrative procedures, the EPA’s new direct final rule will take effect six months after being published in the Federal Register if no “adverse comments” are filed by the public. Groups including Earthjustice are almost certain to lodge adverse comments, in which case the rule would not take effect, and instead the companion proposal — to extend the facilities report deadline to February 2028 — would undergo a public comment process.
This poses a bit of a conundrum for environmental groups: If they challenge the rule, they may end up with an even longer delay.
“If you get a year or two years, you get another two years to put in groundwater monitoring. Then that delays the determination of contamination, which then delays development of a cleanup plan and final remedy,” said Evans. “You’re pushing everything into the future.”
An EPA press release says, “These actions advance [EPA] Administrator [Lee] Zeldin’s Powering the Great American Comeback Initiative,” which includes energy dominance, among other pillars.
Evans said the EPA’s announcement came immediately after a July 17 meeting that she and other advocates had with EPA officials, along with residents who live near some of the country’s hundreds of legacy coal ash impoundments. She said the officials listened to their concerns but made no mention of the delays that were about to be unveiled.
“We were all stunned,” she said. “Years do make a difference when you’re thinking about the movement of contaminated groundwater. This will allow more contaminants to get into groundwater, it will make it hard, possibly impossible, to remediate. We know these sites; we know how contaminated these sites are; we know contamination is moving in the groundwater.”
Almost a century ago, on the shores of Lake Michigan in northwest Indiana, the utility NIPSCO mixed coal ash from its Michigan City coal plant with sand and sod to help fill in the space behind steel retaining walls. On the other side of those now-corroding steel walls is the lake, which provides drinking water for the region and is a hub of both human recreation and aquatic life.
Environmental leaders have serious concerns that waves will pound away at the decaying wall, further weakening it, to the point that tons of toxic coal ash will spew into the lake. Coal ash contains heavy metals and other contaminants known to cause cancer and other serious health problems, as the EPA notes.
The Michigan City coal plant is among more than 300 sites covered by the updated rules, according to Earthjustice’s analysis, meaning NIPSCO should be required to file a CCRMU facilities report by February 2026 and then groundwater monitoring results and cleanup plans. Any delay in the reporting deadlines means a delay in the site being remediated — and extends the risk of coal ash contaminating the lake and possibly the groundwater too, environmental leaders say.
“Having the delay in some of those requirements is pretty devastating to hear,” said Ben Inskeep, program director of the Citizens Action Coalition, an Indiana consumer protection group. “These are coal ash waste dumps that have been there for decades. For all this time, they are just leaching really nasty things into our water supplies, putting us in grave danger of a catastrophic failure of the coal ash, all that coal ash getting into our waterways or drinking water supplies.”
NIPSCO is in the process of repairing one of the steel seawalls adjacent to a creek that empties into Lake Michigan by the Michigan City plant, but local leaders say that is less a solution and more a sign of the risks.
“The utilities have had a long time to figure out what kind of coal ash they have on their properties, what damage has been done, what remedies are possible,” Inskeep said. “Further delay is certainly harmful to communities who have been forced to endure living next to these toxic sites for so long.”
Owners of legacy coal ash ponds were required in November 2024 to file inspection documents for their sites. Those documents show serious groundwater, lake, and river contamination concerns from sites in Alabama, Georgia, Illinois, Indiana, and West Virginia, among other states, according to Earthjustice’s analysis.
The Widows Creek plant on the Tennessee River in Alabama may be the “dirtiest” site subject to the updated rules, according to Earthjustice. The plant was retired shortly before the 2015 rules took effect, meaning that it was not regulated until the update last year. Also unregulated until the 2024 update was the Morrow Lake plant in Michigan, whose location puts coal ash in direct contact with a recreational lake, according to its recently filed inspection reports.
Also troubling, advocates say, is that multiple companies known to have legacy ponds on-site did not file any reports by the November deadline or within an allowed six-month extension period. An EPA website compiling reports includes 46 sites filed under the legacy rule, out of at least 84 sites known to have legacy ash, according to Earthjustice’s analysis.
“It’s unfortunately not surprising, considering the industry’s general noncompliance,” said Mychal Ozaeta, Earthjustice’s clean energy program senior attorney. “It’s nothing new. We’re going to continue to monitor it, utilize our internal resources, work closely with our partners to track it just so the public is aware of various sites across the country failing to make publicly available this critical information and comply with requirements.”
The EPA press release about the deadline extensions also refers back to “March 12, 2025, the greatest and most consequential day of deregulation in the history of the U.S., [when] EPA committed to taking swift action on coal ash, including state permit program reviews and updates to the coal ash regulations.”
It’s a reference to another move the EPA is making to further undercut federal coal ash rules: Giving states, including those with lax records on the environment, the power to enforce their own coal ash rules.
On July 10, the EPA had issued another announcement that could weaken the legacy coal ash rules. It essentially said an earlier memo from the EPA — aimed at defining “free liquids” causing contamination concerns in coal ash repositories — should be ignored.
“It’s pretty nefarious,” said Evans. “This is all just the start of the Trump administration’s attempted unraveling of coal ash protections.”
State legislators pushing to unravel North Carolina’s climate law say their bill will give utility Duke Energy more leeway to build new gas and nuclear power plants and save its Tar Heel customers billions of dollars.
But Gov. Josh Stein disagrees: He vetoed Senate Bill 266 on Wednesday, prompted by data showing that the legislation would cost households and slow the state’s energy buildout. The GOP-sponsored measure would repeal a requirement that Duke slash carbon pollution 70% by 2030 compared to 2005 levels, while leaving a 2050 carbon-neutrality deadline intact.
“This summer’s record heat and soaring utility bills has shown that we need to focus on lowering electricity costs for working families — not raising them,” Stein, a Democrat, said in a statement. “My job is to do everything in my power to lower costs and grow the economy. This bill fails that test.”
In issuing his veto, Stein pointed to a new study from researchers at North Carolina State University, which builds on projections from the state customer advocate, Public Staff. That modeling showed SB 266 could cause Duke to build less generation capacity over the next decade, just as electricity needs are expected to surge.
That means Duke would have to lean harder on aging plants and burn almost 40% more natural gas between 2030 and 2050, experts at N.C. State University say. Under a worst-case but plausible scenario for gas prices, customers could pay $23 billion more on their electric bills by midcentury as a result.
“As our state continues to grow, we need to diversify our energy portfolio so that we are not overly reliant on natural gas and its volatile fuel markets,” Stein said.
A complex measure that’s faced little public debate, SB 266 easily cleared both chambers of the Republican-controlled General Assembly in June with a handful of Democratic votes. With Stein’s action, advocates now turn their focus back to state lawmakers, who are on break for at least another week. The GOP has the three-fifths majority needed to override the veto in the Senate, but is one member shy of that margin in the House.
“Governor Stein is championing working families all across North Carolina who would be harmed by this new law,” said Will Scott, Southeast climate and clean energy director for the Environmental Defense Fund. “Legislators should reconsider the harmful consequences of this law for the working families in their districts.”
The N.C. State study underscores a surprising finding from Public Staff’s modeling: SB 266 does little to prepare North Carolina for ballooning electricity needs expected from an influx of data centers, manufacturers, and new residents. In fact, removing the 2030 goal would prompt Duke to build 11,700 fewer megawatts of new power plants in the next decade than its current plans.
“In talking with legislators, I found that almost all of them emphasized economic growth and the need for power generation to meet that demand,” said Scott. “But Public Staff’s analysis found that the most likely short-term impact of SB 266 is to build less new generation and storage and instead to lean harder on aging coal and gas facilities.”
The Public Staff forecast shows renewable energy would be the main short-term casualty of SB 266, just as its backers intend. By 2035, Duke would construct 7,200 fewer megawatts of solar and battery storage, and no offshore or onshore wind farms whatsoever — a 4,500-megawatt decrease compared with the status quo.
But new “always-on” nuclear and gas resources — the same ones SB 266 champions seek to promote — would also suffer. Without a near-term carbon reduction deadline, Public Staff says Duke would develop just 300 megawatts of nuclear power in the next decade, half as much as it currently plans. The utility would build 1,400 fewer megawatts of large, efficient combined-cycle gas units.
Only gas “peaker plants” — simple-cycle combustion turbines that are relatively cheap to build but expensive to operate — would become more abundant, Public Staff forecasts. Duke would build 3,800 megawatts’ worth instead of 2,100.
The model’s underlying assumptions haven’t been made public. But experts say the reason for this short-term impact is likely that without a carbon constraint, it’s simply cheaper to run existing coal and gas plants more often than it is to build new ones.
The same Public Staff study predicts that removing the 2030 target would yield $13 billion in present value in customer savings by 2050 — a figure much vaunted by SB 266 supporters.
But detractors have long pointed out that the discount comes from avoided construction costs only and doesn’t account for the price of fuel, 100% of which is passed to utility customers through a “rider” on monthly bills.
As it happens, the $23 billion in added fuel costs estimated by N.C. State translates to $13 billion in present value.
“That is a pure coincidence,” said Jeremiah Johnson, one of the researchers. “It completely negates the claimed savings.”
Duke might also have to buy more power from utilities in neighboring states to meet electricity needs, another blow to residential consumers, who under SB 266 would pay a higher fraction of those costs than they do today.
“This bill not only makes everyone’s utility bills more expensive,” Stein said, “but it also shifts the cost of electricity from large industrial users onto the backs of regular people — families will pay more so that industry pays less.”
Advocates also point to the simple public health rationale for keeping the state’s 2030 pollution-reduction goal intact. Relying on existing coal and gas plants instead of building more solar means millions of tons more climate pollution released into the atmosphere every year, plus pollutants that lead to smog and soot.
Then, there’s the commonsense argument, said Matt Abele, executive director of the North Carolina Sustainable Energy Association: “You don’t establish a 30-year goal without milestones along the way.” Achieving emissions reductions is like saving enough money for retirement — it takes planning and can’t be done in just a couple of years. “These things do not happen overnight,” he said.
Abele’s group analyzed the 24 states, plus D.C. and Puerto Rico, with zero-carbon targets around the middle of the century. Just one, Nebraska, lacks any sort of interim goal.
The reason, according to state Rep. Maria Cervania, a Democrat from Wake County who voted against SB 266? “Deadlines matter.”
At a news conference last week, she said that the 2030 goal has given “us a clear, science-based target to hold the utilities accountable. … Without it, progress slows and polluters face no urgency to act.”
An update was made on July 2, 2025: This story has been updated to reflect that Gov. Stein vetoed SB 266 after this story was published.
Global demand for steel is rising, and with it, emissions from the coal-fired blast furnaces that churn out around 70% of the world’s supply. American steelmakers are less reliant on blast furnaces than other countries, but they are doubling down on plans to extend the lives of the handful still operating in the U.S.
As those same steelmakers plan new facilities, though, they are embracing a cleaner technology called direct reduced iron, or DRI, to purify iron ore, the first step in the production of primary steel.
The DRI process uses a high-temperature gas to remove oxygen from the ore. The remaining iron can then be added to a traditional basic oxygen furnace or, more commonly in modern systems equipped with DRI, to an electric arc furnace that can be powered by carbon-free electricity.
Most DRI plants operating today use natural gas, a fossil fuel primarily made up of planet-warming methane. But even those can produce 50% less carbon emissions than coal-fired blast furnaces — and if the technology can be paired with carbon capture or fueled instead by green hydrogen, carbon-free steel becomes a possibility.
While DRI facilities account for just 9% of global ironmaking capacity today, they comprise nearly 40% of what’s under development. The U.S., for its part, has only three DRI plants up and running — but every new ironmaking facility slated to be built in the country will use DRI. That includes South Korean automaker Hyundai’s planned DRI plant in Louisiana, which the company announced in March.
The technology for DRI has existed for more than half a century, but it’s made exclusively by two firms that few outside the industry have ever heard of: Midrex Technologies and Tenova. Now, as some countries seek to build steel plants that don’t burn coal, these two firms are poised to reap the benefits.
Midrex Technologies dominates the DRI market. The North Carolina-based company built the first U.S. plant using the technology in Portland, Oregon, in 1969.
“DRI has a bigger and bigger role to play in the energy transition. The long-term view for DRI is positive. Demand for DRI keeps increasing,” said Vincent Chevrier, Midrex’s general manager of technical sales and marketing. “It’s probably going to double, then triple, in the next 20 years.”
The other major manufacturer, Tenova — owned by the Buenos Aires-based Techint, with technology jointly developed with Italy’s steel giant Danieli — started making DRI technology at the turn of this century. With just a fraction of the market, the firm may be the underdog, but CEO Francesco Memoli sees an advantage.
Tenova’s technology can swap out natural gas for hydrogen without any modifications. While Midrex says its equipment needs only minor upgrades to optimize for hydrogen, Tenova said the innate flexibility of its system allows it to ride out whichever way the political tides turn in the U.S.
Lately those tides have been turning against green steel.
In January, just before President Donald Trump’s inauguration, the Swedish steelmaker SSAB bowed out of negotiations for $500 million in federal funding the Biden administration had put up to support a DRI plant powered entirely with green hydrogen in Mississippi.
Cleveland-Cliffs — considered the more progressive of the American steelmakers — has suggested it would abandon its plans to build a DRI facility and use hydrogen to produce steel at its Middletown, Ohio, plant as it renegotiates the $500 million grant it had been awarded with the Trump administration.
Weeks after Cleveland-Cliffs started backing away from the project, Nippon Steel secured Trump’s approval to take over American rival U.S. Steel. The Japanese behemoth, the world’s fourth-largest steel producer, lags so far behind other companies in developing a decarbonization plan that the watchdog group SteelWatch recently described Nippon as “a coal company that also makes steel.” While Nippon has pledged to build a new electric arc furnace, a machine that uses electricity to turn scrap metal into fresh steel, the company has also staked out plans to extend the operations of U.S. Steel’s existing blast furnaces.
Meanwhile, Republicans in Congress have proposed eliminating the federal tax credit meant to spur green hydrogen production, which would create yet another setback.
In the near term, most of the new DRI plants in the U.S. will likely run on gas, Memoli said.
“Natural gas is very accessible in the U.S.,” he said.
Already, Tenova can capture some of the emissions from the gas it uses. Steelmaker Nucor deploys Tenova equipment at its plant in Louisiana, which last year set a world record for DRI production. In 2023, Nucor inked a deal with Exxon Mobil Corp. to capture and store the carbon from the steelmaker’s DRI process.
In Mexico, the Latin American steelmaker Ternium funnels CO2 captured from Tenova’s DRI equipment to Coca-Cola, Memoli said. Tenova puts the gas through two rounds of cleaning until it’s safe for use in beverages, and sells it to another company that in turn supplies the CO2 to Coca-Cola.
“All of the soda produced in Mexico by Coca-Cola is using CO2 recycled from an ironmaking plant,” Memoli said. “The joke is that Mexican Coke tastes better because of that.”
While the CO2 emitted by the DRI process is captured in the Tenova system, Memoli said the carbon produced from heating the gas to 1,000 degrees Celsius remains a source of pollution. The company is planning to roll out new features in the next few years to capture even that “residual” CO2.
Elsewhere, the company’s equipment is already running on hydrogen, or will be soon.
Last year, a major Swedish green metal project selected Tenova’s technology to generate iron with 100% hydrogen for the steelmaking giant SSAB. The fuel is gaining ground in China, too, which lacks domestic gas resources. Tenova-equipped plants in the world’s second-largest economy are already churning out 700,000 tons of iron per year using anywhere from 30% to 70% hydrogen, Memoli said, though only some of that hydrogen is green. The world produces about 2.5 billion tons of iron each year, for context.
Despite the headwinds for hydrogen-based steelmaking in the U.S., the industry could still move away from traditional steel plants (also called integrated plants because of their use of blast furnaces and basic oxygen furnaces) in the coming years. Industry analysts say DRI is the technology that will enable this shift — one that some say is critical both economically and for the climate.
“Blast furnace technology is outdated — full stop. It’s too dirty, it’s too energy intensive, and it’s too inefficient,” said Elizabeth Boatman, a lead consultant at 5 Lakes Energy, a Michigan-based research firm. “Overhauling our integrated mill fleet will be expensive, but it’s an investment that will pay off in the long term.”
Already, mini mills across the U.S. make use of the large volumes of scrap metal in the U.S. to produce lower-carbon steel than what coal-fired plants in China make fresh.
“What we are seeing, because of the switch of energy from coal, is that it offers the possibility of decoupling ironmaking from steelmaking,” said Midrex’s Chevrier. “You can place your ironmaking facility where the energy is cheap, and maintain your steelmaking facility at the location where your customers are and your scrap is.”
That could also create an opening for some of the startups looking to popularize next-generation ironmaking techniques. The Colorado-based company Electra, which aims to use a process called “electrowinning” to purify iron without a blast furnace, raised $186 million in April to support its scale-up. The Massachusetts Institute of Technology green steel spin-off Boston Metal, meanwhile, is inching toward its first commercial revenue.
Memoli said Tenova’s own research and development teams are working on similar technology. But he warned that it’s unlikely to be able to scale up fast enough in the near term to compete with DRI or blast furnaces.
A medium-sized blast furnace can churn out enough iron for 3 million tons of steel per year. A DRI plant can reach about 2.5 million tons. It’ll be decades before any of these newer electricity-based technologies reach that scale, Memoli said.
“The level of development of those technologies is still at a very early stage,” he said.
“We’re still talking about 20 years, 30 years from now. We need to be conscious of what are the targets and what are the deadlines today,” he added. “If we wait for something like that, the target of cleaning the planet will be pushed down and the cost of cleaning the planet will be much higher.”
Memoli said he wants to see more competition in the DRI space.
“Today there are only two companies – us and Midrex. Two is not enough,” Memoli said. “Not even four would be enough to develop all the projects that potentially could happen. Anybody with a green solution is welcome.”
A recent pact between North Dakota and the Trump administration shows how coal-friendly states could enshrine lax standards and block future federal enforcement on toxic coal ash pollution.
North Dakota earned preliminary approval from the U.S. Environmental Protection Agency last month to regulate coal ash — a byproduct of burning coal — at the state instead of federal level. Indiana environmentalists fear that their state will follow the same path.
The distinction may seem moot under President Donald Trump — whose administration did not enforce federal coal ash regulations during his first presidency — but if his EPA approves so-called primacy arrangements allowing states to run their own programs, it could lock in weaker enforcement even if a future administration wants to take a tougher stance on coal ash contamination.
“What primacy would do is cement a situation that, depending on the state, could be very detrimental,” said Lisa Evans, senior counsel for the law firm Earthjustice, calling the North Dakota decision “precedent-setting.”
Under 2015 federal rules, coal ash is not allowed to be stored in contact with groundwater, and contamination caused by the substance must be reported and remedied. A 2016 law allows states to adopt their own coal ash rules that are at least as protective as the federal standards, after which states can petition the EPA to gain primacy and take responsibility for issuing coal ash permits and enforcing regulations.
EPA Administrator Lee Zeldin has encouraged states to do this, citing the administration’s commitment to “clean beautiful coal.”
This raises concerns when a state’s government is known to be friendly to the coal industry and lenient on pollution. Indiana consumer and environmental leaders have long described their state this way, and indeed, Indiana lawmakers have proposed and passed multiple measures supporting coal, including two laws obligating the state to seek coal ash primacy.
“One reason” the possibility of primacy “is so bad in Indiana is the amount of coal they burn and the amount of coal ash that’s been mismanaged,” Evans said.
In a Jan. 15 letter to Zeldin, obtained by Canary Media, coal and energy companies asked the government to expedite state control over coal ash regulation.
West Virginia, Wyoming, and Alabama have also sought coal ash primacy, and all three are plaintiffs in a lawsuit challenging aspects of the federal coal ash rules, according to the Cowboy State Daily. In May 2024, the Biden administration denied Alabama’s request for primacy, and state officials said they would appeal.
North Dakota’s attorney general sent the EPA a notice of the state’s intent to sue over its coal ash primacy application, in January, shortly before Trump took office. The Trump administration proposed approving North Dakota’s primacy request last month.
Georgia was granted coal ash primacy in 2019, and it has issued permits allowing utility Georgia Power to permanently leave large amounts of coal ash in pits submerged partially in groundwater, a move that environmental groups say violates federal rules. Texas and Oklahoma also have primacy programs.
States can gain similar authority over the regulation of underground injection wells, and in February, the EPA approved West Virginia as the fourth state — along with Wyoming, North Dakota, and Louisiana — with such primacy.
In 2021 and again in 2023, Indiana lawmakers adopted legislation obligating the state to adopt its own coal ash rules and then seek primacy to enforce them. This upset environmental and health advocates, said attorney Indra Frank, since they feared that the state would not actually enforce coal ash standards after being freed from federal scrutiny.
“In Indiana, our industry would prefer to deal with [the Indiana Department of Environmental Management] rather than EPA,” added Frank, who serves as coal ash adviser for the Hoosier Environmental Council. “It’s a problem if the EPA approves a program like the one they just approved in North Dakota, where the state agency has a long history of ignoring noncompliance and actually issuing approvals for plans that are not compliant. Once the state has primacy, the EPA will be very hesitant to step in. And the courts will defer to the state’s primacy as well.”
In 2024, Indiana issued draft state coal ash rules akin to the federal rules and accepted public comment on them. But Frank suspects that Indiana regulators will wait to revise those standards once laxer federal rules are finalized. In March, Zeldin announced a review and planned overhauls of the coal ash rules, which were barely enforced until 2022, when the Biden administration began issuing decisions and mandates.
With revised federal rules on the books, Indiana could enshrine state rules that are similarly weakened.
And even if the federal rules are beefed up again in the future, the federal government would be hard-pressed to impose those rules on a state that gained primacy with weak rules, explained Evans and Frank.
“The trifecta would be that EPA weakens the current regulations, and the states adopt those weak regulations and issue permits based on those weak regulations,” said Evans. “Then I think we’re in a really terrible situation. Because if the regulations are again strengthened under a new administration, the states have three years to change their programs to be consistent, but who is going to enforce that deadline? I think it would be more than three years before corrections would be made to state programs, and in the meantime a lot of damage is being done.”
Indiana is home to more than 73 million cubic yards of coal ash stored on at least 16 sites, according to data compiled by Earthjustice in 2022 based on companies’ own reporting required under federal rules. That’s the equivalent of more than 22,000 Olympic swimming pools. And that number doesn’t even include ash not covered by the federal rules until a 2024 update.
All the coal ash ponds noted in the data are unlined, and most of them have contaminated groundwater with elements including arsenic, molybdenum, and lithium, according to the companies’ own reports.
Companies have proposed to close many of the ponds in place — without removing the coal ash from the unlined repositories. Ben Inskeep, program director for the consumer group Citizens Action Coalition, said he would expect state regulators to approve such plans.
“The track record in Indiana has been lax enforcement, not particularly focused on ensuring good environmental quality outcomes and more focused on doing the bidding of industry,” he said, noting that’s a reason to oppose primacy on coal ash.
“We certainly would be very concerned by that path forward, given we think the EPA is the right entity to implement those regulations and ensure enforcement,” Inskeep said. “The Trump administration is a four-year term, and managing coal ash is going to be decades into the future. This is a long-term issue that requires federal oversight for the duration; it’s absolutely critical the federal government keep that ability.”
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