Back
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the year implementing an ambitious if inadequate decarbonization law, and is now exiting 2025 with that law all but repealed?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.
In early December, Nippon Steel announced it would build a $4 billion steel plant as part of a larger plan to invest $11 billion in its new American subsidiary, U.S. Steel, over the next two years. The facility, the location of which likely won’t be determined until 2027, is expected to include two electric arc furnaces that turn scrap into new steel.
The news came on the heels of a November announcement about the company’s plans for a new “direct reduced iron” facility at the Big River Steel Works campus in Osceola, Arkansas. Taken together, the two announcements suggest the company is working on a strategy for producing cleaner steel in the United States, even as it doubles down on coal-fired incumbent technology.
In August, Nippon unveiled plans to revamp an aging coal-fueled facility at the Gary Works complex in Indiana, one of six U.S. Steel blast furnaces the Japanese giant plans to overhaul in order to, as the company put it last year before the deal was finalized, “extend their useful lives for many years to come.”
Those relined blast furnaces could last decades, locking in demand for coal and dimming hopes in neighboring communities — which have some of the nation’s worst air pollution — that cleaner steelmaking equipment could replace the coal-burning facilities.
However, the new DRI plant in Osceola, if merged with an electric arc furnace, could establish a greener alternative for an integrated steel plant and potentially vault U.S. Steel ahead in the race to supply American automakers and industrial buyers with greener metal.
With billions more dollars yet to be allocated, analysts are watching closely to see how the two strategies play out.
Nippon Steel is “at a crossroads,” said Matthew Groch, a senior director at the environmental group Mighty Earth who tracks the steel industry. “Which way do you want to go?”
U.S. Steel confirmed its plans for a DRI plant in Arkansas in an email to Canary Media, but Nippon did not respond to a request for comment on the broader investment strategy.
Blast furnaces transform iron ore into high-strength steel by combining the metal with purified coal, or “coke,” and limestone to produce liquid iron, which is then put into a separate furnace to become steel. The DRI process uses a high-temperature gas — usually natural gas, but increasingly hydrogen — to remove oxygen from the ore before it goes into an electric arc furnace to be turned into steel. If the electricity powering both the production of hydrogen and the EAF itself comes from zero-carbon sources, the steel is considered “green.”
Much of the steel production in the U.S. involves turning scrap metal into new steel in an EAF. But one-quarter of domestic steel production comes from seven integrated iron and steel facilities that all use coal-fired blast furnaces.
Under the Biden administration, there was a growing push for U.S. steel manufacturers to switch to more modern, less polluting processes. But since Trump returned to office in January, the industry has retreated from its plans for greener steel. Right before the inauguration, the Swedish steelmaker SSAB pulled out of negotiations for $500 million in federal funding to support a project to make iron with green hydrogen. In June, Cleveland-Cliffs exited its own green steel effort in Middletown, Ohio, after the Trump administration pressed the company to spend a $500 million Biden-era grant on ramping up coal-fired iron production.
On the face of it, Nippon’s reputation as a “coal company that also makes steel” suggested the merger would largely result in extending the life of coal-fired blast furnaces. But new investments in DRI and EAFs could transform U.S. Steel into the leading American steelmaker with lower-carbon integrated plants.
“Just building more EAFs without any clean iron going into it doesn’t really make a lot of sense,” said Roger Smith, Mighty Earth’s Japan director, who is based in Tokyo.
“Relining blast furnaces won’t help Nippon Steel achieve its commitment to become net zero by 2050. And by the time they finish planning and construction, we’ll be well past the U.S. midterm election and potentially into the next presidency,” he said. “Their plans need to be for the coming decades, not this moment in time.”
Analysis by the nonprofit energy researcher RMI shows that investing in gas-fueled DRI with an EAF is already roughly competitive with the cost of relining blast furnaces and upgrading basic oxygen furnaces at existing integrated plants.
“Every new investment decision or announcement that’s happened since the Trump administration took office has focused on cleaner steel or iron-making processes,” said Evan Gillespie, a partner at Industrious Labs, a nonprofit that researches ways to decarbonize heavy industry. “Nobody is investing in coal. That’s worth noting.”
Building only EAFs makes little sense, because the impurities in the scrap metal that’s typically used in that process make it difficult to forge steel strong enough for automobile manufacturing, the largest market for new steel in the U.S.
“U.S. Steel could build an EAF plant but source DRI from a different producer and still have a quality steel product to sell to automotive manufacturers,” said Elizabeth Boatman, a lead consultant at the Michigan-based clean energy consultancy 5 Lakes Energy.
“You can also produce steel out of high-quality scrap, when you’re careful about what you’re putting into your EAF,” she said. “Otherwise, you build a DRI-EAF plant.”
That’s what the leading low-carbon steel producer in the U.S. is doing. Hyundai Motor Group is charging ahead with plans to build a DRI plant powered by blue hydrogen — the version of the fuel that uses carbon capture to reduce emissions from gas-fueled operations — alongside an EAF. Projected to come on line in 2029, the plant is expected to switch its fuel to green hydrogen made with renewable electricity in 2034.
European steelmaker ArcelorMittal is an industrial giant, producing more of the high-strength metal than any other company except China’s state-owned Baowu Group. Its reliance on coal-fueled blast furnaces has made it a target for climate activists, who claim the Luxembourg-based manufacturer isn’t moving nearly fast enough to reduce its planet-warming pollution.
For years, advocacy groups have urged ArcelorMittal to adopt lower-carbon methods of making iron and steel. When the company sponsored the 2024 Summer Olympics in Paris, members of the Fair Steel Coalition staged a series of public actions, including projecting the message “True Champions Quit Coal” onto the side of an ArcelorMittal building in Luxembourg.
Now they’re trying a new tactic: formally documenting their frustration.
Last week, the U.K.-based nonprofit Opportunity Green filed a climate-related complaint through a process overseen by the Organisation for Economic Co-operation and Development — an influential group of 38 market-based democracies, including Luxembourg. The OECD sets voluntary guidelines for “responsible business conduct” for multinational enterprises within its sphere, and civil groups can raise concerns if they feel companies aren’t adhering to those standards.
In its complaint, Opportunity Green claimed that ArcelorMittal lacks “a robust, science-based climate strategy” — which the OECD guidelines call for — and is “failing to take adequate action” to reduce its emissions. ArcelorMittal, which generated $62.4 billion in revenue in 2024, produced more than 100 million metric tons of carbon dioxide equivalent that year, about the same amount as Belgium.
“The impact that [those emissions] are having on climate and people needs to be addressed,” Kirsty Mitchell, the legal manager at Opportunity Green, told Canary Media.
The climate group said it sent its complaint to the Luxembourg National Contact Point, a nonjudicial body that handles OECD grievances against firms in the tiny European country. Mitchell said Opportunity Green hopes to foster a “cooperative dialogue” with ArcelorMittal and to reach a resolution that accelerates the steelmaker’s efforts to clean up.
“ArcelorMittal, given its scale and influence, should really be driving more of that positive action, and that’s what we’re hoping to get out of this process,” she said.
Steelmaking is responsible for roughly 9% of global greenhouse gas emissions, making it one of the world’s most heavily emitting industries. Most of that pollution is the result of using coal-fueled blast furnaces that convert iron ore into iron. A separate furnace then turns the iron into steel for use in cars, ships, roads, bridges, furniture, appliances, and more.
ArcelorMittal operates 32 blast furnaces globally, and coal-based steelmaking accounts for about three-fourths of its annual production, according to the company.
The European steelmaker didn’t directly address questions about the Opportunity Green complaint in an email to Canary Media. But ArcelorMittal said that it remains “committed to decarbonizing our operations.”
The company noted that between 2018 and 2024 it invested over $3 billion in efforts to reduce emissions, including by testing carbon-capture technology, installing wind and solar projects, and using more scrap metal in electric arc furnaces. Scrap-based steelmaking now accounts for a quarter of its total production, up from 19% in 2018. And ArcelorMittal’s absolute emissions fell by almost 50% over the six-year period, though much of that drop was due to declining production and selling off steel and mining assets.
Still, ArcelorMittal acknowledged that “progress in decarbonizing has been slower than initially expected.”
In 2021, the company outlined plans to lead the steel industry in achieving net-zero carbon emissions by 2050. ArcelorMittal set a goal of reducing its emissions intensity — the amount of CO2 released per ton of steel produced — by 25% globally by 2030 and by 35% for steel made in Europe. The company also pledged $10 billion in total investment to help it reach those targets, including funding for hydrogen-based steelmaking.
ArcelorMittal planned to use green hydrogen — made from renewable energy — to produce iron at a proposed facility in Gijón, Spain. New electric arc furnaces, also powered by renewables, would then convert the clean iron and scrap metal into steel. While ArcelorMittal is moving forward with the electric furnaces, in 2024 it postponed making a final investment decision on the iron-production plant, citing economic headwinds for green steel and uncertainty around the European Union’s climate and trade policies.
“Our original plans were premised on a favourable combination of policy, technology, clean energy, and market development that have not progressed as originally foreseen,” ArcelorMittal said in the email. “We are not the only company — nor is steel the only industry — to be experiencing such challenges.”
In Mitchell’s view, ArcelorMittal shouldn’t sit back and wait for all the political and economic stars to align before committing to more ambitious climate action today. Instead, she said, the company should press ahead and help drive broader demand for green hydrogen.
“We really need near-term, deep emissions reductions” to limit global warming, Mitchell said. “And we need clear direction and transformative decisions now that create certainty, and not just acting only when everything is perfectly suited.”
The Luxembourg National Contact Point will likely review Opportunity Green’s complaint within the next three months to assess the arguments and decide whether to move it forward, Mitchell said. If ArcelorMittal opts to participate in the voluntary process, it could take anywhere from six months to a few years for the groups to reach an agreement.
“Public scrutiny and independent oversight are essential to ensure companies like ArcelorMittal deliver credible climate action,” Caroline Ashley, executive director of SteelWatch, said in a news release supporting the complaint. “The stakes are too high for further delay.”
The Trump administration has ordered another aging, costly coal plant to keep operating past its long-planned retirement date — this time in Centralia, Washington.
On Tuesday, the U.S. Department of Energy issued an emergency order requiring Unit 2 of the TransAlta Centralia Generation power plant to keep running for the next 90 days. (Unit 1 was shut down in 2020.) Power plant owner TransAlta had planned to shutter Unit 2 this month, as part of an agreement in place since 2011 with Washington state. State law prohibits utilities from burning coal starting next year.
The DOE order claims that “an emergency exists” in the Western U.S. grid that justifies this action under Section 202(c) of the Federal Power Act. President Donald Trump’s DOE has used the same emergency power this year to force the J.H. Campbell coal plant in Michigan and the Eddystone oil- and gas-burning plant in Pennsylvania to keep running via successive 90-day orders. It may issue more must-run orders to coal plants set to close at the end of the year in Colorado and Indiana.
State regulators and environmental and consumer advocacy groups have filed legal challenges to the DOE’s must-run order for J.H. Campbell in Michigan, saying the agency is misusing its authority as part of a broader political agenda to protect the coal industry. The complaints highlight that emergency claims from Energy Secretary Chris Wright, a former gas industry executive who denies that climate change is a crisis, are unsubstantiated — and that utilities and regulators have found the plant can be safely closed.
Forcing some of the country’s oldest and most expensive coal plants to keep running is driving up costs for utility customers already struggling with rising electricity bills.
Consumers Energy, the utility that owns the J.H. Campbell plant, reported that it spent at least $80 million to keep the plant running from May to the end of September, or roughly $615,000 per day.
About 27 gigawatts’ worth of coal-fired capacity is scheduled to retire in the U.S. from now until the end of 2028, according to U.S. Energy Information Administration data, equal to roughly 15% of the country’s current coal fleet. Should the Trump administration force all of those facilities to stay online, as well as other fossil-fueled power plants slated to shutter, it could cost U.S. utility customers between $3 billion and nearly $6 billion per year by the end of 2028, an August analysis from consultancy Grid Strategies found.
It would also stymie progress in decarbonizing the power grid. Coal retirements have been crucial to the emissions reductions the U.S. has managed in recent years.
“As families struggle with rising electricity bills, the Trump Administration is delivering coal for Christmas and forcing households to pay for it,” Earthjustice attorney Michael Lenoff, who is leading litigation against the DOE on its J.H. Campbell plant stay-open order, said in a Wednesday statement after the Centralia must-run order was issued. “Coal is not only the most polluting and carbon-intensive source of electricity, it’s expensive. And these aging coal plants are increasingly unreliable.”
DOE’s must-run order for TransAlta’s Unit 2 may also complicate plans to convert the power plant to run on fossil gas. Less than a week ago, TransAlta announced an agreement with utility Puget Sound Energy to convert Unit 2 to gas by late 2028 at a cost of about $600 million, which the firm said would help meet regional grid needs while reducing carbon emissions.
Pacific Northwest utilities in September released a report expressing concerns about longer-running grid reliability challenges in the region. Tuesday’s DOE order cited a separate analysis from the North American Electric Reliability Corporation (NERC) indicating “elevated risk during periods of extreme weather” for the Northwest region as justification for keeping the Centralia plant running.
But critics have pointed out that DOE’s Section 202(c) authority to force power plants to keep running for up to 90 days at a time is meant to deal with immediate emergencies, rather than serve as a tool to override the long-term planning and analysis of utilities, state regulators, regional grid operators, and reliability coordinators.
And if you’re aiming to boost reliability, aging coal plants are not your best bet. They are more likely to experience unplanned outages than modern power plants, according to a recent analysis of NERC data conducted by the Environmental Defense Fund.
“There is no ‘energy emergency’ in the Pacific Northwest that would justify forcing the continued operation of an old and dirty coal plant,” Ben Avery, the Sierra Club’s Washington state director, said in a statement on Wednesday. “All the evidence shows that when Centralia shuts down, customers’ costs will decrease and air quality will improve. Instead of lowering bills or protecting families from harmful pollution, the Trump administration is abusing emergency powers to prop up fossil fuels at any cost.”
For years, a team of experts has traveled from tiny town to tiny town in New Hampshire, helping the communities plan and execute clean energy strategies. Now the idea has secured federal funding to expand nationwide — a notable win as the Trump administration claws back billions of dollars for decarbonization policy.
The $3 million in funding was included in the fiscal 2026 agriculture spending package that President Donald Trump signed into law last month as part of the bill that reopened the government after the shutdown this fall. Sen. Jeanne Shaheen, a Democrat from the Granite State, led the push for the pilots, which could help municipalities not only cut greenhouse gas emissions but save money as energy costs rise nationwide.
“It’s very exciting to us that Sen. Shaheen saw what we were doing and saw the potential,” said Sarah Brock, director of the New Hampshire program, dubbed Energy Circuit Rider. “It would be amazing to have versions of this program scattered across the country to help communities understand and find solutions to whatever their energy challenges are.”
Shaheen’s office hopes to get the program — which will be administered by the U.S. Department of Agriculture’s Rural Utilities Service — up and running within the next year. Because it is a pilot, it does not have to go through the same extensive regulatory processes as other programs, which should allow a relatively timely implementation, a Senate aide said.
Shaheen originally proposed a national version of the program with an annual budget of $25 million in standalone legislation in 2023, and again in June 2025, before pushing to include the smaller pilot in November’s spending bill.
“The commonsense energy circuit riders pilot is an important and effective way for communities to get the tools they need to take on clean energy and energy efficiency projects that lower costs,” Shaheen said in a statement to Canary Media.
The seeds of New Hampshire’s program were planted roughly a decade ago, as towns and cities across the state formed energy committees tasked with lowering power bills and emissions, Brock said. Clean energy advocates began talking about how to support these groups, which were made up of volunteers with widely varying levels of expertise, and which often served small towns without the resources to hire staff focused on energy issues.
The conversation turned to the idea of hiring a “circuit rider,” a position modeled on the traveling preachers, judges, and doctors of centuries past, who provided their services to communities along their route. In 2018, the Neil and Louise Tillotson Fund, a foundation that supports causes in New Hampshire’s rural north, funded a position for a full-time clean energy expert who would provide knowledge and support to any town in the region at no cost. Nonprofit Clean Energy New Hampshire agreed to host the new hire.
The first energy circuit rider, Melissa Elander, had a mission statement but no real guidance on how to do her new job. She spent her first year introducing herself to towns throughout the region, offering her services as a researcher, consultant, and grant writer, and she slowly began to rack up some wins, Brock said. The first initiative she supported was an energy-efficient lighting project for the town of Whitefield, population 2,500.
“As word of those successes spread, more and more communities were interested,” Brock said. “It was clear to us there was something here.”
Today, the program has six energy circuit riders on staff, including Elander. It has expanded to cover all of the state’s 234 municipalities — 138 of which the program has provided support for — as well as small businesses. The team has helped towns navigate a wide range of projects, including weatherization of public buildings, solar installations, and planning for fleet electrification. Clean Energy New Hampshire does not have complete data, but estimates that just 41% of completed projects have yielded $4.26 million in total savings for municipalities.
The program was vital to the successful completion of an all-electric, solar-powered library in the community of Barrington, said Cynthia Hoisington, chair of the town’s energy committee. The municipality worked with an energy circuit rider to manage the process of accepting bids and choosing a vendor for the solar installation.
“You need a trusted expert in these special-knowledge situations when you want to make sure you’re doing what’s right for your town,” Hoisington said. “The bottom line is a lot of this never would’ve gotten done without their help.”
.svg)
