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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.”
It’s been a difficult year for clean energy in America. President Donald Trump entered office in January and promptly stopped the transition away from fossil fuels and toward solar, wind, and batteries in its tracks. Right?
Not quite. In fact, for all of Trump’s paeans to “beautiful, clean coal” and to natural gas, it’s clean energy that has once again led the way this year. Through November, 92% of new power capacity added to the grid in 2025 came in the form of solar, wind, or storage, according to Cleanview analysis of U.S. Energy Information Administration data shared with Canary Media.
That’s in line with figures from recent years. In 2024, 96% of U.S. capacity additions were carbon-free.
This year, solar alone accounted for half of new capacity added to the grid through November, while storage made up 31%. Despite Trump’s all-out assault on wind energy — and his pledge that no “windmills” would be built during his term — the energy source has so far accounted for more gigawatts of new electricity than gas turbines have.
It’s worth noting that December is typically the busiest month for new energy deployments in the U.S., so these numbers will look a bit different when the full-year data comes in. It’s also possible that clean-energy deployments are artificially high right now as developers race to complete projects before Trump’s restrictions on lucrative tax credits kick in. And, overall, fossil fuels still generate a much larger share of U.S. electricity than renewables do — even if solar and wind are closing that gap.
Still, the figures underscore the warnings made by energy experts, policymakers, and advocates: The Trump administration is playing with fire by trying to limit the development of solar, battery, and wind energy right when electricity demand is rising at its fastest rate in decades.
These are the quickest sources of energy to deploy. Meanwhile, gas turbines face a supply-chain crunch that is both driving up the cost of some new power plants and making it near impossible to build enough gas facilities to meet new demand, even if climate concerns weren’t a factor.
Should Trump administration policies succeed in drastically slowing down solar, batteries, and wind next year, it’ll only make the mounting energy-affordability crisis even worse.
This year in energy has been an absolute blur. We started with President Donald Trump’s declaration of a federal energy emergency, saw the gutting of clean-energy tax credits, and finished with an Election Day where affordability took center stage.
Now, with 2025 almost behind us, let’s rewind and revisit the 10 stories that defined this year.
Trump declares an energy emergency
On his first day in office, Trump set course for a total revamp of the American energy landscape. Step one: Citing rising power demand to declare a national emergency on energy, all while freezing funds for clean energy programs. Trump proceeded to use that “emergency” to prop up fossil fuels — more on that below.
Interior Department halts — then restarts — Empire Wind construction
The Trump administration’s laser focus on killing offshore wind became impossible to ignore when, in April, it ordered Empire Wind to stop work. The turbines off New York had only been under construction for a few weeks, and the stop-work order was eventually lifted. The story essentially repeated itself a few months later with the nearly complete Revolution Wind project.
The Department of Energy forces coal plants to stay open
In May, the U.S. DOE cited its “emergency” to force Michigan’s J.H. Campbell coal plant to run past its retirement date. That order has been extended twice, and so far, the plant has racked up more than $100 million in costs for utility customers. The DOE later ordered other soon-to-retire fossil-fueled plants to keep operating.
The “Big, Beautiful Bill” guts clean energy incentives
On the Fourth of July, Trump signed into law the One Big Beautiful Bill Act, which was big but certainly not beautiful for clean energy. The legislation took an axe to the Biden administration’s Inflation Reduction Act and its tens of billions of dollars in funding for the energy transition.
Nuclear gets a federal boost
At least one carbon-free power source has been exempt from Trump’s hit list. The administration has elevated nuclear power as a solution to rising power demand, including by promoting the restart of some retired nuclear plants. It’s also poured funding into the development of small modular reactors and other next-generation technologies.
Batteries have a stellar year, again
Energy storage was also spared the Trump administration’s wrath, though tariffs and “foreign entity of concern” rules will likely weaken the industry. Still, the U.S. installed 12.9 GW during the first three quarters of the year, already beating 2024’s total installed capacity of 12.3 GW.
EVs’ record quarter and collapse
Federal tax credits for EV purchases went out with a bang. In the three months before their expiration at the end of September, the U.S. saw nearly 440,000 new EVs hit the roads, smashing the past quarterly sales record. But now that we’re in a post-incentive world, EV sales have sunk.
Blue-state climate grants slashed
One of the Trump administration’s biggest attacks on clean energy came in October, when the DOE moved to claw back nearly $8 billion in grants for climate and energy projects, largely in states that voted for Democratic nominee Kamala Harris in the 2024 election. The Justice Department later admitted in a court filing that those states’ politics put them in the administration’s crosshairs.
Data center opposition reaches a fever pitch
Data centers and their potential to use huge amounts of energy became a top concern in 2025, especially in hot spots like Virginia and Texas. State legislatures introduced close to 200 bills regarding data centers this year, with about 50 aimed at incentivizing their development, and others targeting their impact on the environment and on electricity costs for other consumers.
Energy affordability defines state elections
Democrats swept this year’s few statewide elections, many of which centered on rising energy prices. Both New Jersey Gov.-elect Mikie Sherrill and Virginia Gov.-elect Abigail Spanberger campaigned on promises to tackle spiking energy costs, and the two Democrats who won seats on the Georgia Public Service Commission said they’d push to build more clean, cheap energy.
Ford trades EV ambitions for battery storage
From electrifying its bestselling F-150 to building a massive manufacturing complex in Tennessee, Ford once aspired to lead the EV transition. That all changed this week as the company announced it will incur nearly $20 billion in charges to extricate itself from its EV investments. That Tennessee facility, known as BlueOval City, will build gas-powered trucks in lieu of electric models, and production of the F-150 Lightning will end.
But as Ford backs away from EVs, it’s entering a new market. The automaker will repurpose its Kentucky EV battery facility to build grid-scale batteries instead. As Canary Media’s Julian Spector put it, Ford is essentially copying Tesla’s game plan to expand into storage — but without an EV stronghold to fall back on, it could be a risky move.
Another coal plant restart — and more to follow?
As you read above, the Trump administration’s coal plant restarts are a huge piece of its fossil-fuel-boosting agenda, and we got two more updates on that front this week. On Tuesday, the DOE ordered Unit 2 of TransAlta’s Centralia, Washington, coal power plant to stay open for the next 90 days. TransAlta has been planning since 2011 to shutter the facility, and was prepared to do so this month to comply with a Washington state law prohibiting coal burning that takes effect next year.
A similar situation may soon play out in Indiana, Canary Media’s Kari Lydersen reports. Two coal plants in the state are supposed to close this month, but their owners have told regulators they anticipate orders from the Trump administration will keep the facilities running.
Also this week: The U.S. House passed a bill that will broaden the Federal Energy Regulatory Commission’s authority to keep power plants online past their scheduled retirements.
Not so fast: The U.S. House passes the SPEED Act, an attempt at revamping the National Environmental Policy Act to hasten energy project permitting, but the bill faces a big hurdle in the Senate: opposition from climate-hawk Democrats. (Inside Climate News)
The sun is setting: Solar companies face a “mad rush” of customers looking to get panels before federal tax credits expire, leading to installation delays that could cause many hopeful buyers to miss out on the incentives. (The Verge)
Can you dig it? A Colorado coal town prepares for the closure of its nearby power plant by building an industrial park that aims to attract businesses by offering low-cost geothermal heating and cooling. (Canary Media)
Fusion fight: China pulls ahead in its race with the U.S. to prove and commercialize fusion energy technology, largely because it’s devoting far more resources to the effort. (New York Times)
Keeping renewables rolling: Tribal nations look to loans and philanthropy to keep building planned clean energy projects after the Trump administration revokes the Solar for All program and other federal funding. (Utility Dive)
Planning committee: A New Hampshire program that deploys experts to help small towns plan for a transition to clean energy inspires a federally funded nationwide pilot. (Canary Media)
Winter woes: The National Energy Assistance Directors Association predicts U.S. home heating prices will rise an average of 9.2% this winter compared to last — about three times the rate of inflation — thanks to increasing gas and electricity prices and cold conditions. (New York Times, news release)
The Georgia Public Service Commission on Friday approved a controversial plan that will allow the state’s biggest utility to commence one of the largest new fossil-fuel buildouts in the country — a move that critics fear will raise utility bills for most Georgia residents over the coming years.
The last-minute settlement was approved unanimously by the five commissioners, all Republicans. The vote came just weeks before two of those commissioners are set to be replaced by Democrats who won upset victories in the November election by running on the issue of energy affordability.
Back in November, staff at the PSC recommended that the commission allow Georgia Power to build only about one-third of the nearly 10 gigawatts of new gas-fired power plants and batteries the utility had requested. Friday’s decision instead gives it the go-ahead to move forward on building the full total.
The utility has justified that scale by pointing to forecasts of booming electricity demand due to new data-center construction. In recent weeks, however, even Georgia Power has reduced its data-center demand projections. And across the state and the country, concerns are rising that the boom in artificial intelligence that is driving data-center investments may be a bubble about to burst.
That’s why PSC staff deemed the utility’s full buildout plan too risky — and why energy experts and consumer and environmental advocates oppose it. Should Georgia Power build all of that infrastructure while data-center demand fails to materialize, its customers would be forced to pay higher bills for the unnecessary power plants.
“It is a massive financial gamble,” said Jennifer Whitfield, a senior attorney at the Southern Environmental Law Center, one of several groups protesting Georgia Power’s gas-heavy buildout plan. “The bottom line is that we don’t need this much energy based on the data that’s been provided.”
The PSC staff expect the plan to raise average household utility bills by about $20 per month, or possibly more if gas prices rise or data-center demand fails to show up, according to testimony from November. Those costs would be layered on top of six rate hikes since late 2022 that have already increased average residential bills by $43 per month, and which helped propel the two incoming Democratic commissioners to victory in November.
Georgia Power can expect to profit handsomely from the commission’s decision. The utility revealed in a Securities and Exchange Commission filing last week that the plan would allow it to invest $16.3 billion in “company-owned projects” — capital investments on which the utility earns a guaranteed rate of return.
To avoid passing extra costs onto consumers, Georgia Power would need gigawatts’ worth of data centers to be built and to continue buying electricity for decades.
Right now, it’s highly uncertain whether those data centers will ever show up.
“[O]nly a fraction of the requested capacity is backed by data center customers that have signed contracts for electric service, and even less have signed contracts covered by the protections contemplated in the Commission’s new rules and regulations,” the Southern Alliance for Clean Energy and Sierra Club wrote in a briefing filed with the commission. “With no data center customer committed to pay for most of the capacity Georgia Power is requesting for the entirety of the assets’ lifetimes, ratepayers will inevitably be on the hook.”
PSC staff in November testified that only about 3.1 gigawatts of Georgia Power’s buildout should be approved right away, based on the number of data centers that have executed contracts with the utility. It also proposed allowing about 4.3 gigawatts more on condition that additional data centers sign definitive contracts by March 2026.
Indeed, PSC staff’s forecasts of demand growth between now and 2031 were far lower than Georgia Power’s: about 6 gigawatts less under a “lower large-load materialization assumption,” and about 4 gigawatts less under a “greater large-load materialization case.”
Utilities and regulators across the country are struggling to manage similar mismatches between the unprecedented boom in proposed data centers and the increasing uncertainty that those plans will come to fruition.
When the new Democratic commissioners take office next month, it’s unclear whether they’ll be able to adjust the plan or rein in costs.
Foes of the plan are pressing commissioners to use their authority to force Georgia Power to update its load-growth forecasts and report on changing costs for the power plants it plans to build, and to retract approval for spending plans that may no longer be justified by growing demand.
But Whitfield noted that Friday’s vote by the commission authorizes Georgia Power to begin charging customers for the expenses it incurs to build and procure the resources approved by the plan.
“If in the future the commission were to modify its certification order — which it could — Georgia Power would still be able to recover any costs it incurred up to that point,” she said.
It’s also unclear whether the settlement agreement will force Georgia Power to follow through on its public pledges to limit the impact of its data center–driven investments on everyday customers, Whitfield said. Her group filed a motion earlier this week asking the commission to order Georgia Power to provide more information about its plan to use revenue from data centers and other large customers to put “downward pressure” on rates for typical residential customers.
“There are so many loopholes in the financial assurances that staff tried to achieve when it entered into this stipulation,” she said. “The end result is nearly meaningless for a typical Georgia Power customer … The reality is, we just don’t have any reassurance that all of us aren’t going to be on the financial hook for it.”
In the waning days of Governor Phil Murphy’s tenure, New Jersey officials unveiled an updated Energy Master Plan that calls for 100% clean electricity by 2035 and steep reductions in climate pollution by midcentury. Since 2019, the state has used the first version of the plan as the backbone of its climate strategy, promising reliable, affordable, and clean power.
The blueprint lands at a moment when delivering on all three goals is increasingly in doubt.
While the second Trump administration rolls back federal clean-energy support, PJM Interconnection, the regional grid operator that serves New Jersey and a dozen other states, struggles to manage surging electricity demand from artificial intelligence data centers.
“The Energy Master Plan is a statutorily required report to chart out New Jersey’s energy future,” said Eric Miller, who leads the Governor’s Office of Climate Action and the Green Economy. While not binding, it is the state’s official roadmap to attain its climate goals.
Miller’s office and the state Board of Public Utilities developed the plan with public input and help from outside consultants.
Under the plan, New Jersey is betting heavily on utility-scale solar and battery storage. State modeling envisions total solar capacity climbing to about 22 gigawatts by 2050, which is four times today’s roughly 5 gigawatts of installed solar. On paper, it would be enough to supply nearly all the state’s current households over a year. To get there, the plan assumes adding about 750 megawatts of new solar each year from 2026, roughly double the pace of solar construction in 2024.
The plan’s release follows a governor’s race in which energy costs dominated, and voters chose U.S. Rep. Mikie Sherrill, a Democrat who campaigned on preserving Murphy-era climate targets, over Jack Ciattarelli, a Republican who argued for a slower transition.
“Voters sent a clear message that clean energy is the most cost-effective path forward and the smartest long-term investment,” said Ed Potosnak, head of the New Jersey League of Conservation Voters and a local council member in Franklin Township.
The plan lands as New Jersey enters what Miller calls the “load-growth era.”
For roughly two decades, electricity demand in PJM’s footprint, which stretches from New Jersey to Illinois, was flat or falling as aging power plants retired and efficiency improved. That trend has flipped because of data centers.
“What we saw in 2024 into ’25, and I think what we’re going to see for the next 15 years, is a scenario where demand on the electric grid is growing,” Miller said.
For years, New Jersey spent billions subsidizing hundreds of thousands of electric vehicles and thousands of buildings to electrify. Now, Miller said, “some of the techniques for greenhouse gas reductions are going to have to kind of meet the moment,” by taking a more proactive role in engaging with PJM or by filling in the dearth in clean energy incentives caused by the Trump administration.
The recent PJM capacity auctions have added billions of dollars in costs for customers across the region. This showed up as a 20% jump in summer electricity bills in New Jersey this year, which became a hot campaign issue during its recent gubernatorial race.
“The wholesale price of electricity is determined by PJM and federal policy, and then also the price of natural gas,” said Frank Felder, an energy economist who has advised regulators. “New Jersey can’t do much about that.”
Participating in a fast-track rulemaking process that PJM initiated to address data center–driven demand, outgoing governor Murphy joined other governors in proposing that data center developers bring their own power generators in exchange for quicker permit processing.
PJM seeks to decide which proposals to pursue this month and file them with the Federal Energy Regulatory Commission by the end of the year.
Layered on top of PJM’s turmoil are decisions coming from Washington.
Experts repeatedly pointed to President Donald Trump’s second-term moves to strip away clean-energy tax incentives from the Inflation Reduction Act and to impose new tariffs on imported solar panels and wind equipment. They say those steps have raised costs and driven off developers.
Potosnak called it “Trump’s clean energy ban” and said the administration’s opposition to offshore wind “derailed the best chance we had to get massive amounts of offshore wind going that would have begun lowering our utility rates this year.” Several major Atlantic projects, including those planned off New Jersey’s coast, have been canceled or delayed.
Offshore wind “was a big piece of trying to get to 100% clean electricity by 2035,” Felder said. With new contracts unlikely for several years, he warned that New Jersey could be “back at basically square one” by the end of the decade.
Even so, Felder and others urged caution against writing off renewables entirely. Robert Mieth, a Rutgers University researcher who studies power systems, noted that offshore wind is well established in Europe and that, with or without U.S. manufacturing, “there will be access to competitive and affordable renewable technology from other countries.”
In the meantime, state officials point to progress in areas they can influence more directly.
Miller noted that New Jersey has gone from roughly 20,000 plug-in vehicles in 2018 to about 270,000 today, after lawmakers set clear targets and funded incentives and chargers.
The state’s “nation-leading solar program,” he said, is “primarily state-incentivized, primarily state-funded,” and it can keep expanding — albeit more slowly now — even as federal tax credits expire.
“The cheapest energy is the energy you don’t have to make,” Potosnak said, citing efficiency programs, rooftop and warehouse solar, and batteries on parking lots that “drive down utility costs for families and businesses” while cutting pollution.
For all its detail, the Energy Master Plan is not binding.
“The Energy Master Plan does not have the force of law,” Miller said. It has been “very informative,” he added, but “it is not a legal requirement that we follow it exactly.”
Gov.-elect Sherrill will determine how closely New Jersey hews to the map. Neither she nor her opponent had any role in shaping the modeling, Miller said, and the plan was not written with a particular “political future” in mind. Instead, Miller said, the Murphy administration hopes the incoming governor will treat it as “a very useful modeling exercise” or a guide.
Advocates are already trying to lock some of those targets into a statute. Potosnak’s group is backing a lame-duck bill that would incorporate the state’s 2035 goal of 100% clean energy — currently in place from a 2023 Murphy executive order — into state law.
If it passes, he said, it would give residents and environmental groups the right to sue if future administrations fall short and send a signal to investors that New Jersey’s direction will not change with every election.
At the start of next year, companies that make and buy energy-intensive commodities like steel and aluminum will enter the era of CBAM — the Carbon Border Adjustment Mechanism.
CBAM is a first-in-the-world policy by the European Union that charges fees on imports based on how much planet-warming pollution was produced in their manufacturing. On Jan. 1, 2026, the carbon tariff will officially take effect, raising costs for European businesses that source products from dirty facilities abroad.
The policy is part of the EU’s broader effort to drive the decarbonization of heavy industries in the 27-member bloc as well as globally. It’s already having a ripple effect, with other countries considering adopting their own carbon-pricing schemes and international firms investing in cleaner technologies to make their exports more enticing to Europe.
Here’s what to know as the landmark policy goes into effect.
In 2005, the EU launched the Emissions Trading System, the first scheme in the world to limit greenhouse gas emissions from power plants and industrial facilities. The ETS caps the total amount of carbon pollution that each operator is allowed to spew. The companies can then buy allowances that give them the right to generate 1 metric ton of CO2-equivalent. The idea is that making it costlier to pollute will incentivize businesses to clean up their operations.
Until now, however, the ETS has given what experts call a “free pass” to producers of certain trade-exposed commodities. Manufacturers argued that raising the costs of producing goods in Europe would make their industries less competitive on the global market. It could also push key customers, including European automakers, to import cheaper materials from countries without stringent climate policies — a phenomenon known as “carbon leakage.”
As the EU phases out these free passes, CBAM is designed to plug such a leak.
“It doesn’t make sense that you basically ask your own producers to produce in a certain way, to be as clean as possible, or else ask them to pay a price, and then let others — competitors from outside Europe — bring in their products and then compete unfairly,” Mohammed Chahim, the European Parliament’s lead negotiator on the carbon border fee, said on the Energy Policy Now podcast earlier this year.
The EU officially finalized CBAM’s rules in May 2023. Later that year, a “transitional phase” began for importers of goods from six carbon-intensive sectors: aluminum, cement, electricity, fertilizers, hydrogen, and iron and steel. Companies had to begin filing quarterly reports listing the direct and indirect carbon emissions of those products.
On Dec. 31, that phase will end, kicking off the “definitive period.”
Starting next month, in addition to tracking emissions, importers will pay a fee on covered products like steel rods, metal wiring, and ammonia. Initially, the fee will be a small percentage of the average quarterly price of CO2 allowances under the ETS — though participants could pay less, or nothing at all, if the exporting country has a similar carbon-pricing scheme in place. Over eight years, the CBAM tariff will gradually increase to represent 100% of the weekly average allowance price.
At the same time, the EU will wind down the special treatment it’s given to trade-exposed industries under the regional cap-and-trade scheme, requiring European manufacturers to gradually pay more for their facilities’ emissions.
The free allowances were “always viewed as a bit of a black mark on Europe’s decarbonization ambitions,” said Trevor Sutton, who leads the program on trade and the clean energy transition at Columbia University’s Center on Global Energy Policy. European regulators have billed CBAM as a “necessary component” to meeting the region’s climate goals — a way to curb industrial emissions without endangering its economy, he added.
To start, the rules will only apply to importers that bring in more than 50 metric tons of goods every year. According to the EU, this threshold excludes roughly 90% of importers, who are mainly small and medium-sized businesses, but still captures around 99% of emissions from CBAM-covered goods, since large manufacturers represent the bulk of industrial imports.
CBAM has dominated global discussions on climate policy and trade in recent years. But the regulation itself is surprisingly narrow in scope. Targeted products only make up 3% of EU imports from countries outside the bloc. And the carbon footprint of those goods collectively represents about 0.31% of global greenhouse gas emissions in 2022, according to the Organisation for Economic Co-operation and Development.
Still, “it’s a topic that inspires intense emotions,” Sutton said.
Critics, including Europe’s trade partners in the Global South, have argued that the carbon tariff amounts to protectionism — an excuse to shut out foreign competition — and “green imperialism,” since Europe is unilaterally making decisions that affect producers abroad. Mozambique, for instance, sends 97% of its aluminum exports to the EU, leaving it especially exposed.
Manufacturers within the EU have also pushed back against CBAM and the related decline in free CO2 allowances, claiming that the measures put companies at a competitive disadvantage in global markets and will inflate costs for producers. Last week, the head of French aluminum producer Constellium urged Europe’s regulators to “eradicate” CBAM altogether. Importers and their suppliers have also expressed frustration at the onerous and confusing requirements involved with tracing and reporting emissions, Sutton said.
Even so, some of the EU’s key trading partners are responding to CBAM’s signals. Since the measure passed, countries like Brazil and Turkey have introduced domestic carbon-pricing policies. The United Kingdom is set to implement its own Carbon Border Adjustment Mechanism starting in 2027. China, for its part, has started shipping steel made using hydrogen to Italy — a move experts say could set the stage for increasing Chinese green-steel exports.
Sutton said that CBAM “has helped drive a conversation and elevated the salience of carbon pricing” in other countries, while also setting “a foundation for decarbonization of European industry.”
Colorado just set a major new climate goal for the companies that supply homes and businesses with fossil gas.
By 2035, investor-owned gas utilities must cut carbon pollution by 41% from 2015 levels, the Colorado Public Utilities Commission decided in a 2–1 vote in mid-November. The target — which builds on goals already set for 2025 and 2030 — is far more consistent with the state’s aim to decarbonize by 2050 than the other proposals considered. Commissioners rejected the tepid 22% to 30% cut that utilities asked for and the 31% target that state agencies recommended.
Climate advocates hailed the decision as a victory for managing a transition away from burning fossil gas in Colorado buildings.
“It’s a really huge deal,” said Jim Dennison, staff attorney at the Sierra Club, one of more than 20 environmental groups that advocated for an ambitious target. “It’s one of the strongest commitments to tangible progress that’s been made anywhere in the country.”
In 2021, Colorado passed a first-in-the-nation law requiring gas utilities to find ways to deliver heat sans the emissions. That could entail swapping gas for alternative fuels, like methane from manure or hydrogen made with renewable power. But last year the utilities commission found that the most cost-effective approaches are weatherizing buildings and outfitting them with all-electric, ultraefficient appliances such as heat pumps. These double-duty devices keep homes toasty in winter and cool in summer.
The clean-heat law pushes utilities to cut emissions by 4% from 2015 levels by 2025 and then 22% by 2030.
But Colorado leaves exact targets for future years up to the Public Utilities Commission. Last month’s decision on the 2035 standard marks the first time that regulators have taken up that task.
The commission’s move sets a precedent for other states working to ditch fossil fuels from buildings even as the federal government eliminates home-electrification incentives after Dec. 31. Following Colorado’s lead, Massachusetts and Maryland are developing their own clean-heat standards.
Gas is still a fixture in the Centennial State. About seven out of 10 Colorado households burn the fossil fuel as their primary source for heating, which accounts for about 31% of the state’s gas use.
If gas utilities hit the new 2035 mandate, they’ll avoid an estimated 45.5 million metric tons of greenhouse gases over the next decade, according to an analysis by the Colorado Energy Office and the Colorado Department of Public Health and Environment. They’d also prevent the release of hundreds more tons of nitrogen oxides and ultrafine particulates that cause respiratory and cardiovascular problems, from asthma to heart attacks. State officials predicted this would mean 58 averted premature deaths between now and 2035, nearly $1 billion in economic benefits, and $5.1 billion in avoided costs of climate change.
“I think in the next five to 10 years, people will be thinking about burning fossil fuels in their home the way they now think about lead paint,” said former state Rep. Tracey Bernett, a Democrat who was the prime sponsor of the clean-heat law.
Back in August, during proceedings to decide the 2035 target, gas utilities encouraged regulators to aim low. Citing concerns about market uptake of heat pumps and potential costs to customers, they asked for a goal as modest as 22% by 2035 — a target that wouldn’t require any progress at all in the five years after 2030.
Climate advocates argued that such a weak goal would cause the state to fall short on its climate commitments. Nonprofits the Sierra Club, the Southwest Energy Efficiency Project, and the Western Resource Advocates submitted a technical analysis that determined the emissions reductions the gas utilities would need to hit to align with the state’s 2050 net-zero goal: 55% by 2035, 74% by 2040, 93% by 2045, and, finally, 100% by 2050.
History suggests these reductions are feasible, advocates asserted.
“We’re recommending targets that put us on a technology-adoption curve — a trajectory that’s been seen over and over again,” said Ramón DC Alatorre, senior program manager at the Southwest Energy Efficiency Project. “There’s a tremendous amount [of] mature technology available today in order to be able to meet these targets.”
Heat pumps, for example, have a track record of holding their own even in Denver’s deepest freezes. Some companies are devising ways to bring installation costs way down. And the state is making the tech more affordable via a federally funded rebate program for low-income households and tax credits worth hundreds of dollars for both customers and contractors.
Expecting the market to move more slowly than advocates predicted, the Colorado Energy Office and the Colorado Department of Public Health and Environment recommended a 41% cut. But then in September, after reviewing stakeholders’ comments, the agencies dropped it to 31% — a “more realistic, yet still ambitious goal,” they wrote.
The agencies’ 41% proposal was “far better supported” by their own analysis, Commissioner Megan Gilman said at the Nov. 12 commission meeting: Agencies found that this target comports with the clean-heat law. The 31% figure, by contrast, seemed untethered to the legislation’s mandates, she noted.
The commission’s decision doesn’t factor in concerns about the cost of decarbonization — nor is it meant to, Gilman said. The regulators will address cost-effectiveness when they evaluate utilities’ specific plans for complying with the statute, which are required every four years. Xcel Energy, the state’s largest utility, will file its next plan in 2027.
Even as Colorado doubles down to leave gas in the past, Xcel isn’t planning to relinquish the fossil fuel anytime soon.
Xcel provides gas to 1.5 million customers across the state. From 2025 to 2029, the utility is seeking to invest more than $500 million per year on the gas system — costs passed on to customers via their energy bills. That’s a bigger investment than Xcel’s $440 million plan for 2024 to 2028 to reduce reliance on gas by implementing clean-heat measures.
Overbuilding gas infrastructure now could have decades-long ramifications for energy bills. “If utilities are not scaling these [electrification] programs, the customers left on the gas systems are ultimately going to face higher costs,” said Courtney Fieldman, utility program director of the Southwest Energy Efficiency Project.
Colorado is nudging gas utilities to instead become clean-heat utilities; for example, lawmakers have directed the companies to pilot zero-emissions geothermal heating projects and thermal energy networks.
Meanwhile, the commission’s November decision sends a clear signal that utilities need to adjust their gas-demand forecast, the Sierra Club’s Dennison said. While advocates hoped that regulators would create more policy certainty by setting targets beyond 2035, commissioners demurred. They have until 2032 to get those standards finalized.
“The targets that conservation advocates have proposed are achievable,” said Ed Carley, an expert on building decarbonization policy at Western Resource Advocates. Adopting them “is really our opportunity to be a leader in achieving our greenhouse gas emissions goals — and demonstrating that market transformation is possible.”
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