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U.S. solar manufacturers start 2026 in an odd position. They have made real strides toward reshoring production, but still have a long way to go — and federal and trade policies are layering new uncertainties onto the task.
The U.S. is now actively producing all the major components in the solar supply chain: polysilicon, ingots, wafers, cells, and modules. That hasn’t happened in over a decade, since SolarWorld closed its wafer-production plant in Oregon in 2013.
“Except for the glass, everything we have in the module could be domestic, should the client choose that,” said Martin Pochtaruk, CEO of Heliene Solar, which manufactures in Minnesota. “The main issue is the limitation on capacity.”
The U.S. can make almost 65 gigawatts of panels annually, according to the Solar Energy Industries Association. But it can’t yet build enough of the precursor components to meet the demand for panels. (SEIA expects the U.S. will install 44 gigawatts of direct-current solar capacity this year.)
Major factory construction now underway takes aim at that shortfall, even as factory owners grapple with upheavals in federal domestic and trade policies.
Congress created new rules last year that block tax credits from going to “foreign entities of concern,” or FEOC. Those regulations technically kicked in on Jan. 1, but the Treasury Department still needs to release preliminary guidance and launch formal rulemaking.
Separately, an anti-dumping investigation could raise tariffs on solar imports from India, Indonesia, and Laos, as part of a long-running Commerce Department effort to block imports by China-linked companies that build in other countries to avoid steep tariffs.
And last year, Commerce Secretary Howard Lutnick launched an investigation into the national security implications of the polysilicon supply chain, which could impose global tariffs on products that contain polysilicon — including solar panels and their components.
Here are the three biggest storylines to follow for the state of domestic solar manufacturing in 2026.
As of last year, U.S. factories have officially been able to make enough solar modules to meet domestic demand.
Cell capacity, however, lags far behind, at just 3.2 gigawatts. This year, companies are pushing to catch up.
“If we want to have the manufacturing here, we have to have the cell manufacturing here, because that’s the most difficult step, in many ways; it’s where a lot of the innovation happens,” said Tim Brightbill, a lawyer at Wiley Rein LLP who has brought numerous trade cases on behalf of domestic manufacturers. “We can’t just outsource that to China and hope the rest of the industry will be OK.”
Newcomer T1 Energy started building its cell factory in December in Rockdale, Texas, and should open 2.1 gigawatts of cell production by year’s end.
“This is the year of execution for us,” said Russell Gold, T1’s executive vice president for strategic communications. The 100-acre facility will cost $400 million to build and will generate 1,800 jobs. A planned second phase would add another 3.2 gigawatts.
Qcells, the subsidiary of Korean conglomerate Hanwha, is still plugging away on its ingot, wafer, and cell factory in Cartersville, Georgia. The site started producing modules in 2024; it was supposed to produce ingots, wafers, and cells — the more complicated precursor steps — in 2025, but that build-out fell behind schedule. Qcells is aiming to get Cartersville fully operational by the end of 2026, said Marta Stoepker, head of corporate communications at Qcells North America.
Norway’s NorSun had planned a $620 million, 5-gigawatt ingot and wafer factory near Tulsa, Oklahoma, set to open in mid-2026 and supply Heliene and others. But the company’s website returns a 404 error code, and NorSun told Heliene that the Tulsa factory is not moving ahead, Pochtaruk said.
Heliene had wanted to build a cell factory to supply its 1.3-gigawatt module production in Minnesota, but it froze development amid the market turbulence when President Donald Trump took office in 2025. In the coming weeks, Pochtaruk said, Heliene will begin large-scale production of panels using Suniva cells made with domestic wafers, supplied by Corning, which are sliced from domestic polysilicon created by Hemlock Semiconductor in Michigan.
Then there’s an important outlier: First Solar, which has long been the only solar manufacturer with a homegrown supply chain.
First Solar is also unique in that it eschews silicon in favor of thin-film deposition of cadmium and telluride. It’s able to produce a fully functioning solar panel without the separate steps of carving wafers or etching silicon cells. That advantage allowed the company to grow and thrive behind protective U.S. tariffs in the years when the silicon-solar industry collapsed.
First Solar has built 14 gigawatts of domestic manufacturing capacity across Alabama, Louisiana, and Ohio and is building a new site in South Carolina.
The Republican budget law passed last year forces companies that want to claim the solar manufacturing tax credit, or tax credits for installing solar panels, to prove that they aren’t overly beholden to control or support from prohibited Chinese entities.
Weaning any high-tech supply chain from Chinese influence is challenging, but the task is further complicated because the federal government hasn’t finalized its rules yet. In theory, any panel coming off the line since New Year’s Day needs to comply, but doing so requires a bit of extrapolation, or perhaps luck.
Some companies should have no problems. Heliene is headquartered in Canada. Qcells hails from Korea. First Solar is homegrown. Still, they need to pay for the legalistic accounting to prove they qualify.
Some manufacturers that had ties to China, however, have taken steps to reverse that status. China’s JA Solar sold its Arizona factory to Corning. Trina Solar sold its Dallas factory in 2024 to the company that became T1; in December, T1 released a detailed breakdown of the steps the U.S.-headquartered company took to clear itself of FEOC-related risk.
“We want to show investors, hey, we’re prepared for this, we did our work,” Gold said.
Others have slightly more complicated arrangements, like Canadian Solar, which, despite its name, operates largely out of China; and Illuminate USA in Ohio, a joint venture between U.S. developer Invenergy and Chinese solar giant Longi. These firms have not yet completed the kind of sell-off that Trina did with T1, so it’s harder to see how their 2026 production could qualify for tax credits.
In another category are clearly Chinese-owned factories in the U.S., including JinkoSolar in Florida and Hounen Solar in South Carolina, which seem sure to fail the FEOC test.
The quest for FEOC compliance will be a dominant theme for the industry this year — especially once the rules are actually released.
U.S. solar manufacturing has long depended on trade protections, and two major proceedings could reshape the global playing field this year.
Historically, the U.S. has levied tariffs on China’s solar exports in order to offset government subsidies that helped drastically lower the cost of panels made there. Major Chinese manufacturers responded by building module assembly factories in other countries that did not face such tariffs.
Last year, the U.S. added tariffs on solar modules from Cambodia, Malaysia, Thailand, and Vietnam after concluding a Biden-era trade case.
A subsequent petition by U.S. manufacturers could extend tariffs to India, Indonesia, and Laos. Such requests used to draw an outcry from solar developers, who would face higher prices for their materials. But last year, at the U.S. International Trade Commission’s preliminary hearing for the latest case, nobody testified in opposition, Brightbill said, though some parties later filed opposing statements.
The Commerce Department’s investigations could wrap up over the next few months and lead to preliminary duties, with a final determination coming in the early fall.
A different trade action could take a more global approach than this country-by-country effort.
“It’s not only tax credits you have to look into,” Pochtaruk said of planning new factory investments. “Any and all business plans have to have in consideration what the heck the 232 [outcome] is.”
He’s referring to the ongoing investigation into the national security implications of the polysilicon supply chain, under Section 232 of the Trade Expansion Act of 1962. Trump previously used this mechanism to push for tariffs on things like steel and aluminum; it’s different from the authority he invoked for the so-called Liberation Day tariffs last year.
“The courts have largely upheld Section 232 actions by the president, because they tend to defer to the president on national security issues,” Brightbill said.
The Section 232 investigation could produce a far-reaching global tariff on products that contain silicon — not just raw polysilicon but also finished solar cells and panels.
Such a global tariff could drive up costs for the domestic module makers that still have to import cells, since the U.S. is not yet self-sufficient in that step. Then again, it would also raise the cost of foreign modules competing with domestic ones.
“It could be a way to address this Whac-A-Mole problem that we’ve been dealing with for some time,” Brightbill said.
By statute, the Commerce Department must send recommendations to the White House by March 28, which then gives the president 90 days (until late June) to formulate a response.
“All of this contributes to a level of uncertainty around your solar supply chain, and makes building a reliable, transparent, domestic solar supply all the more important,” said Gold, of T1. “The fact that we have a supply deal with Hemlock and Corning gives us a lot of comfort.”
New Hampshire Republicans are attempting to do away with a 50-year-old property tax exemption for households and businesses with solar, contending that the policy forces residents without the clean energy systems to unwittingly subsidize those who have them. Supporters of the exemption, however, say this argument is misleading, insulting, and at odds with New Hampshire’s tradition of letting communities shape their own local governments.
The focus of the debate is a bill proposed in the New Hampshire House this month by Republican Rep. Len Turcotte and several co-sponsors in his party. The measure would repeal a law, established in 1975, that authorizes cities and towns to exempt owners of solar-equipped buildings from paying taxes on whatever value their solar systems add to their property. As of 2024, 153 of the state’s municipalities – roughly two-thirds – had adopted the exemption, one of the only incentives offered in support of residential solar power in the state.
The exemption means that homeowners without solar must pay more property tax to make up for the money not being collected from the “extreme minority” who have solar panels, Turcotte said while presenting his legislation at a hearing of the House Science, Technology, and Energy Committee last week. This “redistribution” of the tax burden is unfair, he said.
The solar property tax exemption is a fairly common policy: Nationally, 36 states offer some version of it. While legislators in many states have targeted pro-solar policies like net metering, property tax exemptions have so far avoided similar attacks. New Hampshire, therefore, could end up as a proving ground for whether this approach can find traction.
New Hampshire does not have a sales tax or an income tax and leans heavily on local property taxes for revenue; its rates are among the highest in the country. That makes changes to property tax policy a particularly sensitive subject. The solar exemption bill has Republicans, who are typically tax averse, walking a fine line between championing what they say is fairness for all and pushing a policy that will inevitably raise taxes for some.
The state authorizes 15 other property tax exemptions — including for elderly residents, veterans, and those with disabilities — but Turcotte’s bill targets only the one for solar.
The exemption is a “local option” policy, meaning cities and towns must opt in through a vote in each municipality. Turcotte, however, doubts the average resident realized that they were signing up to pay more on their own taxes.
“They see a feel-good measure,” he said. “Do they truly understand? I don’t believe they do.”
After Turcotte presented his bill, the remaining speakers — about a dozen clean energy advocates, lawmakers, business leaders, and local solar owners — uniformly opposed his proposal.
Removing the exemption would be an unfair rule change after homeowners invested in solar systems with the understanding they’d be getting a tax break, many argued. Businesses using solar could face a “significant tax increase,” said Natch Greyes, vice president of public policy at New Hampshire’s Business and Industry Association. The change could cost homeowners with solar hundreds of dollars per year while barely reducing the property tax rate for everyone else, others said.
In the town of Hudson, for example, $2.2 million in property value isn’t taxed because of the exemption, out of a tax base of $5.1 billion, its chief assessor James Michaud testified. Removing the exemption would have virtually no effect on the tax rate, he said.
“It’s almost incalculable how small it is,” he said.
Whatever tiny tax shift the exemption creates is worth it, others argued, saying that it provides an incentive for the public good: More solar means lower greenhouse gas emissions and less burden on the grid. Turcotte countered that these broader benefits of solar — many of which have been well documented — are “subjective.”
The question of local control also loomed large in the testimony. In New Hampshire, whose motto is “Live Free or Die,” the right of individual towns to decide on their own rules and regulations has long been a point of pride. Repealing the exemption would mean overriding decisions made by voters. Turcotte’s claim that residents didn’t understand what they were getting into is not only condescending but also just plain wrong, several witnesses said.
“You are essentially, with this bill, substituting your judgment about what is proper at the level of local taxation for that of town meetings and city councils throughout the state,” said Rep. Ned Raynolds, a Democrat, while questioning Turcotte.
The bill now awaits a vote in committee before it can face a floor vote from the full House. It would then advance to the Senate. Republicans control both chambers of the state Legislature and the governor’s office.
But the bill’s opponents hope that lawmakers will heed their arguments and give weight to the mass of voters who have approved the exemption across the state.
“This is the reason two-thirds of the towns have adopted it: They can see it’s a good thing,” testified David Trumble, a solar owner from the town of Weare. “Solar is a good thing.”
Last year brought a torrent of bad news for the U.S. electric vehicle industry. The Trump administration pushed Republicans in Congress to cancel Biden-era EV tax credits and revoke states’ rights to set clean-car mandates. The White House moved to weaken vehicle fuel-economy standards. And it froze billions of dollars in federal EV-charging grants — although legal challenges have since unlocked $5 billion of that money.
Despite the upheaval, U.S. public charging networks had a growth spurt last year, according to a report released today by data analytics firm Paren. And the new chargers are working more reliably and being used more heavily than ever — a sign the country is matching charging supply to demand.
The nation’s public fast-charging network expanded by 30% over the course of 2025, adding 18,041 ports, according to Paren. That’s up from the 13,970 fast-charging ports deployed in 2024, and way up from the 5,313 installed in 2021.
“We’ve got a record number of chargers being deployed by a bunch of new players in the industry, as well as the stalwarts,” said Bill Ferro, Paren’s co-founder and chief technology officer.
Last year’s growth included more charging stations, but also more ports per station, Ferro noted. That’s a sign that charging providers are striving to ensure that EV drivers don’t have to wait too long for a charge when they pull up.
Reliability scores, which Paren measures as the share of charging sessions that are successfully completed, ticked up in 2025 too, averaging 93%. That’s good news for EV drivers who’ve been disappointed by malfunctioning chargers in past years. Ferro credited these incremental improvements both to new infrastructure, “which by default is going to work better,” and improved maintenance and remote diagnostics of malfunctioning chargers.
And utilization rates — a measure of how often a charging port is in use — held steady in most states and even increased slightly in some over the course of 2025. Paren tracked 141 million public charging sessions from January to December, a roughly 30% increase from the previous year.
Paren’s data indicates that charging infrastructure is expanding at a rate that matches up well with demand from a growing number of EV drivers, Ferro said. Maintaining that balance is vital for charging providers, who don’t want to overinvest in charging stations that fail to get enough business to pay themselves off, but also don’t want to leave drivers waiting too long for charging ports to open up.
To date, charging remains in much higher demand in some states than in others. California led the pack on utilization of its fast chargers in 2025, as it has for years, followed by Florida, Hawaii, Maryland, New Jersey, and Nevada. But the fastest growth in utilization occurred in Sunbelt states, including Arizona, Georgia, and Texas.
Importantly, the growth in charging infrastructure was driven almost entirely by private investment rather than by government funding, Ferro said. Tesla, which operates the country’s biggest charging network, continued to lead the pack, with more than 6,700 charging ports deployed in 2025, more than a third of the total. But longtime charging operators, other automakers, and regional players also each added hundreds of charging stations over the course of the year.
This increasing private investment helped counteract the decline in federal funds. In February, the Trump administration tried to cancel the $5 billion National Electric Vehicle Infrastructure program. After setbacks in court, the U.S. Transportation Department reopened the NEVI program in August, allowing states to resume contracting and installing chargers. Last week, a federal judge ruled that the department’s initial suspension of the funding was unlawful.
That program was designed to bolster public charging along highways and other major transit corridors across the country, including places where EV adoption has lagged, undermining the business case for building chargers. But with just over 700 ports installed as of the end of 2025, NEVI projects make up only a small fraction of the country’s total public charging — although they’re important for rural areas where chargers are still hard to find.
Although NEVI dollars are flowing again, the Trump administration hasn’t released the entirety of the federal EV-charging funding it canceled last year. States and environmental advocates have filed lawsuits seeking to force the federal government to unfreeze the $2.5 billion Charging and Fueling Infrastructure grant program for state and local agencies, much of it targeted at expanding charging in rural and lower-income areas.
Meanwhile, the One Big Beautiful Bill Act passed by Republicans in Congress last summer not only ended EV tax credits as of September 2025, but will end tax credits for EV chargers as of July 2026. The law also rescinded hundreds of millions of dollars from the Environmental Protection Agency’s Clean Heavy-Duty Vehicles Program, which was meant to help state and local governments, schools, territories, and tribes purchase zero-emissions trucks and buses and charging equipment.
Even NEVI isn’t out of the woods yet. The draft fiscal year 2026 transportation bill introduced in Congress earlier this month would strip $503 million in unobligated funds from the program, according to the Sierra Club, as well as $300 million earmarked for repair and maintenance of chargers — a potential hit to the network’s reliability.
Looming large over charging providers is the risk that EV adoption may slide precipitously downward. Demand for the vehicles boomed right before federal tax credits expired in September, but sales are now slowing. And major automakers Ford and General Motors have written down billions of dollars of losses on their EV investments.
Still, Paren is forecasting that charger deployments will continue to rise in 2026, albeit at a rate of about 8%, much slower than the breakneck pace set last year. Ferro sees the risks of overbuilding charging infrastructure falling mainly on smaller companies or those overly reliant on federal funding, whose networks could be snapped up by bigger firms.
“I think the industry is going to consolidate and expand at the same time,” he said. “We know the larger players are building out for the future. They’re not looking to 2027 for their goals. They’re looking to 2035.”
In the United States, the Trump administration is waging a relentless war on offshore wind, taking an all-of-government approach to thwarting construction of turbines at sea.
On the other side of the Atlantic, however, 10 European countries have formed an alliance to build out 100 gigawatts of offshore wind power and transform the North Sea into what German Chancellor Friedrich Merz called “the world’s largest clean energy reservoir.”
On Monday, officials from Belgium, Denmark, France, Germany, Iceland, Ireland, Luxembourg, the Netherlands, Norway, and the United Kingdom met in Hamburg to sign a declaration vowing to collaborate on construction of enough offshore wind capacity to power nearly 150 million households by 2050. The document, dubbed the Hamburg Declaration, affirms a goal of building a total of 300 gigawatts of offshore wind capacity in the region, although only a third of that would come from international projects that involve cross-border collaboration. The remaining two-thirds would come from national projects built by countries to send power to their own grids.
At least 100 companies signed onto an accompanying industry declaration in which they promise to cut the costs of offshore wind installations and hire upward of 91,000 workers.
“This is a move not just to establish European energy independence, but to support a strategic sector that’s had a very difficult few years,” said Ollie Metcalfe, the head of wind research at the consultancy BloombergNEF.
Europe has faced energy shortages since Russia invaded Ukraine in 2022, forcing Kyiv’s allies to wean themselves off the cheap natural gas the Kremlin had shipped westward for decades. The continent ramped up imports of American liquefied natural gas, but that proved very expensive and has left Europe vulnerable to the Trump administration’s bullying on issues such as Greenland’s sovereignty. Nuclear power produces roughly one-quarter of Europe’s electricity, but building new reactors can take well over a decade and some countries, including Luxembourg, remain firmly opposed to atomic energy. In cloudy Northern Europe, with its limited solar potential, harnessing the fierce gusts on the North Sea with offshore turbines represents one of the best options to produce large volumes of power.
Implementing the pact will prove harder than signing it. Countries with lower electricity prices are likely to encounter pushback over a cross-border compact with nations whose energy-market policies have driven up rates. Norway boasts relatively low electricity prices thanks to its vast system of hydroelectric dams. Already, exports of Norwegian electricity to the continent, where Germany’s decision to shut down its nuclear power plants helped push its rates to some of the highest levels in the world, have stirred political blowback in the Nordic nation.
“Sometimes the technical stuff sounds like the most difficult to overcome, but in reality it’s the political and regulatory barriers that end up being the most difficult to solve,” Metcalfe said.
Norway may contribute the fewest turbines under the pact, BloombergNEF forecasts, because its continental shelf drops sharply into deep water, making it difficult to site traditional turbines bolted to the seafloor. Norway has experimented with floating turbines, but the technology is much less mature. And the country’s offshore energy industry has traditionally focused on oil and gas. (Landlocked Luxembourg, which lacks a shoreline, is contributing financing to the deal.)
Europe’s homegrown offshore wind giants, such as Norway’s Equinor and Denmark’s Ørsted, are likely vendors for the buildout, said Gaurav Purohit, the Germany-based vice president of European asset finance at the credit-ratings agency Morningstar DBRS. With the U.S. government bearing down on projects such as Ørsted’s Revolution Wind in New England and Equinor’s Empire Wind in New York, he said the North Sea buildout would allow the companies to redirect capital back to Europe.
Other likely winners of the offshore wind push include the German utility RWE, German transmission giants TenneT and Amprion, and the French energy giant TotalEnergies, which has committed to a big renewables buildout — a contrarian move among oil majors. While China’s soaring offshore wind companies are looking to enter the European market, “I do think European developers will benefit more,” Purohit said.
But he cautioned that the high cost of building offshore wind, particularly when interest rates are elevated and inflation is driving up the price of materials, means that projects would likely “need financial institutions to take a stake.”
Increasing the transmission connections is key, said Matt Kennedy, an executive who heads up sustainability issues for IDA Ireland, the government agency that attracts foreign investment. Right now, the island nation on the EU’s western fringe is connected to other grid systems only by power lines to the United Kingdom. In 2028, the Celtic Interconnector, a 700-megawatt power line connecting Ireland to France, is set to come online, establishing the first direct transmission between the Emerald Isle and the continent. Kennedy said the two-way line will likely hasten construction of offshore wind in Ireland, where the industry has been stunted by planning bottlenecks and, like Norway, a steep continental shelf dropoff. Ireland, which already has a large onshore wind industry, has 7 gigawatts of offshore turbines approved.
Establishing a link to France “really sets the pace for us to be able to deliver on our commitment,” Kennedy said.
“This is a radical step,” he added. “It’s a massive step for Ireland in terms of providing that enabling architecture to access the European market. This will allow us to export an abundance of renewable energy that we plan to have, but also in times of need allows us to import.”
The pact is not renewable energy for the sake of going green, said Ed Miliband, the British secretary of state for energy security and net zero.
“Our view on offshore wind energy is hard-headed, not soft-hearted,” he said, according to Euronews. “I think offshore wind is for winners. Different countries will pursue their national interests, but we are very clear where our interests lie.”
A decade ago, North Carolina boasted more solar power than any other state in the country but California — a distinction owed to scores of large projects built under a suite of clean energy–friendly policies that the Tar Heel State has since repealed or amended.
Now, many of those solar farms are staring down the end of their initial agreements with Duke Energy, the state’s predominant utility. But under a new proposal before North Carolina regulators, project owners could lock in favorable long-term renewals pending one main condition: They have to add batteries.
The scheme was proffered by Duke and is backed by clean energy businesses and advocates. If it’s green-lit by the North Carolina Utilities Commission, it would represent the first systematic move toward “repowering” large-scale solar facilities in the state. The potential is enormous: Contracts expiring in the next five years total 1.9 gigawatts — an amount equal to more than a quarter of North Carolina’s entire utility-scale solar fleet.
Since battery storage will benefit from federal tax credits with few strings attached for at least another six years, and Duke faces daunting power demands from coming data centers and other large electricity users, this form of repowering could support reliability and affordability. In large swaths of rural North Carolina, extending the life of these older projects also makes more sense than decommissioning them.
“Adding batteries to a system that’s already out there makes it immensely more valuable to the grid,” said Steve Kalland, executive director of the North Carolina Clean Energy Technology Center. “In North Carolina, that’s going to be significant.”
More so than its ample sunshine or abundant open space, state policy propelled North Carolina to become a national solar leader back in 2016.
A decades-old state tax credit supplemented federal incentives, and in 2007, lawmakers adopted a modest but meaningful renewable energy requirement. But perhaps most important was the state’s implementation of a federal law designed to encourage small power producers independent of utility monopolies. North Carolina’s rules under the Public Utility Regulatory Policy Act, or PURPA, were among the most favorable in the country, with standard offer, 15-year contracts available for projects with up to 5 megawatts of capacity.
This cocktail of rules and mandates caused PURPA-qualified solar projects to soar, with over 450 large-scale developments coming online in the state from 2010 to 2017, according to the nonprofit North Carolina Sustainable Energy Association, with a capacity of over 3.3 gigawatts.
But by 2017, Duke was on pace to easily meet the clean energy mandate, and Republican state lawmakers had repealed the tax incentive. What’s more, the utility said the surge in solar was creating interconnection bottlenecks and the need for expensive grid upgrades.
So the company helped draft a new state law that year meant to clear the backlog and move most new solar into a competitive procurement process. The standard offer contracts under PURPA survived but were reduced to 10 years for projects with up to 1 megawatt.
In part due to the PURPA changes, annual solar installations in the state have slowed, dropping from a peak of 985 megawatts in 2017 to an average of just under 500 megawatts in the years that followed.
How much should data centers pay for the massive amounts of new power infrastructure they require? Wisconsin’s largest utility, We Energies, has offered its answer to that question in what is the first major proposal before state regulators on the issue.
Under the proposal, currently open for public comment, data centers would pay most or all of the price to construct new power plants or renewables needed to serve them, and the utility says the benefits that other customers receive would outweigh any costs they shoulder for building and running this new generation.
But environmental and consumer advocates fear the utility’s plan will actually saddle customers with payments for generation, including polluting natural gas plants, that wouldn’t otherwise be needed.
States nationwide face similar dilemmas around data centers’ energy use. But who pays for the new power plants and transmission is an especially controversial question in Wisconsin and other “vertically integrated” energy markets, where utilities charge their customers for the investments they make in such infrastructure — with a profit, called “rate of return,” baked in. In states with competitive energy markets, like Illinois, by contrast, utilities buy power on the open market and don’t make a rate of return on building generation.
Although seven big data-center projects are underway in Wisconsin, the state has no laws governing how the computing facilities get their power. Lawmakers in the Republican-controlled state Legislature are debating two bills this session. The Assembly passed the GOP-backed proposal on Jan. 20, which, even if it makes it through the Senate, is unlikely to get Democratic Gov. Tony Evers’ signature. According to the Milwaukee Journal Sentinel, a spokesperson for Evers said on Jan. 14 that “the one thing environmentalists, labor, utilities, and data center companies can all agree on right now is how bad Republican lawmakers’ data center bill is.” Until a measure is passed, individual decisions by the state Public Service Commission will determine how utilities supply energy to data centers.
The We Energies case is high stakes because two data centers proposed in the utility’s southeast Wisconsin territory promise to double its total demand. One of those facilities is a Microsoft complex that the tech giant says will be “the world’s most powerful AI datacenter.”
The utility’s proposal could also be precedent-setting as other Wisconsin utilities plan for data centers, said Bryan Rogers, environmental justice director for the Milwaukee community organization Walnut Way Conservation Corp.
“As goes We Energies,” Rogers said, “so goes the rest of the state.”
We Energies’ proposal — first filed last spring — would let data centers choose between two options for paying for new generation infrastructure to ensure the utility has enough capacity to meet grid operator requirements that the added electricity demand doesn’t interfere with reliability.
In both cases, the utility will acquire that capacity through “bespoke resources” built specifically for the data center. The computing facilities technically would not get their energy directly from these power plants or renewables but rather from We Energies at market prices.
Under the first option, called “full benefits,” data centers would pay the full price of constructing, maintaining, and operating the new generation, and would cover the profit guaranteed to We Energies. The data centers would also get revenue from the sale of the electricity on the market as well as from renewable energy credits for solar and wind arrays; renewable energy credits are basically certificates that can be sold to other entities looking to meet sustainability goals.
The second option, called “capacity only,” would have data centers paying 75% of the cost of building the generation. Other customers would pick up the tab for the remaining 25% of the construction and pay for fuel and other costs. In this case, both data centers and other customers would pay for the profit guaranteed to We Energies as part of the project, though the data centers would pay a different — and possibly lower — rate than other customers.
Developers of both data centers being built in We Energies’ territory support the utility’s proposal, saying in testimony that it will help them get online faster and sufficiently protect other customers from unfair costs.
Consumer and environmental advocacy groups, however, are pushing back on the capacity-only option, arguing that it is unfair to make regular customers pay a quarter of the price for building new generation that might not have been necessary without data centers in the picture.
“Nobody asked for this,” said Rogers of Walnut Way. The Sierra Club told regulators to scrap the capacity-only option. The advocacy group Clean Wisconsin similarly opposes that option, as noted in testimony to regulators.
But We Energies says everyone will benefit from building more power sources.
“These capacity-only plants will serve all of our customers, especially on the hottest and coldest days of the year,” We Energies spokesperson Brendan Conway wrote in an email. “We expect that customers will receive benefits from these plants that exceed the costs that are proposed to be allocated to them.”
We Energies has offered no proof of this promise, according to testimony filed by the Wisconsin Industrial Energy Group, which represents factories and other large operations. The trade association’s energy adviser, Jeffry Pollock, told regulators that the utility’s own modeling of the capacity-only approach showed scenarios in which the costs borne by customers outweigh the benefits to them.
Clean energy is another sticking point. Clean Wisconsin and the Environmental Law and Policy Center want the utility’s plan to more explicitly encourage data centers to meet capacity requirements in part through their own on-site renewables, and to participate in demand-response programs. Customers enrolled in such programs agree to dial down energy use during moments of peak demand, reducing the need for as many new power plants.
“It’s really important to make sure that this tariff contemplates as much clean energy and avoids using as much energy as possible, so we can avoid that incremental fossil fuel build-out that would otherwise potentially be needed to meet this demand,” said Clean Wisconsin staff attorney Brett Korte.
And advocates want the utility to include smaller data centers in its proposal, which in its current form would apply only to data centers requiring 500 megawatts of power or more.
We Energies’ response to stakeholder testimony is due on Jan. 28, and the utility and regulators will also consider public comments that are being submitted. After that, the regulatory commission may hold hearings, and advocates can file additional briefs. Eventually, the utility will reach an agreement with commissioners on how to charge data centers.
Looming large over this debate is the mounting concern that the artificial-intelligence boom is a bubble. If that bubble pops, it could mean far less power demand from data centers than utilities currently expect.
In November, We Energies announced plans to build almost 3 gigawatts of natural gas plants, renewables, and battery storage. Conway said much of this new construction will be paid for by data centers as their bespoke resources.
But some worry that utility customers could be left paying too much for these investments if data centers don’t materialize or don’t use as much energy as predicted. Wisconsin consumers are already on the hook for almost $1 billion for “stranded assets,” mostly expensive coal plants that closed earlier than originally planned, as Wisconsin Watch recently tabulated.
“The reason we bring up the worst-case scenario is it’s not just theoretical,” said Tom Content, executive director of the Citizens Utility Board of Wisconsin, the state’s primary consumer advocacy organization. “There’s been so many headlines about the AI bubble. Will business plans change? Will new AI chips require data centers to use a lot less energy?”
We Energies’ proposal has data centers paying promised costs even if they go out of business or otherwise prematurely curtail their demand. But developers do not have to put up collateral for this purpose if they have a positive credit rating. That means if such data center companies went bankrupt or otherwise couldn’t meet their financial obligations, utility customers may end up paying the bill.
Steven Kihm, the Citizens Utility Board’s regulatory strategist and chief economist, gave examples of companies that had stellar credit until they didn’t, in testimony to regulators. The company that made BlackBerry handheld devices saw its stock skyrocket in the mid-2000s, only to lose most of its value with the rise of smartphones, he noted. Energy company Enron, meanwhile, had a top credit rating until a month before its 2001 collapse, Kihm warned. He advised regulators that data center developers should have to put up adequate collateral regardless of their credit rating.
The Wisconsin Industrial Energy Group echoed concerns about risk if data centers struggle financially.
“The unprecedented growth in capital spending will subject [We Energies] to elevated financial and credit risks,” Pollock told regulators. “Customers will ultimately provide the financial backstop if [the utility] is unable to fully enforce the terms” of its tariff.
Jeremy Fisher, Sierra Club’s principal adviser on climate and energy, equated the risk to co-signing “a loan on a mansion next door, with just the vague assurance that the neighbors will almost certainly be able to cover their loan.”
Rye Development secured a federal license to build a massive new pumped hydro energy storage facility in Washington state. The company could become the first to construct this type of grid megaproject in the U.S. since 1995.
Long before lithium-ion batteries reshaped the power sector, utilities stored electricity by pumping water uphill when energy was abundant and later letting it descend, turning turbines to generate power when needed. This technique depends on gravity and heavy construction, and the U.S. pumped hydro fleet got built when utilities could unilaterally invest in long-term assets. In the country’s modern, largely deregulated, and rapidly changing power markets, nobody has pulled off the expensive and time-consuming feat.
Until now — potentially. On Thursday, Rye secured a license from the Federal Energy Regulatory Commission to build and operate a planned pumped storage project just north of the Columbia River Gorge, near the town of Goldendale (population 3,500). It’s the final regulatory step, meaning that Rye can now finalize plans and begin building.
“With electricity demand and energy costs on the rise, this type of pumped storage project represents a huge step forward,” said Erik Steimle, director of development at Rye. He added, “It’s a fully domestic source of energy storage: The major components are concrete, steel, and labor.”
That effort joins two others Rye is working on, which Steimle said could start construction sooner: Swan Lake in Oregon and Lewis Ridge in Kentucky. So far, though, none have broken ground.
At Goldendale, Rye plans to excavate two 60-acre reservoirs separated by 2,000 feet of vertical gain. The company will pipe in water from the nearby Columbia River, then circulate the water up and down to store and discharge power.
This will have a nameplate capacity of 1.2 gigawatts, bigger than any battery storage installation thus far. But pumped storage really shines in how long it can discharge power for — in this case, 12 hours. The cost of building a bigger reservoir scales much more favorably than stacking more batteries does to achieve the extended storage.
The project is a bet on increased demand for long-duration storage as intermittent renewable production surges. The Pacific Northwest has built ample solar and wind generation but has struggled to expand its transmission network, which produces congestion on the wires. So a major storage plant like Goldendale could help: charging up when solar or wind floods the network and then discharging back when demand is high.
The project will typically pump water for 12 to 16 hours a day and generate eight hours a day, but it could push that to a maximum of 12 hours, according to the license document.
Individual power plants seldom need to petition FERC for permission, but Goldendale fell under that body’s jurisdiction because it will connect with federal land and pump water from a navigable waterway. Notably, the new reservoirs will not even touch the Columbia, drastically limiting environmental impacts, compared with those from America’s earlier dam-building spree.
The layout covers about 680 acres, largely private land that used to house a decommissioned aluminum smelter, but it connects to transmission infrastructure overseen by the federal Bonneville Power Administration. Up on a ridge, the high reservoir will be nestled among a series of wind turbines. Between that power plant and the smelter, Rye won’t need to build any new access roads, Steimle said.
The approval stipulates certain environmental mitigations: Rye has to schedule its filling of the reservoirs to avoid altering the river flow during salmon smolt migration, for instance; plant native vegetation on disturbed land; and purchase 277 acres elsewhere to dedicate to golden eagles’ nesting and foraging.
With federal permission secured, Rye now needs to lock down customer contracts (much like another capital-intensive long-duration storage project, Hydrostor’s recently approved compressed-air effort in California). This type of infrastructure is too costly to build without a guarantee of revenue. But Rye needed to win its license before it could finalize contracts with customers, Steimle noted. The project can serve utilities in the Pacific Northwest as well as in California, where state regulators have mandated that power providers buy long-duration storage to balance a massive supply of solar generation.
Rye has already secured a financing partner for Goldendale: Danish firm Copenhagen Infrastructure Partners, which also bought Rye’s Swan Lake project, back in 2020. Copenhagen Infrastructure Partners will supply the estimated $2 billion to $3 billion needed to build Goldendale once Rye finds buyers for the clean power.
Now, Rye will finalize construction planning alongside its commercial efforts. The FERC license stipulates that construction must commence within 24 months, so the countdown is on.
Even Rye’s successful licensing journey underscores the challenges of leaning on pumped hydro to support the transition to clean energy. The company filed for its license in June 2020. It took five and a half years to get the green light, and it will take up to two years to finalize plans and then four or five more to actually finish building the thing.
That ponderous pace explains why such a large-scale plant hasn’t been built in the U.S. since the Rocky Mountain Hydroelectric Plant came online in Georgia in 1995. A few other companies have tried, like Absaroka Energy, which is developing the Gordon Butte plant in Montana. Globally, a new pumped hydro site opened in Switzerland in 2022; it took just 14 years.
To put it simply, pumped hydro construction isn’t a nimble response to a rapidly changing electricity mix. Batteries, on the other hand, are — they’re mass-produced in factories and can be installed swiftly in prepackaged containers.
But pumped hydro works extremely well when built. It has a far longer duration than the typical four-hour lithium-ion battery. These facilities also last far longer than lithium-ion cells, which degrade with use. The Goldendale license covers 40 years of operation, but the system is designed to last 100, Steimle said; the owner of the Rocky Mountain plant sought a license extension for another 40 to 50 years.
“Pumped hydro is a battery you can cycle over and over again with little to no degradation over a very long period of time,” he said.
And it clearly works at a massive scale: The U.S. has more than 22 gigawatts already running.
As Paul Denholm, a clean grid modeler at the institution formerly known as the National Renewable Energy Laboratory, told Canary Media previously, “Utilities with pumped-storage plants love them — they’re awesome.”
Since emerging as the world’s No. 2 producer of steel eight years ago, India has ramped up its exports to Europe. By some estimates, upwards of 60% of the country’s steel exports now head to the European Union.
But India’s steelmakers are poised for what one prominent New Delhi–based business magazine recently referred to as a “wake-up call.”
The EU’s world-first carbon tariff — known as the carbon border adjustment mechanism — took effect this month, forcing companies in the bloc to pay levies on certain imports based on how much planet-warming pollution was emitted during their manufacturing. That means metal from Indian steelmakers — which rely heavily on coal — will come in at a much higher price in the EU.
“Europe is the elephant in the room. It’s a pretty big deal,” said Kaushik Deb, executive director of the India team at the University of Chicago’s Energy Policy Institute. “It makes it a lot more urgent for India to start thinking about green steel.”
Coal dominates the steelmaking process in much of the world, and especially in India. The traditional method for producing the metal relies on a coal-fired blast furnace to refine iron ore into iron, which is then forged into steel in a basic oxygen furnace. That two-step process accounts for 43% of India’s steel output, according to a June report from Johns Hopkins University’s Net Zero Industrial Policy Lab.
The rest of the nation’s steel is produced in electric arc furnaces or induction furnaces, alternatives to basic oxygen furnaces that melt iron into steel using electricity. But even that equipment depends on iron refined using coal. The fossil fuel also generates upwards of 75% of the power on India’s grid, meaning that ostensibly cleaner methods that use electricity still generate plenty of emissions.
Some steelmakers in India have begun to build out the infrastructure for direct reduced iron, a cleaner method of making iron than relying on coal-burning blast furnaces. But in contrast to American or European DRI facilities, which typically use natural gas or hydrogen, Indian DRI plants often use coal as the input.
The Indian government has started looking to change the trajectory of its coal use. The fossil fuel is making up less and less of the country’s power mix as India installs record amounts of solar panels and wind turbines and embarks on plans to build new nuclear power stations.
In September 2024, India’s Ministry of Steel — the only cabinet-level agency in any major country dedicated just to steel — issued a 420-page report outlining the potential pathways to greening the industry. The report calls for studies into different approaches to slash emissions from steelmaking, including swapping the coal used in DRI for green hydrogen made with renewables and equipping fossil-fueled facilities with carbon-capture equipment. It also proposes studying ways to retrain workers on greener technologies. But the report acknowledges that financing remains a challenge.
“I don’t see the timeline for this happening optimistically,” said Shreyas Shende, the senior research associate at the Net Zero Industrial Policy Lab who co-authored last summer’s report. “The issue is the pricing. Green hydrogen has no cost competitiveness. The government is running a few pilot projects, but we have to see if it’s scalable.”
Some private companies in India have started their own decarbonization pilot projects. JSW Steel announced plans in 2022 to spend $1 billion on green steel by 2030, and later expanded the vision via a partnership with the South Korean steelmaker Posco to develop a new green-steel mill.
That same year, industrial behemoth Adani inked its own deal with Posco to develop a $5 billion green-steel facility in the western state of Gujarat.
In 2024, Tata Steel entered the green-steel market with plans for a low-carbon mill in the United Kingdom. At the World Economic Forum in Davos, Switzerland, last week, the giant announced another $1.2 billion investment in a green-steel plant in the eastern state of Jharkhand.
Acting on its own, however, the “industry will take a long time to catch up,” Shende said.
“The most important development recently is that the government has talked about putting together a big plan,” he said. “We haven’t seen what that plan looks like. But if and when it does come out, that would have potentially the greatest impact on anything India will do.”
In the meantime, India’s steelmakers — which directly employ 2.5 million workers and generate as much as 2% of the country’s gross domestic product — face increased competition. Last August, a Chinese steelmaker scheduled the first shipment of green steel to Italy, an effort to establish a supply chain between the People’s Republic and the EU ahead of the carbon tariff taking effect. In November, industry groups representing European and Chinese steel producers and buyers came together to work on a uniform set of standards for determining whether steel is, in fact, green.
“The Chinese are much better prepared with green steel than India is, and they will probably gain market share at India’s expense by being more compliant” with the EU’s new carbon tariff, Deb said. “That threat of losing market share is relevant and important for India’s decision-making process. It would be a very hard blow to the Indian steel industry.”
This story was first published by Grist.
One year ago, with one of the first strokes of his presidential Sharpie, President Donald Trump signed an executive order declaring a “national energy emergency,” making good on a campaign promise to “drill, baby, drill.” It was the first of many such orders, signaling that the championing of fossil fuels would be a cornerstone of the new administration: A subsequent order pledged to revitalize America’s waning coal industry, eliminate subsidies for electric vehicles approved by Congress under former President Joe Biden, and loosen regulations for domestic producers of fossil fuels. Yet another executive order withdrew the U.S. from the Paris Agreement, the nearly unanimously adopted international treaty that coordinates the global fight against climate change. He resumed liquefied natural gas permitting paused by his predecessor and reopened United States coastlines to drilling.
In the days following his inauguration, Trump killed a climate jobs training program, closed off millions of acres of federal water designated for offshore wind development, and scrubbed mentions of climate change from some federal agency websites. To many observers, it looked like the most comprehensive reorientation of the executive branch’s environmental and climate priorities in American history.
On paper, it certainly appears as though Trump has continued to make good on these early promises. He pushed Congress to pass the so-called Big Beautiful Bill, which phases out an extensive set of tax credits — for wind and solar energy, electric vehicles, and other decarbonization tools — that were responsible for much of the progress the U.S. was expected to make toward its Paris Agreement commitments. (That move has already led some companies to abandon new clean energy projects.) Trump’s attacks on the nation’s offshore wind industry, which he recently called “so pathetic and so bad,” have been unrelenting, culminating in a blanket ban on offshore leases last month. A few weeks ago, he upped the ante on his earlier withdrawal from the Paris Agreement by severing ties with the United Nations framework that facilitates international cooperation on matters of climate change, environmental health, and resilience — a treaty that was ratified unanimously by the U.S. Senate in 1992.
“It has been an extraordinarily destructive year,” said Rachel Cleetus, climate and energy policy director at the nonprofit Union of Concerned Scientists. It’s not hard to find specific moves that have already done tangible harm to the climate: The EPA, for instance, delayed a requirement that oil and gas operators reduce emissions of methane, an ultra-potent and fast-acting greenhouse gas, for a full year. The Interior Department announced a $625 million investment to “reinvigorate and expand America’s coal industry” and directed a costly Michigan coal plant on the verge of closure to stay open.
However, while these moves have been effective in sowing panic and uncertainty, their long-term effects on the country’s climate policy framework are far from certain. Indeed, only a small fraction of the climate damage threatened by Trump is truly permanent, experts told Grist. That’s not only because many of Trump’s moves may ultimately be ruled illegal — federal judges in Rhode Island, New York, and Virginia, for instance, allowed offshore wind farms in those states to resume construction just last week — but also because executive actions can be reversed by a future president. And the president has not shown much interest in passing energy- or climate-related legislation, a far more durable form of policymaking than executive decree. Despite claims to the contrary, Trump has signed fewer bills than any president since Dwight D. Eisenhower.
“He is not changing law,” said Elaine Kamarck, who worked in the Clinton administration and is the founding director of the Brookings Institution’s Center for Effective Public Management. “He is changing practice.”
Even something as unprecedented as the EPA’s moves to relinquish its own authority to regulate the emissions that affect human health — a responsibility that is a core tenet part of the agency’s mission and is therefore widely regarded as unlikely to hold up in court — could be unraveled by a future administration even if it’s ruled to be legal, though that process would take years.
“You can’t make up for the lost time, the increased emissions, and the extent that new areas are opened up for [fossil fuel] exploration,” said Michael Burger, executive director of the Sabin Center for Climate Change Law at Columbia University. “But from a regulatory perspective, what this administration is doing to EPA and the other agencies are all executive actions that can be undone in the same way they were done.”
The major exception is the GOP’s One Big Beautiful Bill Act, or OBBBA. If a future administration wants to restore expansive tax credits for wind and solar energy, that president will have to push Congress to pass new climate legislation. But the climate-relevant portions of OBBBA are noteworthy for being subtractive rather than additive — and are perhaps more accurately viewed as a representation of Trump’s quest to refute Biden’s legacy than as a desire to radically alter U.S. energy law. Indeed, the new law left in place the tax credits for other sources of carbon-free energy, including nuclear and geothermal — something that more moderate Republicans who do not share the president’s dismissal of climate science have been quick to note.
“We like to point out that the baseload clean energy credits were maintained,” said Luke Bolar, head of external affairs and communications at ClearPath, a think tank that develops conservative climate policies. Sean Casten, a Democratic U.S. representative from Illinois, said that the goal of the Biden-era climate legislation — ensuring that U.S. clean energy can be built in a cost-competitive way — has largely been achieved even if specific parts of the law have been repealed.
“Every single zero-carbon power source … is still cheaper on the margin than a fuel energy source,” he said.
The relative fragility of Trump’s assault on bedrock environmental and climate laws could be a product of the president’s prioritization of political dominance over lasting change, said Josh Freed, senior vice president for climate and energy at the think tank Third Way.
For example, the administration has taken steps to shield the American coal industry from the punishing blows of competition, environmental regulation, and the rising costs of mining. Trump has signed an executive order aimed at “reinvigorating America’s beautiful clean coal industry,” granted coal-fired power plants temporary exemptions from emissions limits, and ended a federal moratorium on coal leasing. But those interventions will do little in the long run to reverse a decline driven mainly by economics: The nation’s aging coal plants are becoming increasingly expensive to run while natural gas and solar energy have only gotten cheaper. And they certainly don’t help the president’s stated goal of reducing household energy costs.
To attempt to make sense of the president’s crusade to save coal is to assume there is a larger political strategy at play — which may not be the case, Freed said.
“There’s no reason to bring back coal other than to show that the administration can bring back coal,” he said. “It’s not like there’s this huge lobbying effort or donor base that will be of significant benefit to MAGA or Republicans if they do it.”
A style of governance motivated by political dominance is a good way to make headlines, but it’s not a particularly effective way to build a lasting legacy. Trump’s efforts to buoy coal may help the industry in the short term, but experts are broadly in agreement that coal can’t be “saved” without sustained support from the federal government. And an industry that can survive only with a coal-friendly Republican in the Oval Office isn’t exactly thriving.
“When you have to get the government to step in to put its thumb on the scale in order to help your industry,” Sean Feaster, an energy analyst at the Institute for Energy Economics and Financial Analysis, told my colleagues earlier this week, “it’s a sign that you’re not particularly competitive, right?”
For decades now, the pendulum of U.S. climate policy has swung left and right, reflecting the priorities of the sitting president. Trump’s climate blitzkrieg may be the starkest example yet of the benefits and drawbacks of that model. But despite his best efforts to stand out from the pack, the president’s first year back in office fits a well-worn pattern. As a result, his victories may not last much longer than his presidency.
For nearly two years, Century Aluminum has been searching for a site to put a giant new U.S. smelter — a decision that largely hinged on where it could strike a deal with utilities to access cheap, reliable electricity.
On Monday, the Chicago-based manufacturer finally unveiled its plans. Rather than build its own power-hungry facility, Century is partnering with Emirates Global Aluminium to jointly develop a smelter near Tulsa, Oklahoma, the companies announced. The facility will be America’s first new aluminum smelter in nearly half a century if completed as planned by the end of the decade.
“Together we will make a huge contribution to rebuilding American aluminum production for the 21st century,” Abdulnasser Bin Kalban, CEO of the Dubai–based EGA, said in a statement.
Century had previously identified northeastern Kentucky as its preferred location for a $5 billion smelter, though the company was also evaluating sites in the Ohio and Mississippi river basins. In 2024, the Biden-era Department of Energy selected Century to receive up to $500 million to build a “green” smelter powered by 100% renewable or nuclear energy.
Century didn’t immediately return Canary Media’s questions about the status of the federal award or how energy issues factored into its decision to join forces with EGA.
But on Tuesday, Century CEO Jesse Gary told Fox Business, “That grant is going to underlie the total investment … to help build this new smelter.”
Aluminum production contributes about 2% of greenhouse gas emissions globally every year, and the majority of those emissions come from generating high volumes of electricity — often derived from fossil fuels — to power smelters.
Emirates Global Aluminium first proposed building its own Oklahoma smelter last May. Up until this week, EGA and Century seemed to be racing each other to fire up their new facilities. The fact that the companies teamed up reflects how difficult it is for manufacturers to secure power at the volumes and prices they need, not only in the United States but globally — a challenge that’s getting even harder with the competition from AI data centers.
Building a smelter “is very expensive and very complicated, so I take it as good news,” said Joe Quinn, who leads the Center for Strategic Industrial Materials for SAFE, which advocates for policies to enhance U.S. energy security.
“There was a scenario where both could have failed,” he added. “But now they’re getting together, and I think that strengthens the likelihood of a new smelter being built in the United States.” He said the news was “a little surprising, but then again not that surprising” given the challenges of opening a multibillion-dollar greenfield smelter.
Under this new agreement, EGA will own 60% of the joint venture and Century will own the remaining 40%. The Tulsa-area facility is expected to produce 750,000 metric tons of aluminum per year, an amount that is 25% larger than previously envisioned — and more than double the current U.S. production of primary aluminum.
A facility that massive will require over 11 terawatt-hours of power, or enough electricity annually to power the city of Boston or Nashville, according to an Aluminum Association report.
America’s output of the versatile metal has sharply declined in recent decades, in large part owing to rising industrial electricity rates. Today, the country operates just four smelters — down from 33 in 1980 — and it imports about 85% of all the aluminum it needs each year. At the same time, the U.S. is using more aluminum in solar panels, power cables, infrastructure, and electronics. By 2035, U.S. demand for primary aluminum is expected to rise by as much as 40%, the advocacy group Industrious Labs said in a report last year.
Annie Sartor, Industrious Labs’ senior campaigns director, said that “two smelters would have been ideal” for boosting U.S. aluminum production. “One is better than none, but neither can succeed without affordable, clean power,” she said in a statement.
Construction on the Oklahoma smelter is set to start by the end of this year, the companies said. Negotiations are still underway with the Public Service Company of Oklahoma, which is a subsidiary of utility giant AEP, and the state of Oklahoma to secure a competitive, long-term power contract.
Last year, EGA signed a nonbinding agreement to build its proposed smelter with the office of Republican Gov. J. Kevin Stitt, a deal that includes over $275 million in incentives, including discounts for power. Oklahoma’s “energy abundance” was a key factor in selecting the state for the new aluminum smelter, Simon Buerk, EGA’s senior vice president for corporate affairs, previously told Canary Media.
More than 40% of Oklahoma’s annual electricity generation comes from wind turbines spinning on open prairies, while about half the state’s generation comes from fossil-gas power plants. Last summer, the Public Service Company acquired an existing 795-megawatt gas plant south of Tulsa to meet the rising energy needs of its customers, potentially including EGA.
Buerk said last year that the Oklahoma smelter’s annual power mix “will be based on EGA’s decarbonisation objectives, market dynamics, and market demand for low-carbon aluminum.” He confirmed that Monday’s announcement doesn’t change any of the options being discussed in ongoing negotiations with the utility. That includes a potential tariff structure that gives the smelter dedicated long-term access to a proportion of renewable energy.
The news that Century Aluminum is investing in Oklahoma comes as a major letdown for some environmental and labor groups in Kentucky, who had advocated for bringing the project to their state. Century already owns two aging smelters in western Kentucky, and the new facility was supposed to create thousands of construction jobs and more than 1,000 permanent positions — jobs that will now go to Oklahoma.
“This is a disappointing loss for Kentucky, but it should serve as a wake-up call,” Lane Boldman, executive director at Kentucky Conservation Committee, said in a statement. “For Kentucky to remain an energy leader and meet the needs of industries looking for reliable and affordable power, it must modernize its energy infrastructure more quickly, such as grid modernization, energy storage, and diversifying with renewables.”
An update was made on Jan. 27, 2026 to include a response from EGA and comments from Century CEO Jesse Gary.
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