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Northwest Indiana residents say Nippon Steel’s acquisition of U.S. Steel could bring jobs and growth. But they’re still waiting on Nippon to deliver.
A year ago this month, Japan’s Nippon Steel acquired U.S. Steel, promising to plow $14 billion into America’s legendary but long-declining steel industry.
The hard-fought deal was controversial and highly politicized. But for residents in historic steel communities, like those in northwest Indiana, the foreign investment has come to represent a major opportunity.
Steel mills in the region make the metal that’s used to build the nation’s cars, skyscrapers, appliances, and naval ships. For over a century, the hulking facilities have driven the region’s economy and employed many thousands of workers — while also spewing toxins and planet-warming gases from their coal-fueled furnaces. Today, the jobs are declining even as the pollution continues.
The U.S. Steel buyout and other developments could provide funding needed to not only clean up but also reinvigorate Indiana’s mills, experts say.
Here are four takeaways of where that transformation stands a year into the acquisition.
When Nippon Steel bought U.S. Steel in June 2025, the Japanese firm pledged to build new metalmaking capacity and to modernize the Pittsburgh company’s aging infrastructure, including Gary Works in Indiana, which has been running since 1908.
Nippon Steel isn’t the only foreign manufacturer investing in the U.S. The Korean steelmaker Posco is also in talks to partner with America’s second-largest steel company, Cleveland-Cliffs, which owns the other two mills in northwest Indiana: Burns Harbor Works and Indiana Harbor Works. Posco is separately investing in the nearly $6 billion lower-carbon steel plant that Korean industrial giant Hyundai is building in south Louisiana.
The Trump administration’s high tariffs on steel imports are a key reason why the conglomerates are expanding their presence stateside.
But they’re also looking to capitalize on America’s rising demand for high-value steel that meets the exacting standards for vehicles and electrical equipment, and which represents a more attractive market than the commodity steel that’s flowing out of China.
“The U.S. market is now becoming a proxy battle between three of Asia’s largest steelmakers,” said Roger Smith, a Japan-based expert at the nonprofit advocacy group SteelWatch. He spoke during an April panel that Canary Media convened at the Society of Environmental Journalists’ annual conference, held this year in Chicago.
“This is unprecedented,” Smith added. “The future of the industry may well be decided in Seoul and Tokyo.”
Northwest Indiana’s steel mills certainly need the infusion of funding.
The region’s industry has gradually dwindled over decades because of rising overseas competition, increased automation, and the growth of steel-recycling mills in other parts of the country. At its peak in the 1970s, some 65,000 people worked in the state’s mills. Today, it’s closer to 9,000 people, and the workforce is expected to keep shrinking without further investment, according to an April report by Indiana University.
U.S. Steel and Cleveland-Cliffs have both seen their revenues decline in recent years, and much of the companies’ coal-based capacity is in need of expensive repairs and upgrades.
For activists like Jack Weinberg, the foreign funding represents a chance to rebuild the local industry using modern, lower-carbon methods.
Weinberg is a former steelworker and the green-steel lead for Gary Advocates for Responsible Development in Indiana. He said during the Chicago panel that transitioning away from coal is crucial not only for improving people’s health and addressing climate change — but also for ensuring Indiana’s steel industry can continue operating in a rapidly transforming market.
Today, northwest Indiana is the country’s top producer of high-performance flat-rolled steel.
The region’s “integrated” mills operate in two stages: first, iron ore is heated in coal-fueled blast furnaces to make virgin iron, then the molten metal is processed in a separate furnace to produce steel. The ironmaking step is the main driver of carbon dioxide emissions across the global industry, which accounts for about 9 percent of total annual CO2 emissions.
By making virgin iron, the Gary, Burns Harbor, and Indiana Harbor mills have long held an edge over America’s 150-plus mills that melt down recycled steel scrap in giant electric arc furnaces. While steel recycling is comparatively less carbon-intensive, those facilities’ products haven’t traditionally met the performance standards required by the auto, military, and certain other industries.
Yet the long-standing lines between integrated and steel-recycling mills are starting to blur, in ways that don’t necessarily bode well for northwest Indiana, Weinberg said.
Consider, for example, U.S. Steel’s Big River Steel Works in Arkansas. The sprawling site includes four electric arc furnaces, which use a mix of scrap metal and virgin iron to produce auto-grade steel. For now, that iron comes from Indiana’s Gary Works plant. But in late April, U.S. Steel said it was building a $1.9 billion plant to make iron on-site at Big River Steel, an investment made possible by parent company Nippon Steel.
The Arkansas facility will use natural gas to convert iron ore into iron pellets through the “direct reduction” process. Gas-fueled direct reduction plants can emit about half the CO2 emissions of coal-based blast furnaces. However, companies could produce nearly zero-emission iron if they instead used green hydrogen — which is made with renewable electricity and water — though the concept has been slow to scale up globally.
In Louisiana, Hyundai’s steel mill will include a direct reduction plant that feeds iron into two electric arc furnaces, similar to the setup in traditional integrated mills. The Korean manufacturer initially plans to use natural gas to make iron for its automotive steel but has said it intends to, at some point down the road, switch to green hydrogen.
Weinberg and other northwest Indiana residents hope that the Asian steelmakers will similarly invest in modernizing the region’s aging furnaces. Otherwise, the mills risk becoming uncompetitive and closing down by the 2040s, Gary Advocates for Responsible Development said in a January report. (U.S. Steel, for its part, criticized the group’s findings in statements to the Chicago Tribune.)
“People put up with all the health problems associated with coal-based blast furnaces because they needed the steel and didn’t have any alternative,” Weinberg said. “How long is the country going to put up with this when a cleaner way is available to do the same thing?”
Lisa Vallee, who lives in Whiting near the Indiana Harbor steel mill, said during the panel that shifting to cleaner steel production would be “life-changing” for the region.
Replacing coal-based blast furnaces would curb air and water pollution, while building renewable energy projects, producing green hydrogen, and modernizing steel plants could deliver an economic boost, said Vallee, who is an organizing director for the grassroots group Just Transition Northwest Indiana.
“We have the [steel] facilities, we have a workforce, we have the lake — we have everything we need in northwestern Indiana to create green steel,” she said. “It’s just the investment we need to actually make it happen.”
The manufacturer is building a $6 billion facility that will use cleaner technology — and potentially green hydrogen. But residents question whether they will benefit.
On a drizzly March day last year at the White House, President Donald J. Trump stood behind a podium to make a “beautiful announcement.” Hyundai, the Korean industrial giant, was investing nearly $6 billion in a new steel plant in Louisiana, which would supply domestic metal to the company’s auto plants in Alabama and Georgia.
Hyundai executives flanked Trump as he spoke, as did top Republican policymakers and Louisiana’s governor, Jeff Landry, who stood out among the sea of navy suits in his cornflower-blue attire. Trump praised his own administration’s tariff policy for driving Hyundai’s investment in U.S. manufacturing, and Hyundai officials touted the jobs they’ll bring to the Bayou State.
But one important detail went unmentioned: The new plant may be the lowest-carbon iron and steel mill the United States has ever built.
Traditional steelmaking is highly polluting, responsible for up to 9% of the world’s greenhouse gas emissions. Unlike the hulking furnaces that launched America’s steel industry in the late 19th century — some of which are still cranking across the Midwest — the Louisiana facility won’t rely on coal to produce the sturdy metal.
Last summer, the company indicated its steel mill would use hydrogen — a carbon-free fuel that can be made cleanly from renewable electricity and water. The project would become a “catalyst for the hydrogen ecosystem” in Louisiana, executives told state leaders, while helping Hyundai meet the growing global demand for sustainably produced steel.
This was good news for anyone who cares about climate, coming at a moment when other U.S. efforts to decarbonize the steel industry had stalled in the face of economic headwinds and the Trump administration’s antipathy toward climate policy. The companies SSAB and Cleveland-Cliffs were each slated to receive $500 million in federal funding for hydrogen-based steelmaking under the Biden administration, but they later abandoned those plans.
A green-hydrogen steel mill would be “a chance to change not just the industrial landscape of Louisiana, in terms of what types of industries are here, but also to advance the broader clean energy transition in the state,” said Kelvin Wells Jr., an industrial organizer with Sierra Club’s Delta Chapter who lives in Baton Rouge, the state capital.
But whether Hyundai will fulfill its hydrogen ambitions remains an open question.
In permit fillings, the company stated the steel mill will use natural gas when it starts operating in 2029, and Hyundai confirmed this plan to Canary Media. The firm also said it will capture and store the carbon dioxide emissions the plant produces from the get-go. The combined approach can slash the carbon footprint of coal-based steelmaking by as much as two-thirds — but it’s still more polluting than using hydrogen from renewables, and is sure to face opposition from carbon-capture’s critics.
Asked when the company will transition to using green hydrogen, a representative said, “It is difficult to pinpoint when hydrogen will become economically viable.”
Meanwhile, residents in Ascension Parish, where the facility is being built, have their own questions about the project. Their community is already stacked with petrochemical plants and oil refineries that have turned the rural region between Baton Rouge and New Orleans into “Cancer Alley.” They hope the steel mill will offer an alternative to those dirty facilities, and they want assurances that the steelmaker will deliver on its promises. So far, locals say the company hasn’t responded to their requests for talks.
As Hyundai begins transforming the grounds of a former sugarcane plantation into an industrial site, community members and climate advocates are watching the project closely to see what happens next.
That’s why he joined the grassroots group Good Neighbors Louisiana. The coalition is pushing Hyundai to crystallize its plans — for curbing pollution, using green hydrogen, and protecting workers — in a legally binding “community benefits agreement,” and it is calling on the state to conduct an environmental justice analysis. Not long after my visit, the group claimed a win: Hyundai said it would switch nine gas-fired heaters in parts of its operation to cleaner electrified equipment; the change will “reduce emissions of pollutants,” the company explained by email.
“We can’t stop people coming in — we don’t have the might. So you have to have a plan B,” Price told me inside the small, hushed library. “If they’re going to come in, then we want them to make sound commitments to us. We want the best that we can get.”
Donaldsonville is surrounded by emerald fields of sugarcane and rice paddies dotted with orange crawfish traps. But signs of its modern industrial identity are impossible to miss. Driving west over the Sunshine Bridge earlier that day, I saw silver spires and grayish plumes rising from CF Industries’ ammonia-production plant. It’s the biggest fertilizer factory in the world — and also Louisiana’s largest source of planet-warming emissions and toxic air and water pollution. The imposing complex sits within sight of a primary school and the local Walmart.
As I headed toward the rural village of Modeste, the factory shrank into the distance, replaced by farmland owned by the descendants of slaves and sharecroppers. Hyundai, CF Industries, and other firms are collectively planning to develop a 17,000-acre industrial hub, called the RiverPlex MegaPark, in this area.
I pulled over my rental car — a Hyundai Kona, as it happened — when I came across the temporary sign for Hyundai America. Stepping into the broiling sun, I took in the preliminary site work: leveled ground, piles of dirt, fleets of excavators and dump trucks. At full tilt, Hyundai’s steel mill is expected to churn out 2.7 million metric tons of metal per year on its 1,700-acre property. Posco, another major Korean steelmaker, is set to invest $582 million and take a 20% stake in the operation.
Details about Hyundai’s work and the bigger industrial park are hard to come by, especially for the Modeste residents who fear being displaced.
At least 10 elected leaders in Ascension have signed nondisclosure agreements with Louisiana Economic Development, a state agency. The practice reportedly allowed state officials to privately negotiate a sweeping $2.6 billion incentive deal for Hyundai’s project. The level of secrecy is becoming commonplace in Gov. Landry’s Louisiana, though local environmental groups are suing to stop it. The state agency defended its use of nondisclosure agreements, calling them a “standard part of economic development projects” across the country.
“By engaging local elected officials early while protecting sensitive business information during negotiations, Louisiana is able to compete for transformational projects that create opportunity, grow wages, and strengthen communities across the state,” a spokesperson for Louisiana Economic Development said by email.
Ashley Gaignard, a Donaldsonville resident and president of Rural Roots Louisiana, questioned why project details have been kept secret if they’re in the public’s best interest. “I would love to see my community thrive,” she said. “I just don’t want to do it at the cost of risking our water, our air, our lives.”
Deletrick Dickerson, who lives in the parish, said that while he’s wary of the larger RiverPlex expansion, Hyundai’s steel mill in particular could have a “phenomenal” impact if it employs people within the predominantly Black, economically distressed towns that trace the western bank of the Mississippi.
Dickerson works at the Atalco alumina refinery in neighboring St. James Parish and is a safety representative for his United Steelworkers local union. He also advocates for the union on other urgent political matters. He and I met after my drive to Modeste near the state Capitol building, in Baton Rouge, where he had spent the previous night rallying against a congressional redistricting bill that would eliminate one of Louisiana’s two majority-Black districts. The measure passed at 4:30 a.m.
The Hyundai project is another kind of fight for communities, he said later that afternoon, warding off fatigue. “We just want everything to be on the up-and-up.”
Hyundai-Posco Louisiana Steel, the U.S.-based subsidiary of Hyundai Steel, addressed the community’s environmental and labor concerns in an email to Canary Media.
The steelmaker is using advanced technologies “to minimize emissions of harmful and toxic substances. The project is designed to comply with all applicable environmental regulations and permit requirements,” a representative said. The company plans to “prioritize hiring local residents to the greatest extent possible. Safety will be our top priority, and HPLS will be prepared and operated with the highest safety standards.”
For all the uncertainty surrounding Hyundai’s hydrogen future, one thing is clear: It won’t be like the aging steel mills that operate from Illinois east to Pennsylvania.
Those facilities consume lots of coal in scorching-hot blast furnaces to turn raw iron ore into iron. The molten metal is then transported into a basic oxygen furnace, which removes impurities to make steel. The mills produce most of the high-performance steel that U.S. auto manufacturers need for car bodies and engine parts. They are also responsible for the vast majority of carbon emissions and toxic air pollution associated with steelmaking.
The Louisiana plant will be the first new U.S. steel mill to combine two alternative furnace technologies into one relatively lower-carbon facility.
To produce the iron, the company will install a direct reduction furnace, which can use natural gas or hydrogen, or a combination of the two. Three such facilities already operate in the United States — all of them fueled by gas — including Nucor’s sprawling operation near the community of Romeville, Louisiana, across the river from where Hyundai’s steel mill is being built. At the Nucor site, an impossibly long conveyor belt travels overhead to move the iron onto river barges that ship the metal to other states.
Hyundai’s project, by contrast, will feed iron directly into two electric arc furnaces. Over 150 of these power-hungry furnaces exist nationwide. But they primarily melt down scrap metal, with some virgin iron, into shiny new steel. Hyundai will mostly supply its own iron for the electric arc furnaces, enabling it to form steel sheets with the right qualities for vehicle production.
Hyundai has been making steel in South Korea since the 1950s. But with the Trump administration’s tariffs raising the cost of importing steel and cars, the manufacturer has opted to boost its U.S. production in both sectors. Building a new coal-fueled blast furnace in the United States makes little economic sense, given the expense of using coal and complying with environmental regulations. And there’s no need to — not when Louisiana can offer plentiful supplies of cheaper natural gas.
Eventually, the company intends to sell its Louisiana-made steel to other automakers in the U.S. and internationally. The global market is increasingly calling for lower-carbon steel, through policies like the European Union’s carbon border tax and because of broader consumer interest. Hyundai itself is facing pressure to decarbonize under South Korea’s carbon-neutrality targets.
“This project is not just about producing steel — it’s about producing a better future,” Hyeongjin Kim of Hyundai Steel told Louisiana leaders last year in Baton Rouge.
In May, Hyundai signed a $650 million supply contract with the Italian company Danieli for the two electric arc furnaces and other key steel-manufacturing equipment. The deal also includes an Energiron direct reduction plant, jointly developed by Danieli and the Italian firm Tenova, which is similar to the one Nucor operates in Louisiana.
“This is state-of-the-art, latest technology,” Andrea Diasparro, Danieli’s group sales director and a member of its executive board, said by phone from his office in Buttrio, Italy.
He added that the equipment is designed to limit energy consumption across Hyundai’s operation. The direct reduction furnace has built-in capabilities to capture carbon dioxide emissions, which Hyundai said it will utilize during its initial operations. The plant is also designed to seamlessly transition from using gas to hydrogen to produce the iron.
“No additional equipment has to be implemented for the plant to be hydrogen-ready, in the case that hydrogen is available at a reasonable price,” he said.
The question of when Hyundai will use green hydrogen, if ever, weighs heavily on Angelle Bradford Rosenberg, a medical scientist who leads the Sierra Club’s Delta Chapter. She met with me, her colleague Wells, and Dickerson — all members of the Good Neighbors Louisiana coalition — at a bar in downtown Baton Rouge the afternoon after the combative redistricting hearing.
“There’s no mechanism in Louisiana for watchdogging that sort of thing,” Bradford Rosenberg said. “We need those commitments from corporations in the beginning, because we cannot trust that it will come later.”
Hyundai outlined its hydrogen ambitions last year during meetings with Louisiana’s Clean Hydrogen Task Force, as part of an 18-month initiative created under former Gov. John Bel Edwards, a Democrat. The group included legislators and industry experts, who made policy recommendations for boosting production of the lower-carbon fuel within the state.
Louisiana makes millions of tons of conventional hydrogen every year for use in the chemicals sector, through a dirty and energy-intensive method that breaks the hydrogen-carbon bond in methane from natural gas.
The industry has plans to clean up by capturing its CO2 emissions and storing them permanently underground — producing so-called blue hydrogen — with a few such projects underway. In meetings, Hyundai gave the impression that it would start by using blue hydrogen in its ironmaking furnace. It would have a convenient source: CF Industries is developing a $4 billion blue ammonia plant next door that could also make hydrogen and bury emissions beneath Ascension Parish.
Whether this is a good idea depends on who you ask. The Sierra Club and local groups like Rural Roots and Louisiana Bucket Brigade — and, increasingly, Republican state policymakers — are vehemently opposed to injecting CO2 into underground wells, given their concerns about public safety risks and potential emission leaks. Critics also don’t like that it prolongs industry’s reliance on fossil fuels, and all the harmful emissions that entails.
On the flip side, the nonprofit Clean Air Task Force generally considers carbon capture and storage, or CCS, to be a “safe, permanent, and essential pathway” to curbing industrial emissions. By including CCS in its initial plans, the Hyundai steel mill could help create the supply chains and infrastructure needed to develop blue hydrogen, eventually driving down the costs for hydrogen made with renewables.
“We really see CCS-enabled hydrogen as a way to jump-start the economy and lead us into electrolytic [green] hydrogen in the future,” Lindsay Cooper Phillips, the senior Gulf Coast policy manager for the Clean Air Task Force, told me over coffee in Baton Rouge. “It’s challenging for someone like Hyundai to just start off there.”
Hyundai has indicated that it could later switch to using green hydrogen, which is made by running electrolyzers — powered by renewable electricity — to split water into hydrogen and oxygen. This is considered the cleanest form of the fuel, because it doesn’t directly emit carbon. It also eliminates the harmful air pollution that comes with burning natural gas, including smog-producing compounds and fine particulates, which can damage people’s hearts and lungs.
A handful of global steelmakers have started using hydrogen in their operations. But the world’s first commercial-scale green steel mills are only just being built, both of them in northern Sweden. SSAB and Stegra are aiming to fire up their respective facilities before the end of the decade, despite significant challenges with project funding and delays.
Globally, the limited supply of green hydrogen and sky-high cost of producing it have stalled progress on green steel — problems exacerbated in the United States by politics. Over the last year and a half, the Trump administration has weakened or paralyzed federal funding for new clean hydrogen projects. Gov. Landry has done little to advance the low-carbon hydrogen efforts started by his predecessor, and the state has barely installed any renewable energy to date.
So it’s perhaps unsurprising, if not deeply disappointing for advocates like Bradford Rosenberg, that Hyundai said it will use natural gas when it fires up its steel mill in 2029.
“The production of green hydrogen has not yet reached the scale, nor cost, necessary for feasible implementation to replace natural gas,” Hyundai said in its December air-pollution permit application to the Louisiana Department of Environmental Quality.
In its filing, the company said it would use green hydrogen when there’s enough supply to meet its demand. But it hasn’t disclosed a timeline for when it plans to shift away from gas. “As hydrogen becomes more viable, we have also considered a phased transition to blue and green hydrogen,” Hyundai-Posco Louisiana Steel said by email.
Experts question whether the company will want to make such carbon-cutting investments after its gas-fueled plant is already up and running.
“Hyundai has the ambition, and we really want to see it put into practice,” Cooper Phillips said.
As Hyundai sorts out what will happen inside its steel mill, the world outside is preparing for the plant’s arrival.
Earlier this year, the River Parishes Community College broke ground in Donaldsonville on the Hyundai Training Center, which will offer a two-year program to prepare people for jobs in the steel industry. Landry and Bo-ryong Lee, Hyundai Steel’s president and CEO, were among those tossing shovels of dirt at the February ceremony. Korean investors have purchased hotels and apartments in downtown Donaldsonville to house future steelworkers, and the first Korean barbecue joints are opening up.
About a dozen miles down the river, in St. James Parish, the industrial gas supplier Air Liquide is building a second air-separation unit to serve Hyundai’s steel mill.
During my visit to the area, I stopped by to see its existing facility, which sucks outside air through an enormous filter and distills the molecules into high-purity oxygen, nitrogen, and argon. The Paris-based company is about to start construction on a $350 million additional unit and infrastructure that will mainly supply oxygen by pipeline to Hyundai’s new electric arc furnaces. Injecting oxygen makes chemical reactions more efficient, reducing the amount of electricity needed and lowering emissions.
“Hyundai wants to put the steel plant in badly, so we’re working at a fast pace. We’re going to support their needs,” Nick Frasier, the plant manager, told me as we toured the plant by car, rolling past towering columns and snaking pipes. He said the new unit is expected to come online in 2028.
Air Liquide is also one of the world’s largest producers of hydrogen. The company today primarily makes conventional hydrogen from natural gas, though it is building several large-scale green hydrogen plants at sites in Canada, Europe, and Asia.
Matthieu Giard, a group vice president for Air Liquide, said the company “would be more than happy” to partner with Hyundai if the steelmaker decides to use hydrogen in its Louisiana steel mill. “That could be another project for us tomorrow,” he said by phone from his office in Houston.
But Louisiana will need to first see a massive buildout of renewable energy if Hyundai is going to make that switch.
Producing enough green hydrogen to supply the steel mill could require at least 3 gigawatts of renewable generation capacity to run electrolyzers, the Clean Air Task Force estimated. That’s more than all of the solar power installed in Louisiana, which makes up most of the state’s clean energy capacity. Natural gas power plants provide the majority of the state’s total electricity generation, along with a smaller share from nuclear facilities.
Entergy Louisiana, the state’s largest utility and Hyundai’s electricity provider, is planning to add up to 3 GW of solar power to its portfolio in the coming years. And developers are advancing plans to build the state’s first three onshore wind farms. However, earlier efforts to install gigawatts’ worth of turbines in the Gulf of Mexico have screeched to a halt amid the Trump administration’s attacks on offshore wind development.
Clean energy advocates in the state say they’re trying to position Louisiana’s industrial growth as a key reason for policymakers to support more wind and solar development — particularly given that renewables are now cheaper and faster to build than gas and nuclear plants. Hyundai itself spoke out about its coming clean-energy needs during an off-the-record panel in April at the Powering Louisiana Forum.
If built as promised, Hyundai’s green steel mill could be the start of that broader transformation for both the state and U.S. steelmaking.
When I sat down with Bradford Rosenberg, Wells, and Dickerson in Baton Rouge, the three of them wavered between excitement about what the project could deliver and skepticism about whether Louisiana was being sold yet another dream too good to be true. As they see it, the work of their grassroots coalition is to not only pressure Hyundai but also counter the growing disillusionment in surrounding communities and even within themselves, and to hold on firmly to a vision of what could be.
“The Hyundai plant is huge for the United States and for us,” Bradford Rosenberg said. “We want to make sure we get it right.”
The state’s Republican attorney general — a gubernatorial candidate — sued to stop the new Trump-backed smelter, which would double America’s aluminum output.
A power-hungry aluminum smelter planned in Oklahoma is facing a new legal challenge that aims to stop the massive project in its tracks.
Last week, Oklahoma’s attorney general sued to block Emirates Global Aluminium (EGA) and Century Aluminum from building the $4 billion facility, which is slated to more than double the nation’s capacity for producing aluminum from scratch.
Gentner Drummond, the state’s attorney general, said he took action to protect Oklahomans from the “anticipated public nuisance” he claims the smelter represents. Drummond is running to be the Republican candidate for Oklahoma governor, and the lawsuit has intensified debate about the project in what is becoming an increasingly heated primary race.
Drummond raised concerns that the facility would pollute the air and water and harm cattle and crops in Inola, the rural town in northeastern Oklahoma that is set to host the plant. Residents in Inola share those environmental worries, and local opposition to the smelter — which would be America’s largest if built — is mounting as developers get closer to starting construction this year.
The lawsuit also flagged the smelter’s enormous electricity appetite. The new facility is expected to require over 1 gigawatt of continuous electricity to operate — enough to power a city the size of Boston or Nashville annually. The attorney general claimed that this level of consumption will place “extraordinary strain on the regional grid” and threaten “the reliability and affordability of electricity for Oklahoma ratepayers.”
The developers are currently pushing to finalize a crucial long-term power contract for the smelter, which could draw from Oklahoma’s abundant natural gas and wind energy resources and solar energy potential.
Drummond further objected to the foreign involvement in the project: EGA, a state-owned enterprise of the United Arab Emirates, has a 60% stake in the smelter, while Chicago-based Century owns 40%.
However, the timing of Drummond’s June 2 filing has raised questions about his motivations, and it’s unclear how big a threat the legal action poses to the smelter’s prospects.
Drummond filed his lawsuit four days after President Donald Trump — who has championed the smelter — endorsed Drummond’s rival, former state Sen. Mike Mazzei, for the June 16 gubernatorial primary election.
Mazzei himself had strongly opposed the aluminum plant until very recently, criticizing the hundreds of millions of dollars in tax incentives the project is expected to receive from the state of Oklahoma, including power discounts. The project has also been awarded a $500 million grant from the U.S. Department of Energy.
On May 29, just hours before Trump endorsed him, Mazzei publicly reversed course. He announced on social media that he would strongly support the smelter as governor and would “work with the Trump administration to bring more projects like it to Oklahoma.”
Oklahoma’s outgoing Republican governor, Kevin Stitt, accused Drummond of “weaponizing” the attorney general’s office to retaliate against Trump. In a video message on Facebook, he framed the smelter as key to protecting America’s national security interests, given that China accounts for about 60% of the world’s annual output. Aluminum is used to make not only household products and construction materials but also fighter jets, warships, helicopters, and ammunition.
Drummond, for his part, has denied any ulterior motives. He said he filed his lawsuit in response to the developers’ air-quality permit application, which they submitted on May 19, the news site Oklahoma Watch reported.
“A primary aluminum smelter does not belong in a community’s backyard, and its emissions do not respect property lines,” Drummond said in his initial statement, adding that winds could carry pollutants into the surrounding northeastern Oklahoma communities.
Putting aside the messy governor’s race, the aluminum smelter will undoubtedly change the landscape in Inola, which hails itself as the world’s “hay capital” and is home to many thousands of heads of cattle. The industrial facility is set to span 350 acres along the Verdigris River, where every year it will convert raw materials into 750,000 metric tons of aluminum, not far from schools, homes, and farms.
Last fall, the climate advocacy group Industrious Labs conducted a statewide survey to gauge Oklahomans’ views on the proposed smelter. Some 62% of respondents said they supported the project. But proponents, opponents, and skeptics all said they had at least some environmental worries about bringing heavy industry like aluminum smelting to the state.
“We’ve seen bipartisan support for reshoring domestic manufacturing, and specifically aluminum — both the Biden and Trump administrations are prioritizing this,” said Annie Sartor, senior campaigns director at Industrious Labs. “But concern around local air and water pollution is also bipartisan. People are concerned about dirty industry coming into their neighborhoods.”
Traditionally, America’s smelters have spewed significant amounts of pollution, including fluoride and mercury, which can damage crops and livestock. They also release perfluorochemicals — potent and long-lasting greenhouse gases — and emit sulfur dioxide, which can harm people’s respiratory systems and damage vegetation. Smelters have discharged wastewater into rivers and streams, and they generate toxic waste as the lining in the smelting tanks breaks down.
EGA and Century claim the Inola facility will be significantly cleaner than existing U.S. smelters — the last of which was built in 1980. The companies are building the project through a joint venture named Oklahoma Primary Aluminum, which will use the latest version of technologies that EGA has been developing over decades.
“This facility is designed to be the most modern aluminum plant in the world,” Oklahoma Primary Aluminum said in a statement to Canary Media. On their website, the developers say the smelter will be “highly controlled, with multiple environmental safeguards in place,” including for filtering and monitoring pollution and reducing emissions and energy use.
Oklahoma Primary Aluminum also nodded to questions about the smelter’s enormous draw on the region’s grid. Developers have been negotiating a power agreement for more than a year with Public Service Company of Oklahoma, a subsidiary of the utility giant AEP. Any deal will need to be reviewed through a regulatory process overseen by Oklahoma’s public utilities commission.
“A key purpose of that process is to assess and minimize potential impacts on residential and commercial customers,” the developers said in response to the lawsuit. They added that EGA’s modern smelting technology can reduce electricity use by about a third for every ton of aluminum produced, compared with America’s remaining fleet of aging smelters.
Facing new regulations and stiff competition from China, Sweden and other EU countries are racing to decarbonize steel production. It all hinges on green hydrogen.
In 1872, while on a trip to Europe, Andrew Carnegie met with an engineer and inventor named Henry Bessemer. During the Crimean War, Bessemer had accidentally discovered an efficient (for the time) new method of making steel, which involved blowing air through molten iron to remove its impurities. He later developed it into a process that a few small steelworks had already adopted by the time of Carnegie’s visit. Carnegie had been following Bessemer’s invention from the U.S., but none of the steelworks employing it there had really taken off. The future titan of industry was nonetheless wowed by the older man’s presentation, and returned home convinced that steelmaking should be his next venture.
There was no doubt as to where to make such an investment. Manufacturing steel required huge volumes of iron ore and coal, and both were abundant around Pittsburgh. The city also enjoyed an advantageous location for transporting the heavy end product by barge. The Allegheny and Monongahela rivers merge there into the Ohio, down which one can navigate to the Mississippi and the Gulf of Mexico. Plus, Carnegie had a ready customer in the expanding railroad industry and political help in the form of a recently enacted steep tariff on imported rails. So, the Edgar Thomson Steel Works was erected in 1875, 10 miles outside Pittsburgh, in Braddock. (The thing is still running.)
One hundred fifty years later, a similar confluence of circumstances can be found nearly 100 kilometers (62 miles) south of the Arctic Circle, in Luleå, Sweden — one that could lead to the next big innovation in steelmaking. In 1872, no one knew, or cared, that Bessemer’s method was actually carbon manufacture with a side hustle in steel: Even in today’s furnaces, 1.8 metric tons of carbon dioxide are emitted for every ton of steel, give or take. But now, a new, cleaner method of steelmaking exists. It involves using hydrogen instead of coal to produce iron from iron ore in a process called direct reduction, then fashioning that iron into steel in an electric arc furnace.
When renewable electricity powers the hydrogen production and the electric arc furnace, the CO₂ per metric ton of steel in direct and indirect emissions can be reduced to 0.4 metric tons — about 80% less than from the most efficient methods developed since Bessemer’s time.
Hybrit Development, a joint venture of the Swedish companies LKAB (iron ore mining), SSAB (iron and steel production), and Vattenfall (energy), is developing an end-to-end process for steelmaking using hydrogen in Luleå. The group opened a pilot plant in 2020 and is working to build its first commercial-scale plant. Stegra, another Swedish startup, is aiming to do the same thing about 40 kilometers (25 miles) north, in Boden.
Much like the Pittsburgh area in the 1800s, northern Sweden enjoys certain geographical advantages: a surplus of hydropower, enormous iron ore mines 250 kilometers (155 miles) to the north, and a thriving seaport.
Sweden is also getting a nudge from the European Union, which aims to make Europe the first carbon-neutral continent by 2050. Starting this year, the steel industry across the 27 member states has to start paying for its emissions under the EU Emissions Trading System — the allowances initially granted to give it time to adjust are being phased out. The new regulations will sink its business model.
Germany, Norway, and other European countries are making similar efforts to decarbonize steel production, and as with many things concerning the energy transition, China is leaping ahead. The world’s largest ironmaking plant fueled by hydrogen started operating at full capacity late last year in Zhanjiang City, Guangdong. The U.S., meanwhile (as with many things concerning the energy transition), lags behind. The Biden administration sought to spur green hydrogen projects with tax credits and subsidies, but since January 2025, President Donald Trump has killed $12.5 billion in federal funding for clean energy projects — including some in green hydrogen — and threatened to scrap an additional $12.2 billion in existing grants. (SSAB was behind one of those projects, in Mississippi, but — perhaps seeing the writing on the wall — it quit the subsidy award process just before Trump took office and says it has no plans to try again in the U.S.)
With more than 300,000 jobs and 152 billion euros in economic activity tied to the EU’s steel industry, the stakes are high for Europe in the global race to decarbonize steel. And given the industry’s 5% contribution to overall bloc emissions, if it succeeds, the benefit to the climate will be enormous.
The hulking, rusting blast furnace that greets visitors just inside the gate of SSAB’s Luleå facility is a working remnant of traditional steelmaking. A short drive across the 265-hectare (1-square-mile) site follows the route of an elevated conveyor belt connecting the coking plant, where coal is cooked down, to the blast furnace. The road continues on to the building that houses Hybrit’s direct-reduced-iron demonstration plant. At 50 meters (164 feet) high, it’s about as tall as the blast furnace, but the similarities end there. The demonstration plant’s right angles and light-gray aluminum siding stand in stark contrast to the older structure’s tangle of rusted, ashen cylinders and beams.
General Manager Gunilla Hyllander met me in the parking lot that divides the demonstration plant from Hybrit’s administration building. Just inside the door to the offices, a loose pile of employees’ shoes dripped snow — though at minus 11 degrees Celsius (12°F), it was almost balmy for January in northern Sweden. We sat down in a large room with samples of iron made in the DRI plant laid out on tables. Though the facility wasn’t in operation that day, Hyllander could see the future starting to take shape.
“Hydrogen reduction in itself is not new,” she said. “People have been thinking about that for years. But in an efficient, safe, and productive manner? That has not been proven before. We think that all the processes from mine to steel could be converted to a fossil-free manner. We’re using all existing technologies and putting it together in a new value chain.”
Steel has been produced on this site since the 1940s, originally by Norrbottens Järnverk. In 1978, Sweden’s government decided to socialize the country’s steel industry by merging Norrbottens and two other struggling companies under state ownership, as Svenskt Stål AB (Swedish Steel Ltd.). SSAB reprivatized in 1992, though the government now owns a 16% share. A major investment in the Luleå operation came in 1998, when the company built the current blast furnace at a cost of 850 million kronor (around $150 million, inflation-adjusted). That timing is significant. A blast furnace requires major maintenance about every 15 years. After relining its facility once, SSAB realized that by 2030 at the latest, it would need to either make that investment again, which would mean producing 7% of the country’s carbon emissions even after the carbon allowances had expired, or figure out a way to do things differently. The company took the second path, banding together with LKAB and Vattenfall to form Hybrit — short for “hydrogen breakthrough ironmaking technology” — in 2016.
SSAB’s decarbonization challenge is a microcosm of the European steel industry’s. It’s going to be a heavy lift. The company’s gigantic share of Sweden’s carbon emissions is no outlier. Globally, the sector produces about 7% to 9% of anthropogenic CO₂ emissions, according to the World Steel Association — about the same as all the world’s passenger vehicles — and accounts for over a quarter of the EU’s industrial emissions. Demand for steel is projected to grow by nearly 20% by 2050, according to BloombergNEF.
The traditional steelmaking process that Carnegie helped popularize primarily emits carbon in two ways: First, coal is burned as fuel to heat blast furnaces to above 1,000°C (1,832°F). Second, a purified form of coal, called “coke,” is heated inside the furnace to induce a necessary chemical reaction that strips oxygen from iron ore (the “reduction”), producing iron and — the second emission — releasing CO₂.
Hydrogen-based direct reduction addresses both problems. Instead of carbon, hydrogen serves as the reducing agent for the iron, combining with oxygen to produce water vapor instead of CO₂. The process operates at lower temperatures than blast furnaces do, requiring less energy. When that energy comes from renewables and the hydrogen is produced from electrolyzers — machines that split hydrogen from water — powered by wind or solar, the result is near-zero emissions. “In the development program, we are close to zero CO₂ emissions per tonne of crude steel — 42 kilograms, instead of 1.6 tonnes,” Hyllander said.
Direct reduction with natural gas has been used in commercial operations for decades, particularly in the Middle East and India, where cheap gas has historically been abundant. What’s changing now is the fuel source. Hybrit started with natural gas to establish a baseline for emissions, but in 2021 it began producing hydrogen with two stacks of electrolyzers. Situated behind the DRI plant, the electrolyzers aren’t much to look at. With their cylindrical shape and multiple rubber tubes, they resemble sewage pipes on life support. But inside is a complex system of wires, tanks, valves, and gaskets that passes an electrical current through an alkaline solution between an anode and cathode, splitting the water into hydrogen on one end and oxygen on the other.
Over the past five years, Hybrit has operated its pilot plant for 61 weeks, producing 5,000 metric tons of fossil-free sponge iron pellets, each about the size of a chocolate-covered almond, which a microscope reveals to have a porous structure. The company has also conducted over 400 trial melts at the research institute Swerim, down the road, which operates its own electric arc furnace. At least one automaker is already using the end product in its vehicles, and Hybrit’s green steel has been incorporated into production lines for heavy machinery and consumer products. The process works. The question is whether it can scale economically.
Europe has positioned itself as the global leader in green steel, and major producers have set ambitious targets. SSAB and Thyssenkrupp aim for carbon neutrality by 2045; ArcelorMittal aims for 2050. Already, more than half the near-zero-emissions steel projects in the global Green Steel Tracker are in the EU. Among them are Hybrit’s neighbor and competitor, Stegra, with a goal of producing 5 million metric tons of green steel annually by 2030 at its Boden plant; and Finland’s Blastr, targeting 2.5 million metric tons by 2026. (In comparison, Edgar Thomson outside Pittsburgh, now part of the Mon Valley Works complex, produces 2.9 million tons annually.) Thyssenkrupp, ArcelorMittal, and Salzgitter have all announced hydrogen-based projects in Germany. The EU has approved nearly 9.3 billion euros in state aid for these ventures. The European Steel Association forecasts emissions reductions of 81.5 million metric tons of CO₂ equivalent per year by 2030 if current projects are completed on schedule.
But progress has stalled. As of August 2024, 80% of announced direct reduction capacity hadn’t moved forward. Only 3% had become operational. Recent setbacks have raised serious doubts about whether hydrogen-based steelmaking can scale up in time to meet the emissions-reductions targets.
Stegra, which, like Hybrit, aims to produce hydrogen on-site, has struggled through at least two seismic funding shortfalls. ArcelorMittal, meanwhile, has scrapped plans to convert two steel plants to green production in Germany because of the high electricity costs of running an electric arc furnace. And Thyssenkrupp announced in March 2025 that it might need to ditch a $3.3 billion conversion project, citing the lack of affordable green hydrogen needed to supply its steel mill.
Steel producers such as Thyssenkrupp that plan to outsource their hydrogen face a classic chicken-and-egg problem. They need confidence there will be a hydrogen supply before they’ll commit to building. But hydrogen producers need committed offtake before they’ll invest in production, and pipeline operators need both before they’ll convert networks to use H2. Nobody wants to move first.
“Companies are not going to invest if they don’t know the pipeline is going to be ready on time and that the offtake is there,” said Leif Christian Kröger, Thyssenkrupp’s head of public affairs.
In 2022, European leaders tried to address the lack of supply by setting an ambitious target of 10 million metric tons of domestic green hydrogen production and 10 million metric tons imported by 2030. Hydrogen conferences sprouted up in Rotterdam and Düsseldorf, replete with optimistic projections of when green hydrogen would meet price parity with “gray hydrogen” (produced using natural gas) and “blue hydrogen” (natural gas with carbon capture). But then the reality hit of how much renewable electricity would be required to meet the targets. With estimates running to the equivalent of almost twice the entire United Kingdom’s consumption in 2020 (a pandemic year), it’s not surprising that progress so far has been an underwhelming 1% of the goal. “They need to show a lot of progress in the next 12 to 18 months” to get there, Daniyal Sheikh, hydrogen market analyst at ICIS, a commodities research service in London, told me in October.
Nima Pegemanyfar is executive vice president of customer operations at Quest One in Hamburg, Germany. His company was making 1-megawatt electrolyzer stacks as far back as 1997 (as H-TEC Hydrogen Energy Systems) and in 2023 launched a 10-MW-to-100-MW modular plant. “Capacity was the restraint a few years ago, so we built that up as an industry,” he said. “Now, demand is what’s lagging.” This isn’t just the self-interested complaint of an electrolyzer manufacturer. Christine Falken-Großer, of Germany’s Ministry of Economic Affairs and Climate Action, agreed that “demand is the essential element right now to unlock growth” in green hydrogen production.
But the economics are punishing to buyers. Green hydrogen costs at least twice as much as its fossil-based alternative. Though natural gas prices have spiked with the closure of the Strait of Hormuz, futures contracts indicate the market believes this will be a temporary disruption that will be resolved before green hydrogen scales up enough to compete on price.
“Producer costs are higher than the price, and customers are not willing to pay the premium,” said Camilla Montemurro, a policy adviser at the trade association Eurogas. BloombergNEF doesn’t expect green hydrogen to reach price competitiveness before 2030, leaving scant time before the carbon allowances expire to achieve what it took Hybrit a decade to do.
Electricity costs in Germany — Europe’s leader in steel production — are a significant hurdle. “The green steel industry doesn’t want to decarbonize as fast as planned, because of the high cost of renewable electricity,” Pegemanyfar said. A million-metric-tons-per-year direct reduction plant running fully on hydrogen requires about 70,000 metric tons of hydrogen annually. That amounts to roughly 800 MW to 900 MW of electrolyzer capacity with around 1 gigawatt of electrical transformer capacity — a capital expenditure of 350 million euros to 700 million euros before you’ve bought any iron ore.
Infrastructure gaps compound the cost hurdle. Europe envisions several “hydrogen backbones” — networks of converted natural gas pipelines carrying hydrogen from ports or production sites to industrial (and perhaps commercial and residential) users. But the chicken-and-egg problem persists. “Pipeline operators won’t invest without offtake, and users won’t buy without infrastructure,” said Dirk Niemeier, director and Clean Hydrogen Solutions lead at PwC in Munich.
The backbone is only the half of it. Just as electricity requires tall transmission towers to move large volumes of power long distances and smaller wires to distribute it to users from central hubs, hydrogen requires both thick pipes (the backbone) and skinny pipes (for delivery to the end customers). Barbara Jinks, director of Ready4H2, an industry group that promotes using gas distribution grids to deliver hydrogen, described the scale of the undertaking: “More than half the gas won’t get to the end user with current infrastructure. Anything more than 3 kilometers [1.8 miles] from the backbone needs a distribution line.” The gas industry would rather sell capacity in the pipelines in which it has already invested billions to hydrogen producers than see this asset stranded as the world switches to running on electricity.
But “hydrogen has rather unique effects on materials, and many of them are not good,” noted P. Chris Pistorius, co-director of the Center for Iron and Steelmaking Research at Carnegie Mellon University in Pittsburgh. The pipeline networks can be converted, but that takes money and time.
Storage presents its own conundrum. Daniel Mercer, managing director of Storengy, a subsidiary of French energy giant Engie, hopes to provide “the hydrogen battery for all of Europe” by storing the gas in underground geologic formations near Hamburg, Germany. But funding is scarce. “We are the only part of the hydrogen system not supported by the government, yet we’re the part that takes the longest to develop,” he said. “Finding funding is the toughest part of my job right now. I need somebody to give me 1 billion euros and be OK with not making any money for eight years” while the underground H2 storage project is built out.
Importing hydrogen instead of producing it in Europe wouldn’t really help. Several European ports are developing terminals to import ammonia, which contains hydrogen molecules and is easier, cheaper, and safer to ship than pure H2. But converting hydrogen to ammonia and back again loses about half the energy contained in the original batch. So when the buyer collects a shipment “in Rotterdam or Hamburg, the price is suddenly double,” said Alexander Fleischanderl, chief technology officer of the London-based Primetals Technologies, which developed a proprietary technology called Hyfor for making green steel. “This is by far not competitive anymore.”
Like Hybrit, Primetals Technologies gets around problems with importing hydrogen by attaching production to its green-steel manufacturing process. It hopes to offer green steelmaking as a kind of service and secure contracts to build plants for companies shutting down their blast furnaces.
Amid these converging pressures, European policymakers and industry leaders must confront tricky questions about the continent’s industrial future. Can Europe keep steel production at today’s levels while ratcheting down emissions through the necessary conversion? Can the current political environment withstand losing jobs to countries where steel can be produced at lower cost?
“I would bet that at least some capacity will move away from Europe to more competitive regions,” Fleischanderl said. The logic is straightforward. With steelmaking, 80% of the energy and just 20% of the jobs are in converting iron ore to iron. Turning that iron into steel takes 20% of the energy and 80% of the jobs. “Why should we transport hydrogen if we could use the hydrogen locally” in producing iron? Fleischanderl asked. Most of the world’s iron ore is in places with ample opportunity for renewable energy — Australia, Brazil, Canada — and thus relatively cheap hydrogen. Decoupling the two processes geographically — producing the iron overseas and then shipping it to Europe, where it can be made into steel in an electric arc furnace running on renewable energy — would sacrifice relatively few jobs to gain a lot in savings on green hydrogen.
Pistorius also thinks that the less labor-intensive part of the steelmaking process could move overseas, where renewables are cheaper. “There’s a lot going for that argument,” he said. “Shipping iron is a relatively good way to [move] the energy around rather than trying to ship ammonia and regenerate it to hydrogen at the destination.”
But Germany’s 79,000 steel jobs hold an outsize place in the country’s identity. Next door in the Netherlands, farmers representing 1% of jobs and 1% of GDP almost brought down the government when it threatened to tighten pollution regulations. Germany’s ascendant populist forces, at least, are likely to resist sacrificing even 20% of steel jobs on the altar of green energy.
Either way, strategic considerations argue for maintaining at least some domestic production. Steel is essential for defense, infrastructure, and the energy transition itself — wind turbines and transmission towers are largely steel. The current energy crisis spurred by the war in Iran has driven home once again the risks of long supply chains, and the EU’s Carbon Border Adjustment Mechanism, which functions as a tariff on high-carbon imports, aims to protect European producers that invest in decarbonization.
Additional policy changes could further accelerate progress. The EU’s Renewable Energy Directive (RED 3) imposes strict requirements on what qualifies as green hydrogen — requirements that many argue are too stringent. “EU needs to relax RED 3,” Niemeier said. “That would bring down the cost.”
“You can’t have a free market at the beginning of this,” said Ad van Wijk, professor of future energy systems at Delft University of Technology in the Netherlands. “There will be buildup to a market, but you need some organization at the beginning. Are we able in the EU to organize all this, with all the politics that are behind the different fuels?”
Falken-Großer has learned from experience that “‘quickly’ is not a word that is known in Brussels.”
Julia Metz of Agora Industry, a clean industry research institution, suggests public procurement requirements and state-funded infrastructure projects to provide the nascent industry with guaranteed offtake. “Lead markets [created] through binding requirements in public procurement” would build “secure demand for green steel,” she said in an interview with Clean Energy Wire. The European Commission’s proposed Industrial Accelerator Act, part of the Clean Industrial Deal, aims to support domestic clean industries through public procurement.
Even without these nudges, 510 green hydrogen projects have reached final investment decisions, including 83 since May 2024, and customer commitments for green steel are emerging. BloombergNEF in 2025 tallied up almost 200 supply agreements for low-carbon steel. SSAB has announced deals with Volvo for green steel sourced from Hybrit; Mercedes also has an offtake agreement. The automotive industry — which accounts for significant steel demand — increasingly wants to claim carbon neutrality, said Martin Gidlund, SSAB’s transformation communication manager. “For 2040, they want to be able to say ‘made with green steel.’”
In Luleå, the scale of what’s being attempted becomes tangible. Within view of the current coking plant, SSAB broke ground in September 2025 on a building that is 1.5 kilometers (1 mile) long and about a half kilometer (quarter mile) wide and that will integrate two electric arc furnaces, continuous casting, hot rolling, and cold mill operations. The new plant will be able to run on either scrap steel or sponge iron from direct reduction using green hydrogen, or any mix of gas. Initially, the facility will use scrap, like SSAB’s existing U.S. electric arc furnace operations do in Montpelier, Iowa. At peak construction, up to 3,000 workers will be on-site. In a preview of Fleischanderl’s notion that ironmaking and steelmaking can be geographically separated, the iron ore will be reduced next to LKAB’s mining site and transported by rail to be turned into steel in Luleå. After some delays with the grid connection, startup is now targeted for late 2029. The environmental permit allows only two years of parallel production, so once the new facility starts, the blast furnace must shut down by 2032. Sweden’s single largest CO₂ emitter will be no more.
The business case rests on multiple factors. The existing blast furnace, built in 2000, will need relining soon — a significant investment. The coking plant, built in the 1970s and operating continuously since, is aging; renovation is not an option. “We cannot turn it off, because if we do, it will fall apart,” Gidlund said. The bricks inside the ovens will just shatter as they compress when the heat dies down.
Under the EU Emissions Trading System, continuing with coal-based production would cost SSAB more than 10 billion euros a year in carbon credits, the company has determined. “Either we invest a lot of money in old technology, or invest more money but in new technology,” Gidlund said. “We’re calculating that building the new one is using our capital more efficiently and also setting up for a system that will make us more competitive in the long run.”
It’s a dilemma that steelmakers worldwide need to face eventually — around 70% of blast furnaces need relining or other major maintenance by 2030. In the EU, over half will by 2035. If they’re relined — extending coal-based production — Europe will miss its climate targets and lock in 435 million metric tons of CO₂ over the next 20 years, according to industry estimates. China’s blast furnaces were installed more recently, so their owners can put off the decision for a few more years. But major steelworks in the U.S. are already investing in the past, opting for relining over going green. U.S. Steel is set to start relining its Gary Works blast furnace in Indiana this month; Cleveland-Cliffs plans to do the same at its Burns Harbor plant in Indiana next year.
Whether Europe’s bet on green steel succeeds depends less on technology than on coordination. Hybrit and Primetals Technologies have solved the technical issues. Quest One and other manufacturers can build electrolyzers at scale. Storengy understands how to bottle the hydrogen. Pipeline operators have the know-how to convert networks.
What’s missing is the choreography — getting all these pieces to develop simultaneously at the pace and scale required. “You have to build production and infrastructure and storage and the offtake side at the same time,” van Wijk said. “You have to replace blast furnaces with DRI, and that has to be done in the same volume by all kinds of different companies. If governments don’t have a certain commitment, it won’t happen.”
The pressure is building. The atmosphere doesn’t care who gets there first, but European steelmakers are facing overseas competition from China, which is curbing blast furnace approvals and scaling up hydrogen-fueled ironmaking output, and from the Middle East and North Africa, whose abundant cheap, renewable energy potential could position the regions as future suppliers of both green hydrogen and reduced iron (as long as, in the case of Qatar and United Arab Emirates, Iran keeps the Strait of Hormuz open). If European buyers who want green steel can’t get it in Europe, they will have other options.
“We’re in the lead on technology, and if we are too hesitant, China will drive by us,” warned Pegemanyfar at Quest One. “Already some German [electrolyzer] manufacturing is moving to China because there’s not enough demand here. If the price doesn’t come down, China will flood our market as it did with solar, and we’ll risk losing out on another key technology for the energy transition.”
Those that have opted to produce their own hydrogen, like Hybrit and Stegra, have a head start. Britain’s ITM Power sells a self-standing 50-MW hydrogen plant for the bargain price of 50 million euros. Thyssenkrupp, ArcelorMittal, and Salzgitter can turn to Primetals Technologies’ plants when its Hyfor tech is ready for market in 2028, but they may find that the hydrogen backbones and Ready4H2-promoted projects aren’t built up enough, or that the bottlenecks aren’t resolved soon enough, to prevent their drowning in red ink from the rapidly approaching carbon fees. “Very likely there will not be sufficient hydrogen in three years,” Fleischanderl said. “It takes plus or minus three years to build a hydrogen plant from commitment to production.”
Considering the widely distributed climate risks of business as usual, and the known health impacts to Europeans of burning coal, losing 20% of the continent’s jobs in steel — 300,000 total, or 0.1% of the jobs in Europe — would be a small price to pay for accelerating the transition to green steel. Germany already lost 115,000 jobs in photovoltaic manufacturing between 2011 and 2015 because of cheap imports from China and nobody blinked an eye. The question before Europe now is whether it will do what it takes to bring green steel to price parity with the dirty kind — either by subsidizing it or letting some production move overseas — or allow a tiny constituency to decide that no one must pay a few euros extra for a car and everyone will be forced to suffer the consequences of steel’s current 2.6 billion metric tons of annual emissions.
“Sometimes in Europe we can be too good,” Falken-Großer said.
Battery startup EnerVenue is planning an iconoclastic comeback. After failed plans to build a U.S. factory for its NASA-inspired tech, the firm announced $300 million in fresh funding to execute a manufacturing strategy that flies in the face of broader trends in the American battery market.
Battery startup EnerVenue is planning an iconoclastic comeback. After failed plans to build a U.S. factory for its NASA-inspired tech, the firm announced $300 million in fresh funding to execute a manufacturing strategy that flies in the face of broader trends in the American battery market.
A rendering shows how EnerVenue’s nickel-hydrogen batteries could be stacked in a warehouse, capitalizing on the chemistry’s safety, compared with lithium-ion’s. (EnerVenue)
EnerVenue seeks to commercialize a version of the pressurized nickel-hydrogen energy storage system that NASA used on the International Space Station and the Hubble Space Telescope. The original technology cost far too much to succeed in civilian power markets, but EnerVenue’s founders claimed to have swapped the platinum catalyst for a much cheaper material. The company says its battery can run 30,000 cycles with minimal degradation, maintaining its usefulness far beyond the typical lithium-ion battery’s shelf life, and with much better fire safety.
The Silicon Valley–based startup raised a $12 million seed round in 2020 and a $100 million Series A in 2021 from the likes of Saudi Aramco Energy Ventures and Schlumberger New Energy. In 2023, EnerVenue told Canary Media it would invest $264 million to open a factory in Kentucky and produce batteries by the end of the year.
Battery factories have been opening across the U.S. to meet skyrocketing demand for grid storage. Federal incentives reward factories for manufacturing batteries domestically and storage developers for installing batteries, as long as they don’t depend too much on “foreign entities of concern,” which in practical terms restricts corporate and supply chain exposure to China. This onshoring effort has moved so swiftly that the U.S. may well become self-sufficient in both battery cells and finished battery enclosures for grid storage by the end of this year.
EnerVenue opted not to contribute to this achievement, at least not anytime soon. The company pulled out of its Kentucky deal in 2024. The $300 million it unveiled March 31 (technically an extension of a $308 million Series B from 2024) will instead fund a factory buildout in Changzhou, China, which the company’s press release hailed as “the world’s epicenter of battery manufacturing expertise.” EnerVenue also promised to “expand its commercial operations across Asia, the Middle East, and Europe.”
“We see ourselves still as an American company,” Henning Rath, who took over as CEO in March, told Canary Media. But, he continued, “We’re going to become a global player.”
Why would this startup choose to zig to China when the rest of its peers are zagging to the U.S.?
For starters, once work began on the Kentucky factory, the company realized that its second-generation battery design wasn’t ready for mass production, and that it would be particularly capital-intensive to build a first-of-its-kind battery factory at the site, Rath said.
From the outside, it might seem sensible to design a viable product before starting to build a factory to mass-produce it. The venture-backed cleantech industry, however, boasts a long history of constructing factories for inventions that failed to function in either practical or commercial terms. Chalk it up to undue optimism, or the pressure to show venture investors a quicker path to mass production and revenue.
In any case, EnerVenue pulled the rip cord, and then-CEO Jorg Heinemann left in November 2024, spending 10 months as a “Cyclist, surf coach & c-suite advisor,” according to his LinkedIn, before becoming president and chief operating officer of a startup selling clean, dispatchable power to data centers. “As the company decided on shifting gears and we evaluated the technology and manufacturing setup, I think that both parties agreed to look into different options” Rath said of Heinemann’s departure. Rath didn’t formally step in as CEO until March; he previously ran supply chains for German residential solar startup Enpal — a task that involved sourcing Chinese solar products for installation back in Europe.
After the reset, EnerVenue delved back into engineering and spent nearly two more years honing a fourth generation of its tech, Rath said. Then the company made the choice to assemble the factory process in China, to take advantage of the mature battery manufacturing sector there.
EnerVenue now has a small R&D manufacturing line operating in Changzhou and is working to finish a 250-megawatt-hour-per-year line by the early fourth quarter of this year. The plan is to grow the factory to 1 gigawatt-hour in 2027 — a level of production that unlocks competitive unit economics, Rath said, at which point EnerVenue could “copy-paste it to different markets.” EnerVenue may have an easier time doing this than conventional battery upstarts, since the ingredients to make its nickel-hydrogen battery are more readily available around the world than the carefully refined cathode and anode materials in lithium-ion batteries.
“We have to showcase scale first, in a very capital-efficient way,” Rath said. “That is the reason why we chose China to build the first scale-up.”
That low-cost manufacturing environment comes with trade-offs, however.
The need to distance America’s energy system from China has become a rare point of agreement across the U.S. political divide. The Biden administration pursued this with tax incentives for companies that build batteries in the U.S. and those that install domestically produced batteries. The Trump administration kept those policies but added the more punitive “foreign entities of concern” test to withhold credits from companies subject to corporate control from China and from projects that use too much equipment from China.
Chinese companies that built factories in America have had to divest from those enterprises to preserve tax credit eligibility for the products made within. EnerVenue poses a different accounting challenge: Can an ostensibly American company move production to China and still sell batteries to the U.S. market that let project developers qualify for the tax credits? Will that ability persist after EnerVenue’s latest fundraise welcomed significant equity investment from the Hong Kong Investment Corp. (wholly owned by the government of Hong Kong) and the Hong Kong–based family office of real estate tycoon Peter Lee?
On maintaining tax credit eligibility for the China-built batteries, Rath said, “We haven’t had a clear conclusion on this yet, but I think within the next probably two months or so, we will have certainty and execute against it.”
Geopolitical intrigue is just one of the challenges EnerVenue faces in commercializing a novel battery. Also on the list: Convincing buyers to bet on a little known chemistry for large-scale grid projects, and to embrace the whole new style of power plant unlocked by a battery with a vastly different operating profile than ubiquitous lithium-ion systems.
Typically, the startups vying to replace lithium bill their inventions as long-duration storage, capable of cheaply shifting clean energy production for many more hours than the four or five that lithium-ion batteries currently muster. Companies like Form Energy and Noon Energy are attempting to push the boundaries to 100 hours. EnerVenue does not stake such claims, and to the extent that the company touts duration, it’s in the different context of the batteries’ overall operating life. Rath said customers have asked for different configurations — from a 2-hour duration up to a 25-hour duration — but didn’t highlight a particular level as indicative of what the technology can do.
Instead, EnerVenue hopes to attract customers with its batteries’ ability to discharge three times a day for 30 years without eroding efficiency or catching fire, and operating parameters from minus 4 to 140 degrees Fahrenheit. (Lithium-ion grid batteries typically discharge once or twice a day and can tolerate a much narrower band of temperatures.) That could make EnerVenue’s system ideal for utilities in rugged environments or petrochemical complexes worried about battery safety. The many cycles a day, meanwhile, could help developers in volatile energy markets who want to take advantage of alternating periods of super-low and super-high pricing.
The trade-off of this impressive cycle life is that the battery needs to cycle a lot to justify its up-front costs. Doing so would require a very different sort of battery business model than what’s in practice today. After EnerVenue shows it can manufacture a working battery, it’ll have to prove that customers are actually willing to pay that premium.
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
Cache Energy installed its thermal battery at the University of Minnesota, Morris, where it stores energy from the campus’ two wind turbines and releases it to heat a carpentry workshop. (University of Minnesota, Morris)
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
“It’s windy year-round here in western Minnesota,” said Troy Goodnough, the school’s sustainability director.
Together, Bert and Ernie crank out 10 million kilowatt-hours of electricity annually. According to Goodnough, UMN Morris consumes about half the output and sells the rest to the Otter Tail Power Co., the local investor-owned utility. Now, a first-of-its-kind thermal battery pilot is underway that, if scaled up, could help the campus use more of that juice while reducing the environmental impact of the sprawling methane-powered steam-heat loops that keep it cozy through Minnesota’s bitter winters.
Late last month, technicians from Illinois-based Cache Energy arrived on campus to install the battery unit, which transforms electricity into intense heat. Its outlet temperature can reach 1,000 degrees Fahrenheit — more than hot enough to efficiently run a steam heating system.
It took two hours to position the shipping container that houses the unit next to the school’s carpentry shop, and then another few hours to connect the unit to the building’s electrical and duct systems. It powered up on March 24 and hasn’t stopped providing heat since, Goodnough said. Its task is not small, he added: The “warehouse-like” shop has high ceilings and several thousand square feet of floor space.
“The cool thing is it’s doing what it’s supposed to be doing,” he said. “It’s working great.”
The battery unit contains limestone-derived pellets coated in a proprietary binder that keeps them intact throughout their 30-plus-year operating life, according to Cache. When exposed to a stream of moist air, the pellets get so hot they “can be used to make hot air or even vaporize water to make steam,” Goodnough wrote last month. To recharge, the system uses electricity to dry out (and cool down) the pellets.
Ideally, that electricity is cheap, clean, and otherwise at risk of curtailment, said Sydnie Lieb, an assistant commissioner for regulatory analysis with the Minnesota Department of Commerce. Lieb’s agency helps fund Minnesota Energy Alley, a public-private partnership that supports the Cache project and other cleantech demonstrations in the North Star State.
“The most cost-effective place for thermal batteries is going to be where you have a lot of excess energy being produced where you don’t have a lot of transmission or [customer] load,” Lieb said.
Western Minnesota certainly fits the bill. The wind farms that dot the open, rolling landscape here and in neighboring North and South Dakota routinely produce more energy than the grid can handle. The Midcontinent Independent System Operator, the nonprofit that manages Minnesota’s grid, throttled hourly wind generation by an average of 508 megawatts in 2023, according to the U.S. Energy Information Administration. That’s the equivalent of what’s produced by about 160 newish onshore wind turbines. The Southwest Power Pool, which manages the grid for the wind-rich region stretching from North Dakota to the Texas Panhandle, curtailed wind output by an average of 1,097 MW that same year.
Arpit Dwivedi, Cache’s founder and CEO, said low-cost electricity helps make the economic case for customers to invest in thermal batteries rather than stick with equipment that runs on natural gas, which is also plentiful in the United States’ midsection.
“We know gas is cheap,” he said, and that’s a problem for tech developers looking to electrify heat.
Another issue for big energy users, like UMN Morris, is that switching from gas to electric heat means replacing massive, long-lived boilers — likely fully paid for — with new equipment that needs to be leased or financed.
That shift is necessary if the university is going to meet its aggressive climate goals of reducing greenhouse gas emissions by 87% by 2035 and reaching carbon neutrality by 2050, but it could incur a considerable balance-sheet burden. So from the outset, Dwivedi and his team were intent on reducing Cache units’ upfront cost, he noted.
“We knew that if we did not have a low-capex system, we would not have an economic advantage,” he said.
Like other emerging thermal battery designs, Cache’s uses low-cost — if heavy — materials that are widely available in the United States. The primary inputs are steel, lime, and water, all of which Cache sources domestically, Dwivedi said. The proprietary binder that keeps the lime granules stable is by far the most expensive input, so the company focused on keeping that cost in check. Its secret ingredients are available domestically, too, Dwivedi added.
Cache offers its battery as a lease product that it says bundles the battery unit, delivery, installation, maintenance, guaranteed uptime, and takedown “without capital burden.” Just as an automaker leases a passenger vehicle, Cache retains ownership of the battery unit during the lease term, after which the customer has the option to buy it or send it back.
Cache launched in 2022. For its first few years, space heating was a sideshow. Dwivedi and his team were more focused on the technology’s potential to electrify low- and medium-temperature process heat for food, chemicals, and other types of industrial production. To that end, Cache recently conducted a pilot at a Duke Energy testing facility in North Carolina that “[hosts] several interested industrial companies,” the company said last month in a news release.
Cache still works on industrial heat, but it’s also leaning into relationships with large space heating customers, particularly those with existing hot-water or steam infrastructure such as UMN Morris. That includes the U.S. Army, which is interested in the thermal battery’s ability to provide reliable backup for military installations at risk of extended power outages.
Cache was one of nine finalists in a demonstration cohort fielded last year by Grid Catalyst, a Minnesota-based clean energy accelerator that also supports Minnesota Energy Alley.
“Decarbonizing our heating in Minnesota stood out as a value proposition,” said Nina Axelson, Grid Catalyst’s president and founder. Cache’s technology, she noted, “is simple, less costly, and really effective on thermal storage and dispatch.”
Axelson said Grid Catalyst acted as a sort of “energy matchmaker” on the UMN Morris project, connecting university leadership with the Cache team. Front-end engineering and feasibility work required some time, she said, but once the university decided to move forward, it only took a couple of weeks to get the project up and running.
“It’s about as plug-and-plug as you get for thermal storage,” she said.
Dwivedi said that while the Morris system has been charging and discharging five or six times a day, the underlying technology can actually cost-effectively store energy for months on end. That’s a big selling point for customers serious about electrifying space and process heat.
Cache is fresh off a demonstration at an Alaskan industrial site, owned by oil and gas services firm Halliburton, that validated its batteries’ ability to hold heat for a long time in temperatures as cold as minus 40 degrees, Dwivedi said. That’s a critical proof point because the price of electricity — particularly on grids rich in renewables — tends to fluctuate throughout the year, he said. A Cache system could, for example, charge up on cheap power during a sunny, windy period in October, then wait to fully discharge until a dark, still spell in December, when local power prices are likely to be higher.
With a capacity of “several hundred kilowatts,” according to Dwivedi, the unit at UMN Morris is smaller than the industrial-scale ones that Cache hopes to sell at volume in the years ahead. The startup makes units as large as 5 MW and could deliver one to Minnesota in a few months if the university decides to expand the pilot, he added.
“We see this university project as a demonstration of one of the applications of this technology, and we can scale from there,” Dwivedi said.
A scaled-up, multiunit configuration could serve dozens of campus structures with a variety of uses. Some buildings have labs, swimming pools, and dehumidification systems that require heat even in the warm months, Axelson said.
In theory, Cache units could replace gas boilers on the campus steam system and complement a future hot-water loop powered by ground-source heat pumps — an increasingly popular cold-climate heating technology that Grid Catalyst is familiar with through Flow Environmental Systems, another 2025 cohort member that produces commercial-grade systems using low-impact refrigerant. A hybrid system could more efficiently distribute thermal energy between buildings and optimize campus heating in the depths of winter, “when you need all the heat you can get,” Axelson said.
“We are looking at using this as a showcase project so that our utility, industrial, and campus partners can see it in operation,” she said. “It’s hard for folks to be first, but when you do take that first project, you really open the gates.”
As UMN Morris undertakes a comprehensive review of its energy usage, Cache’s thermal batteries are among several technologies that could factor into a “Swiss Army knife solution” for sustainable heating, cooling, and power, Goodnough said.
On paper, it looks daunting to fully decarbonize a campus whose gas-fueled heat network uses three to four times more energy than all its electrical equipment put together, Goodnough said. But the university has steadily added on-site renewable capacity, including a 500-kW solar array that “we think is the largest agrivoltaic field in the Upper Midwest,” he said.
In the not-too-distant future, it could have far more homegrown electricity to play with.
“It’s not inconceivable that Bert” — the older windmill — “could be replaced by a 5-MW turbine,” Goodnough said. If Ernie meets the same fate, UMN Morris would roughly triple its on-site wind capacity. Goodnough believes that would be a tremendous opportunity not only for the university but also for rural communities nearby.
“Out here in rural Minnesota, you see storage everywhere: grain elevators, propane tanks, fertilizer bins,” he said. “The energy transition will demand lots of different kinds of storage. It’s a natural fit for us.”
Stegra has secured the financing needed to complete its flagship green-steel mill in northern Sweden.
The company, formerly H2 Green Steel, said it landed 1.4 billion euros ($1.65 billion) in capital from a group of new and existing investors led by Sweden’s prominent Wallenberg family. The funding will enable Stegra to finish building and commissioning its novel facility in Boden, just south of the Arctic Circle.
The project is a cornerstone of Europe’s broader ambitions to decarbonize its industrial sector and lead the world on lower-emissions technology. Conventional steel mills rely heavily on coal to produce the ubiquitous metal, making them a major source of planet-warming emissions and harmful air pollution.
Stegra’s first-of-a-kind project will instead rely on green hydrogen, which could slash carbon emissions from steelmaking by up to 95%, compared with traditional coal-based furnaces.
The sprawling facility will use giant electrolyzers, powered by the region’s ample hydro and wind energy supplies, to split water molecules and produce the clean fuel. That hydrogen will then turn raw iron ore into lumps of iron, which will be melted and made into steel in electric arc furnaces, also powered by renewables.
Stegra said it expects to initially produce 2.5 million metric tons of steel annually and eventually double its production of the metal.
The ambitious undertaking has hit some serious snags since construction began in 2022. Stegra previously raised some 6.5 billion euros ($7.64 billion) in loans and equity. But in recent months, faced with rising project costs and delays, the firm had been urgently seeking additional financing to address a growing cash crunch.
In October, the French hydrogen investor Hy24 swooped in to help fund Stegra for an undisclosed amount. That still wasn’t enough to stave off financial troubles for the steelmaker, which has batted away frequent rumors that the company and its marquee steel mill were close to collapsing.
With the new investment from the Wallenberg-led consortium, Stegra says it will now ramp up construction activities following several slower months during its fundraising period. As of last fall, the plant was 60% complete.
The company says the project’s timeline is now “under review,” though Stegra CEO Henrik Henriksson said it will take about 18 to 24 months to start producing steel once the facility is finished, the Sweden Herald reported.
Before its financial woes began last fall, Stegra was planning to complete the steel mill by late 2026.
“As an industrialist, you get a little sad if you come up to Boden now, because there is a half-finished steel mill that is running at perhaps a quarter of the speed it should be running,” Leif Johansson, an adviser to the investor consortium, said at a press event this week. The funding lifeline should change that.
The news comes four months after the European Union’s world-first carbon border tax went into effect. The policy makes it more expensive for European companies to import steel from countries that don’t have carbon-pricing systems, like the EU does, all of which should benefit domestic low-emissions steel producers like Stegra.
“We are convinced of the competitiveness of Stegra and the commercial attractiveness of green steel in addition to the climate benefits, while remaining clear-eyed about the challenges that lie ahead,” Johansson said in a separate statement. “We also consider the project to be of great importance to Sweden’s position as an industrial nation.”
Green steel proponents applauded the news of Stegra’s financing round, which is expected to formally close in June after undergoing credit and regulatory approvals.
“Stegra securing the future of its Boden green steel plant is a welcome development that signals the change towards truly clean steelmaking at scale is happening,” Caroline Ashley, executive director of the nonprofit SteelWatch, said in an emailed statement.
Xcel Energy in Minnesota is poised to become the first utility in the nation to build and operate its own virtual power plant.
For the past six months, fans and foes have debated the novel plan, which will see Xcel deploy hundreds of megawatts of small-scale batteries at customer sites across its territory. The Minnesota Public Utilities Commission ultimately approved a version of Xcel’s plan last week.
Under the new program, known as Capacity*Connect, Xcel will spend up to $430 million to deploy up to 200 megawatts of batteries, in 1-megawatt to 3-megawatt increments, over the next two years. It’s a rare arrangement: Almost every other virtual power plant program in the U.S. is organized around third-party companies, like solar and battery vendors or specialized “aggregators,” that tap into energy resources installed and owned by customers.
VPPs, which aggregate distributed energy resources to mimic the output of a traditional power plant, are seen as a key way to get more energy onto the existing grid. By using customer-owned energy resources or small-scale batteries, VPPs can help utilities reduce the need to build or dispatch expensive power plants.
But utilities have been slow to embrace VPPs. In particular, they’ve struggled to use VPPs to avoid grid investments, which have become a key driver of rising electricity costs. Utilities are leery of relying on technologies in customers’ homes instead of equipment they control. And utilities earn guaranteed profits for investments in their grids, giving them an incentive to resist examining cheaper alternatives.
Supporters of Xcel’s VPP program say it could finally provide a durable model for utilities to use distributed energy resources to defer costly grid investments and to more fully utilize the existing grid.
For one, the structure gives Xcel an economic incentive to recoup its investment. But more important, it requires Xcel to establish a metric to assess the value that distributed energy resources bring to the grid — something utilities have historically struggled to measure. If Xcel can create a template, then it will have removed a major stumbling block for broad adoption of VPPs.
“Putting a value on DERs of different types and capabilities to avoid or defer distribution upgrades is a real opportunity — and it’s really hard,” said Will Kenworthy, Midwest regulatory director for the nonprofit Vote Solar. “Xcel has said, ‘We need to put a value on this.’ And the way this program is set up, they have an interest in getting that right in a way they never have before.”
That’s not to say supporters think Xcel’s Capacity*Connect program should be the only VPP option in Minnesota. Many, including Vote Solar, have pushed for the utility to allow third-party companies to participate in the program. Some have expressed disappointment that the commission failed to do so, and there’s still no way for solar installers, battery vendors, and demand-response aggregators to enlist their own customers to help the grid in Xcel’s Minnesota territory.
And plenty of industry groups were outright opposed to the commission’s decision last week. The Minnesota Solar Energy Industries Association, Solar Energy Industries Association, and Coalition for Community Solar Access all criticized the plan and the lack of a third-party program.
As Andrew Linhares, Midwest director of state affairs at the Solar Energy Industries Association, said in a statement, “Competitive markets for energy storage deployment ensure that ratepayers get the best, most affordable deal possible. The Capacity*Connect program takes the exact opposite approach.”
The genesis of Xcel’s Capacity*Connect program is a bit unusual.
It didn’t originate in a broader policy push for VPPs but instead came out of Xcel’s integrated distribution planning. Minnesota’s Public Utilities Commission created that regulatory structure in 2018 with the goal of getting investor-owned utilities to “maintain and enhance the safety, security, reliability, and resilience of the electricity grid, at fair and reasonable costs.” Integrating DERs into the grid is one way to do just that.
But integrating DERs into utility planning processes is a whole new territory. Utilities, Xcel included, have not factored these technologies into how they plan out and spend money on their power grids. This means VPPs can’t yet specifically help offset distribution grid investments.
Instead, almost all existing VPPs target reducing peak electricity demand across utilities’ or grid operators’ entire service territories, as “bulk system” assets, Kenworthy said. That can — and does — save money by replacing the energy that would otherwise come from costly “peaker” power plants. That’s helpful, but it’s solving a different problem than distribution grid costs.
Using batteries and other DERs to relieve local grid constraints is a lot more technically challenging than relying on them to shave power demand during peaks. Utilities need to know exactly what stresses are happening at individual substations and distribution grid circuits from minute to minute. And they need far more confidence that the DERs will respond reliably and consistently to relieve those constraints in order to prevent overloads or blackouts.
Beyond a handful of pilot projects in California, Connecticut, Massachusetts, and New York, very few utilities have begun to experiment with using customer-sited DERs to relieve these kinds of pinpoint grid challenges. “We don’t have a way to do third-party substations,” Kenworthy said.
Xcel Energy spokesperson Kevin Coss said that the utility will work with local businesses, commercial and industrial sites, and nonprofits to install batteries “at strategic locations on the grid” to begin to test how each battery can mitigate local grid constraints. “These batteries will help meet increasing demand for electricity, maintain reliable service for our customers, maximize the efficiency of existing infrastructure, and support local jobs.”
Xcel Energy’s plan for paying for those batteries blurs the distinction between bulk-system and distribution-level values, as the utility’s batteries will serve both functions.
Xcel’s Capacity*Connect batteries will earn revenues for the bulk-system energy and capacity services they provide for the Midcontinent Independent System Operator (MISO), the entity that manages the transmission grid and wholesale energy markets across Minnesota and all or part of 14 other Midwestern states.
Those revenues will allow Xcel to pay back almost the entire cost of deploying the batteries, said Will Nissen, director of policy at the Minnesota-based Center for Energy and Environment, a nonprofit that’s in favor of the program. The utility has estimated that the batteries’ deployment and associated software development to manage them will add from 67 cents to $1.50 per year to a typical residential customer’s utility bill through 2030.
That’s key to the longer-term vision of using these batteries to avoid grid investment. Xcel has said it can’t start calculating the distribution-grid value of its batteries until it has had a few years to study them — the MISO revenues will fund this research.
Capacity*Connect will also get a $50 million investment from Google, as part of the tech giant’s broader deal with the utility to cover the energy needs of its new data center in the state.
“The beauty of this pilot is [that] it pays for itself with MISO revenues, while we learn about all the potential distribution value,” Nissen said. “It’s getting those bulk-system benefits while also studying how to use the distribution system as efficiently as possible.”
The commission ordered Xcel to establish specific estimates of the benefits that its batteries could provide to its grid by November 2027, when its next integrated grid plan is due, Kenworthy said. The commission also instructed Xcel to provide quarterly progress reports.
Vote Solar hopes that these provisions will drive the utility to “put a number on what avoided or deferred distribution investment is worth,” he said. “And we can take that to other forums where we’re trying to value DER and say, ‘This is what this device is worth, if we can do that thing.’”
Not all the stakeholders who have weighed in on the Capacity*Connect proceedings are as confident in that outcome, however.
“We really see this decision as a missed opportunity,” said Shannon Anderson, policy director at the nonprofit Solar United Neighbors, which is part of a coalition sponsoring VPP legislation in multiple states. “There’s no reason you can’t do ‘both and’ here — do what Xcel proposed and do a behind-the-meter VPP program.”
In fact, Public Service Co. of Colorado, Xcel Energy’s utility in that state, is currently rolling out a VPP program that will pay third-party companies that equip customers with batteries, smart thermostats, smart water heaters, smart heat pumps, and EV chargers, Anderson said.
In last week’s decision, the commission did order Xcel to report on how its experience in Colorado could apply to its work in Minnesota. But the commission declined to take up a proposal from a group of stakeholders that wanted it to order the utility to lay out a plan for doing something similar.
Nor does it seem likely that Minnesota’s legislature will order the commission to push Xcel to create a VPP program in the near future, Anderson said. Efforts to pass a VPP bill faltered last year, and similar legislation introduced this year has not passed out of a key committee, she said.
But VPP proponents are not giving up, Anderson said. “There are a number of filings coming, a lot of paperwork to evaluate and justify the program,” she said. “This is just the beginning of the conversation from our perspective.”
Tropical forests span 1.6 billion hectares (6.2 million square miles) of Earth. These ecosystems support a majority of the planet’s animal and plant species and contain plants that contribute to over a quarter of modern medicine. But over the past two decades, an average of 10 million hectares (nearly 40,000 square miles) of these forests—roughly the size of Kentucky—have been lost each year, according to the United Nations Environment Programme, affecting the ecosystems and communities that depend on them.
NASA scientists recently developed a new method for tracking tropical forest loss that delivers deforestation alerts more than three months faster than current methods. Although the technique was designed for the Amazon rainforest, data from a recently launched satellite are expected to expand its application globally.
July 22, 2020
Because tropical forests are so vast, local communities, conservationists, and policymakers rely on satellite data to manage them. Images acquired by satellites with optical sensors provide highly accurate alerts. For instance, the image above, acquired as part of the Harmonized Landsat and Sentinel-2 (HLS) project, shows newly cleared land in southwest Brazil in July 2020. Images from NASA-USGS Landsat satellites have revolutionized land management for over 50 years. In 1988, Brazil developed one of its first satellite-based monitoring systems using Landsat data, which remains in use today.
Though Landsat is an invaluable tool for Earth observation, it has a critical limitation: clouds. As an optical satellite, it relies on reflected light and cannot observe the ground through cloud cover. This creates data gaps that are especially limiting in tropical regions, which are cloudy most of the year. In some areas, months can pass without acquiring a cloud-free image, hindering efforts to track and curb unregulated forest clearing.
To address Landsat’s cloud challenge, researchers at NASA’s Marshall Space Flight Center tuned into a different wavelength. Led by Africa Flores-Anderson, associate program manager for NASA’s Ecosystem Conservation Program, the team piloted a system for the Amazon that combines existing satellite-based approaches with cutting-edge radar data. The approach builds upon a platform developed by the Cardille Lab at McGill University.
Synthetic aperture radar (SAR) doesn’t require daylight or clear skies. To generate an image, SAR instruments beam radar signals at a surface and measure the signals that bounce back. SAR satellites use various ranges of radar wavelengths, or “bands,” to measure features on Earth’s surface. Over forests, the shorter wavelengths of the C-band scatter off treetops, but the longer wavelengths of the L-band can make it down to the ground.
This L-band is central to Flores-Anderson’s approach. Similar efforts favored C-band because it was more readily available than other SAR data. But when felled trees—along with their branches and leaves—are not removed right away, C-band’s shorter wavelengths are scattered by remaining debris, obscuring evidence of destruction. In contrast, L-band’s longer wavelengths can penetrate this material and reveal the damage. The new method is the first of its kind to automatically combine the user-friendly, intuitive images from Landsat and the consistent, detailed insights from L-band SAR data.
These visuals show the benefit of combining optical images and L-band SAR data. The patch of deforested land in southwest Brazil (top row) is overlaid with colors that represent the month that deforestation was detected (bottom row).
The left map shows that SAR detected two patches of forest loss in January (purple), three months earlier than optical sensors (middle map). The patches appear small because deforestation happens gradually, Flores-Anderson explained. At that point in January, only those areas had been cleared.
By April (green), optical sensors had detected forest loss across a wider area, shown in the middle map. These sensors collect images every few days, while the SAR data used in this study captured the area only once or twice a month. In this case, the optical satellites observed the change during a break in the cloud cover.
The map on the right shows how the new algorithm combines information from both types of observations. To increase accuracy, this algorithm confirms deforestation only if there are multiple, consecutive observations of forest loss. This view confirms deforestation as early as February, up to two months earlier than optical-only, and with much more certainty than the optical- or SAR-only approaches.
On average, the new method for monitoring forests spots felled trees within 16 days with exceptional accuracy, nearly eliminating false alarms. These detections can identify deforestation in very cloudy regions up to 100 days sooner than optical-only systems.
“In the tropics, it’s important to detect deforestation as soon as it occurs,” Flores-Anderson said. “If an image of a cleared forest isn’t available until the following year, the area may already be regrown, and deforestation will be missing from our data.”
For experts like Sylvia Wilson, the chief forest and climate scientist at Wilpa Capacity Development with nearly 20 years of global forest monitoring experience with the U.S. Geological Survey, adding L-band SAR to optical is a scientific game changer. “L-band SAR gives us the opportunity to see what optical doesn’t,” Wilson said. “But it’s not one sensor versus the other; the future is SAR plus optical."
The NISAR (NASA-ISRO Synthetic Aperture Radar) satellite, launched in July 2025, will drastically increase the feasibility of systems like Flores-Anderson’s by providing more frequent and comprehensive L-band SAR data. L-band data has been relatively scarce, with limited images only available in a few areas like the Brazilian Amazon. Once more NISAR data become publicly available, they will provide free, global L-band SAR every 12 days. Flores-Anderson’s system is already prepared to incorporate this data.
“It doesn’t matter which sensor we get data from—whether it’s optical or SAR—it automatically adds to our model,” Flores-Anderson explained. “As more NISAR data become available, we will have more accurate, faster detection of change.”
NASA Earth Observatory images by Michala Garrison, using MODIS data from NASA EOSDIS LANCE and GIBS/Worldview, the Harmonized Landsat and Sentinel-2 (HLS) product, and model data provided by Flores-Anderson et al. Story by Lena Pransky (EarthRISE) with Jake Ramthun (EarthRISE) and Madeleine Gregory (Landsat Project Science Support).
As carbon dioxide levels hit record highs, scientists are testing new ways to fight climate change by locking it up in our oceans. On assignment for Climate Central, Correspondent Ben Tracy explores groundbreaking experiments using “antacid” chemistry to expand ocean carbon dioxide (CO2) storage and keep it out of our atmosphere.
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