Back
Global demand for steel is rising, and with it, emissions from the coal-fired blast furnaces that churn out around 70% of the world’s supply. American steelmakers are less reliant on blast furnaces than other countries, but they are doubling down on plans to extend the lives of the handful still operating in the U.S.
As those same steelmakers plan new facilities, though, they are embracing a cleaner technology called direct reduced iron, or DRI, to purify iron ore, the first step in the production of primary steel.
The DRI process uses a high-temperature gas to remove oxygen from the ore. The remaining iron can then be added to a traditional basic oxygen furnace or, more commonly in modern systems equipped with DRI, to an electric arc furnace that can be powered by carbon-free electricity.
Most DRI plants operating today use natural gas, a fossil fuel primarily made up of planet-warming methane. But even those can produce 50% less carbon emissions than coal-fired blast furnaces — and if the technology can be paired with carbon capture or fueled instead by green hydrogen, carbon-free steel becomes a possibility.
While DRI facilities account for just 9% of global ironmaking capacity today, they comprise nearly 40% of what’s under development. The U.S., for its part, has only three DRI plants up and running — but every new ironmaking facility slated to be built in the country will use DRI. That includes South Korean automaker Hyundai’s planned DRI plant in Louisiana, which the company announced in March.
The technology for DRI has existed for more than half a century, but it’s made exclusively by two firms that few outside the industry have ever heard of: Midrex Technologies and Tenova. Now, as some countries seek to build steel plants that don’t burn coal, these two firms are poised to reap the benefits.
Midrex Technologies dominates the DRI market. The North Carolina-based company built the first U.S. plant using the technology in Portland, Oregon, in 1969.
“DRI has a bigger and bigger role to play in the energy transition. The long-term view for DRI is positive. Demand for DRI keeps increasing,” said Vincent Chevrier, Midrex’s general manager of technical sales and marketing. “It’s probably going to double, then triple, in the next 20 years.”
The other major manufacturer, Tenova — owned by the Buenos Aires-based Techint, with technology jointly developed with Italy’s steel giant Danieli — started making DRI technology at the turn of this century. With just a fraction of the market, the firm may be the underdog, but CEO Francesco Memoli sees an advantage.
Tenova’s technology can swap out natural gas for hydrogen without any modifications. While Midrex says its equipment needs only minor upgrades to optimize for hydrogen, Tenova said the innate flexibility of its system allows it to ride out whichever way the political tides turn in the U.S.
Lately those tides have been turning against green steel.
In January, just before President Donald Trump’s inauguration, the Swedish steelmaker SSAB bowed out of negotiations for $500 million in federal funding the Biden administration had put up to support a DRI plant powered entirely with green hydrogen in Mississippi.
Cleveland-Cliffs — considered the more progressive of the American steelmakers — has suggested it would abandon its plans to build a DRI facility and use hydrogen to produce steel at its Middletown, Ohio, plant as it renegotiates the $500 million grant it had been awarded with the Trump administration.
Weeks after Cleveland-Cliffs started backing away from the project, Nippon Steel secured Trump’s approval to take over American rival U.S. Steel. The Japanese behemoth, the world’s fourth-largest steel producer, lags so far behind other companies in developing a decarbonization plan that the watchdog group SteelWatch recently described Nippon as “a coal company that also makes steel.” While Nippon has pledged to build a new electric arc furnace, a machine that uses electricity to turn scrap metal into fresh steel, the company has also staked out plans to extend the operations of U.S. Steel’s existing blast furnaces.
Meanwhile, Republicans in Congress have proposed eliminating the federal tax credit meant to spur green hydrogen production, which would create yet another setback.
In the near term, most of the new DRI plants in the U.S. will likely run on gas, Memoli said.
“Natural gas is very accessible in the U.S.,” he said.
Already, Tenova can capture some of the emissions from the gas it uses. Steelmaker Nucor deploys Tenova equipment at its plant in Louisiana, which last year set a world record for DRI production. In 2023, Nucor inked a deal with Exxon Mobil Corp. to capture and store the carbon from the steelmaker’s DRI process.
In Mexico, the Latin American steelmaker Ternium funnels CO2 captured from Tenova’s DRI equipment to Coca-Cola, Memoli said. Tenova puts the gas through two rounds of cleaning until it’s safe for use in beverages, and sells it to another company that in turn supplies the CO2 to Coca-Cola.
“All of the soda produced in Mexico by Coca-Cola is using CO2 recycled from an ironmaking plant,” Memoli said. “The joke is that Mexican Coke tastes better because of that.”
While the CO2 emitted by the DRI process is captured in the Tenova system, Memoli said the carbon produced from heating the gas to 1,000 degrees Celsius remains a source of pollution. The company is planning to roll out new features in the next few years to capture even that “residual” CO2.
Elsewhere, the company’s equipment is already running on hydrogen, or will be soon.
Last year, a major Swedish green metal project selected Tenova’s technology to generate iron with 100% hydrogen for the steelmaking giant SSAB. The fuel is gaining ground in China, too, which lacks domestic gas resources. Tenova-equipped plants in the world’s second-largest economy are already churning out 700,000 tons of iron per year using anywhere from 30% to 70% hydrogen, Memoli said, though only some of that hydrogen is green. The world produces about 2.5 billion tons of iron each year, for context.
Despite the headwinds for hydrogen-based steelmaking in the U.S., the industry could still move away from traditional steel plants (also called integrated plants because of their use of blast furnaces and basic oxygen furnaces) in the coming years. Industry analysts say DRI is the technology that will enable this shift — one that some say is critical both economically and for the climate.
“Blast furnace technology is outdated — full stop. It’s too dirty, it’s too energy intensive, and it’s too inefficient,” said Elizabeth Boatman, a lead consultant at 5 Lakes Energy, a Michigan-based research firm. “Overhauling our integrated mill fleet will be expensive, but it’s an investment that will pay off in the long term.”
Already, mini mills across the U.S. make use of the large volumes of scrap metal in the U.S. to produce lower-carbon steel than what coal-fired plants in China make fresh.
“What we are seeing, because of the switch of energy from coal, is that it offers the possibility of decoupling ironmaking from steelmaking,” said Midrex’s Chevrier. “You can place your ironmaking facility where the energy is cheap, and maintain your steelmaking facility at the location where your customers are and your scrap is.”
That could also create an opening for some of the startups looking to popularize next-generation ironmaking techniques. The Colorado-based company Electra, which aims to use a process called “electrowinning” to purify iron without a blast furnace, raised $186 million in April to support its scale-up. The Massachusetts Institute of Technology green steel spin-off Boston Metal, meanwhile, is inching toward its first commercial revenue.
Memoli said Tenova’s own research and development teams are working on similar technology. But he warned that it’s unlikely to be able to scale up fast enough in the near term to compete with DRI or blast furnaces.
A medium-sized blast furnace can churn out enough iron for 3 million tons of steel per year. A DRI plant can reach about 2.5 million tons. It’ll be decades before any of these newer electricity-based technologies reach that scale, Memoli said.
“The level of development of those technologies is still at a very early stage,” he said.
“We’re still talking about 20 years, 30 years from now. We need to be conscious of what are the targets and what are the deadlines today,” he added. “If we wait for something like that, the target of cleaning the planet will be pushed down and the cost of cleaning the planet will be much higher.”
Memoli said he wants to see more competition in the DRI space.
“Today there are only two companies – us and Midrex. Two is not enough,” Memoli said. “Not even four would be enough to develop all the projects that potentially could happen. Anybody with a green solution is welcome.”
Canary Media’s “Electrified Life” column shares real-world tales, tips, and insights to demystify what individuals and business owners can do to shift to clean electric power.
CENTENNIAL, Colo. — At a grassy city park this spring, professional landscapers sauntered between vendor booths, asking questions about the shiny new wares laid out before them: battery-powered push mowers, leaf blowers, string trimmers, chainsaws, and more. Some hopped on new standing and riding mowers to give them a spin.
Noticeably absent throughout it all was the scent and the roar of gas-guzzling equipment; the tools were all electric.
At the event hosted by the nonprofits Regional Air Quality Council and the Colorado Public Interest Research Group Foundation, landscapers were scoping out battery-powered tools to prepare for statewide regulations that kicked in this month. The first-of-their-kind rules, adopted in 2024, restrict the use of landscaping equipment with small gasoline-powered engines on public property during the summer — the state’s high-ozone season.
As you might guess from just a whiff of the noxious fumes, gas-fueled lawn and garden equipment are extremely polluting. Their combustion engines are a hazard not only to a stable climate, but also human health.
In 2020, nationwide, these machines belched over 68,000 tons of nitrogen oxides (NOx) and 350,000 tons of volatile organic compounds, according to the U.S. Public Interest Research Group Education Fund, referencing data from the U.S. Environmental Protection Agency. Together, the chemicals form lung-searing ozone, a key component of smog linked to respiratory problems and even premature death. The amount of NOx emitted by fossil-fueled lawn equipment is equivalent to the annual emissions from about 30 million cars, or more than a tenth of those registered in the country.
After personal vehicles and oil and gas operations, the third-largest source of ozone-causing pollutants in Colorado’s Front Range region is lawn and garden equipment, said David Sabados, spokesperson for the Denver-based Regional Air Quality Council, the lead air-quality planning agency for the area. These machines don’t have catalytic converters, he pointed out, so “they have an oversized footprint on our air-pollution problem.”
The Front Range, which includes Denver and Boulder, frequently exceeds federal air-quality standards for ozone — but it’s not alone.
Cities, counties, and states around the country are also pursuing cleaner air and quieter neighborhoods by limiting the use of gas-fired landscaping equipment, incentivizing electric options, or both. California has had a zero-emissions (i.e., electric) standard for newly manufactured leaf blowers, lawn mowers, and other small off-road engines sold in the state since 2024. Montgomery County, Maryland, banned the use of gas-powered leaf vacuums and blowers, effective July 1. And New York is considering a bill to deliver a financial boost to commercial landscapers who switch to electric tools.
Colorado’s new rules, called Regulation 29, don’t affect individual homeowners, but instead require landscapers who work on federal, state, municipal, and public school properties to use zero-emissions handheld tools and push mowers from June 1 through Aug. 31.
To keep grooming these grounds, contracted companies are replacing their gas gear with electric options as it wears out, which can happen in as little as three years.
Some landscapers say the switch has broad customer appeal. Certain clients prefer electric tools because they work from home and don’t want combustion equipment disrupting their calls. Others prize the environmental benefits.
“The community we serve is very Earth-conscious,” said Ed Johnson, division manager for landscape company Outdoor Craftsmen, which has transitioned two of its six maintenance crews to predominantly electric models. “There’s definitely been a desire” among customers, many in Boulder County, for landscapers to act as good stewards, he said.
Johnson added that it’s strategic to ease into electrification now rather than scramble to overhaul operations when stricter regulations come down in the future. This winter, the Colorado Air Quality Control Commission will weigh tighter restrictions on commercial landscapers working on private properties, The Denver Gazette recently reported.
Making the switch to electric equipment isn’t easy, though. Cost can be a barrier, a concern the industry raised when Regulation 29 passed last year.
“It’s a big investment for all the batteries,” said Brian Levins, manager at Designscapes Colorado, a landscape design, construction, and maintenance firm. “When you’re buying a battery, you’re basically prepaying gas for two years.” The company, which earned $45 million in revenue last year, has spent about $36,000 (after incentives) on handheld electric tools and charging gear for six of its 20 crews, he said.
Designscapes was able to take advantage of the 30% discount on electric lawn equipment that Colorado offers through participating retailers. Other landscaping firms have defrayed costs with grants from state and local agencies, such as Boulder County’s Partners for a Clean Environment program.
Another hurdle is figuring out how to keep the equipment charged.
Johnson has rigged up an equipment trailer with a portable power station from manufacturer Kress that can recharge batteries in as little as eight minutes. And Aurora, Colorado, landscaper Singing Hills has beefed up the electrical infrastructure at its home base to handle the added load from electrifying some of its equipment. That upgrade cost about $15,000, said Jake Leman, CEO of the 30-year-old company.
An added challenge to going electric is that gas versions are still more powerful for a couple types of equipment, like leaf blowers, Johnson of Outdoor Craftsmen said. But the electric tech “is coming along,” he noted. “It’s getting really, really close.”
Plus, electric landscaping equipment boasts a bevy of benefits. It’s safer for operators, who no longer have to breathe their tools’ fumes or go home with the stench clinging to their clothes. Leman has heard from some crew members that they enjoy being able to talk while operating an electric machine — uncomfortable to do over a firing engine — and they’ve praised the faster start up of electric tools compared with gas-powered options that require pulling a cord, he said.
The electric machines also require much less maintenance, Leman noted: “There’s not the filters and the belts and the fluids to change.” With savings on fuel and upkeep costs, Johnson estimated some of his larger equipment would pay back after 27 months of operation.
Some companies don’t have to deal with the challenging economics of replacing equipment. Jordan Champalou started his business, Electric Lawn Care, with primarily electric machines four years ago, when he was 19. “I enjoy not breathing in fumes all day,” he said.
He’s also able to save on energy costs and charge in between job sites using cheap renewable power from two solar panels he installed on the roof of the trailer in which he hauls his Stihl mowers, blowers, trimmers, and chainsaw. His leaf blowers are indeed less powerful than gas-fired versions, he said, but he’s found a solution: He slings two at once.
About a third of Champalou’s clients hire him because he uses electric tools, he said. “This year has been more than ever.”
Some commercial customers are now also breathing easier on landscaping days, says Levins of Designscapes. A few client buildings have ventilation systems that inhale air from close to the ground. With gas equipment, “we need to notify them before we go out there, because otherwise those fumes will get sucked into the air-intake [system] and distributed through the building,” he said.
Battery-powered zero-emissions tools don’t have that issue, Levins noted. “And those customers love that aspect of the electric equipment.”
As some state legislatures try to roll back clean energy measures, a successful policy for community solar in Minnesota has survived a political fight to end it.
Earlier this month, lawmakers ditched language from the state’s energy omnibus bill that would have terminated a successful state community-solar program in three years — and quashed the build-out of 500 megawatts of planned projects, according to advocates.
“I am absolutely thrilled that the community solar program will continue, [particularly] for the communities and individuals that will benefit from it,” said Keiko Miller, director of the community solar program at advocacy group Minneapolis Climate Action. “This really is a way of reducing household energy burden for those who have been left out [of the energy transition] traditionally, as well as increasing the availability of renewable energy resources.”
Minnesota’s Community Solar Garden program is crucial as the state aims to decarbonize its power system by 2040, Miller said. “There is absolutely no way we can get there without community solar being part of the portfolio.”
Community solar projects, which are typically up to 5 megawatts, make it easier for households to tap into the value of solar. Customers who might not be able to install photovoltaic panels on their own roofs, including renters and low-income families, can sign up for a shared solar project sited elsewhere, like on a community center’s roof or in a farmer’s field. Also known as community solar gardens or farms, they can guarantee subscribers a discount on electricity costs.
Minnesota was an early leader in the shared-solar approach, having started the state program in 2013. Last year, the North Star State ranked fourth in the nation for installed capacity with 939 megawatts, according to the National Renewable Energy Laboratory. That’s almost one-third of the state’s total solar capacity of 2.9 gigawatts.
The state revamped its solar garden initiative in 2023 to ensure that more households and lower-income customers would benefit from community solar projects. Lawmakers didn’t assign the initiative an expiration date at the time.
In late March, two Democrats and one Republican introduced Senate File 2855, a bill that would’ve sunset the community solar program in 2028. Senators then rolled the plan into their version of the energy bill.
Minnesota-based utility Xcel Energy supported terminating the program; in a March 26 hearing, a company representative criticized community solar as a costly way to deploy clean energy compared to utility-scale installations. Notably, companies other than utilities can develop community solar projects, and Xcel Energy doesn’t earn a profit on energy infrastructure it doesn’t own.
But the utility and other opponents aren’t accounting for community solar’s wide-ranging benefits, such as avoided transmission costs, the reduction in peak demand on the grid, and resilience, said Patty O’Keefe, Midwest regional director of national nonprofit Vote Solar.
In 2024, the Minnesota Department of Commerce, which oversees the state program, found that it’s expected to deliver $2.9 billion in net benefits over the next four decades. While the initiative is projected to increase bills by 2% to 3% for non-subscribers who aren’t considered low to moderate income, community solar is expected to lower energy bills for participating households by 3% to 8%.
Ultimately, lawmakers stripped the repeal language from the energy bill following pushback from community solar champions in the Legislature, including Democrats Rep. Patty Acomb, Senate Majority Leader Erin Murphy, and Rep. Melissa Hortman, O’Keefe said. (On June 14, Hortman and her husband were assassinated at their home in an act of politically motivated violence.)
Droves of supporters also helped save the state solar-garden program; they testified at hearings, marched, and protested, O’Keefe said. By her count, roughly 100 Minnesotans, including community solar subscribers, farmers, and clean energy advocates, called on legislators to reject the repeal.
The win for community solar in Minnesota comes as the broader solar industry — and the already-struggling rooftop solar sector in particular — faces serious federal headwinds. The Trump administration’s rapidly fluctuating tariffs and the looming repeal of solar and wind energy tax credits in the budget bill threaten to make solar more expensive to build. That could throw cold water on the record-breaking pace of solar deployment the U.S. has experienced in recent years.
But in Minnesota, at least, a major source of clean energy endures.
“This is a victory for the community solar movement,” O’Keefe said. “It just shows that even with a … forceful effort to try and repeal the entire program, we had enough power between the public and clean-energy champions to fight it back — and really send a message that Minnesota benefits from community solar.”
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
The Senate Finance Committee released its portion of the “Big, Beautiful Bill” on Monday, including highly anticipated plans for clean energy tax credits that the House’s version sought to repeal. Here’s what’s better off in the Senate text — which still could change — and what’s not looking so hot.
Solar and wind — sort of
The House version would require clean power projects to start construction within 60 days of the bill’s passage to access production and investment tax credits introduced under the Inflation Reduction Act. The Senate proposes a more gradual phaseout of credits for solar and wind projects before they terminate entirely at the end of 2027. Certain wind and solar projects would be able to access the tax credits beyond that point, as long as they are at least 1 gigawatt, are on federal land, and have already earned right-of-way approval from the Bureau of Land Management. But as Heatmap notes, those exceptions are unlikely to help any projects already in development.
Utility-scale battery storage
Incentives for energy storage projects would’ve ended just like those for wind and solar under the House bill, but that’s changed in this version. The Senate specifically says battery storage projects can access those production and investment tax credits until 2036, though the value of the incentives will taper over the years.
Geothermal, hydropower, and nuclear
Nuclear power was notably spared in the House’s gutting of clean energy incentives, but it got a few new friends in the Senate iteration. Like battery storage and advanced nuclear, geothermal and hydropower projects will be able to tap 45Y production tax credits until 2036.
EVs
The $7,500 tax credit for new EV purchases would end about six months after the legislation is signed, while the $4,000 incentive for used EV purchases would end in three. The House extended that rebate for new EVs through 2026 for some emerging automakers, but the Senate didn’t carry over that same exemption.
Home energy improvements
Homeowners would only be able to get tax credits for rooftop solar installations for 180 days after the bill’s passage. Rebates for home energy upgrades, including to help homeowners buy electric heat pumps and other efficient appliances, will also be phased out in 180 days.
Hydrogen
The IRA’s green hydrogen production credit will only be available to projects that start construction this year, and after that, would end immediately. That cut would be brutal for the already-struggling industry, Canary Media’s Julian Spector reports.
While the Senate’s proposal steps back some from the House version, tax credits that directly benefit consumers remain the most at risk. And as many experts have warned, those slashed tax credits will put jobs, energy bill savings, and major clean power projects at risk.
Still, these changes aren’t set in stone. Once the whole bill is drafted, the Senate will have to actually pass it, and then reconcile its differences with the House, with an ultimate goal of getting the package on President Donald Trump’s desk by July 4. His signature would start the clock ticking on all those tax credit phaseouts.
A wave of community solar wins
The skies are cloudy for clean energy, but community solar is still providing some bright spots.
In Delaware, power will soon begin flowing from a 4.7-megawatt array that will help power as many as 750 homes and small businesses. It’s the first of six projects planned across the state to help locals — especially renters and low-income residents — tap into cleaner power, WHYY reports.
More community solar is on the way in the Northeast. A developer broke ground this week on a 3-MW array in Glastonbury, Connecticut, that’s part of a raft of projects across the region. And in New Jersey, lawmakers advanced a bill that would expand the state’s community solar capacity by 50% in an attempt to help curb power bills.
Meanwhile in Minnesota, the preservation of a community solar program will stand as a piece of state Rep. Melissa Hortman’s lasting legacy on clean energy. Hortman, a Democrat who was assassinated in her home last weekend, played a pivotal role in passing the state’s clean electricity standard and updating a community solar program in 2023. More recently, she pushed to keep the repeal of that program out of the state’s energy omnibus bill passed earlier this month.
Renewables still win: Renewable electricity is cheaper than power produced by fossil fuels, even without government subsidies, though low gas costs and rising prices for renewables threaten the clean energy buildout, an investment bank’s annual report finds. (E&E News)
Energy research deep freeze: Federal employees say Trump administration funding cuts and freezes are making it impossible for EPA scientists to publish research, for Energy Department employees to visit the agency’s labs, and for other energy and environmental staffers to conduct critical work. (Politico)
Fossil fuels financed: The world’s largest banks increased financing for fossil fuel projects between 2023 and 2024 despite their climate commitments, reversing several years of shrinking financial support for coal, gas, and oil projects. (The Guardian)
Another blow to wind: Anti-wind activists say they’re looking to build on the implosion of a Maine floating offshore wind project as they push the Trump administration to revoke a grant for a similar project in Northern California. (Canary Media)
Pricing out gas: Maryland residents who want new gas service will now have to pay for the connection, as public utilities regulators decide the old system of free or reduced-price hookups is at odds with the state’s climate goals. (Baltimore Sun)
Nuclear goes nationwide: State lawmakers across the U.S. have filed more than 200 bills related to nuclear energy this year, with dozens going into law as states look to meet rising power demand. (E&E News)
Senate Republicans released a draft budget on Monday that presents a slightly less draconian prescription for clean energy tax credits than what the House had put forth.
In May, House Republicans voted to slash all the clean power credits, with some favorable treatment for nuclear plants. The Senate took a more nuanced approach, doing away with credits for cheap but intermittent resources, while continuing to incentivize projects that can generate power on demand.
The Senate version would crank down investment and production tax credits for wind and solar power starting in 2026, reducing them to zero by 2028. But the Senate Finance Committee threw a lifeline to other zero-carbon power plants, allowing hydropower, geothermal, and nuclear to keep their full credits until 2033. Crucially, energy storage was included in that group, which could help grid batteries keep their meteoric growth streak going.
This effort to continue supporting “firm” power sources, which provide energy even when the sun isn’t shining and the wind isn’t blowing, could be hugely consequential for America’s ability to meet spiking demand for electricity. Companies are racing to build new power plants to serve AI computing and domestic manufacturing (two avowed priorities of the Trump administration), not to mention the widespread electrification needed to address climate change.
The problem is, nuclear construction has stagnated since the woefully delayed and over-budget Vogtle expansion; hydropower has been essentially frozen for decades; and geothermal is just starting to gain traction thanks to a handful of startups developing new technologies.
Of the Senate’s chosen few, batteries are the only contender showing real dynamism in energy markets: In just a few years, they’ve jumped from the margins to become the second-biggest source of new power capacity added to the U.S. grid each year, after solar. Energy storage dominates the queues of projects waiting to hook up to the grid in the next few years in places like California and Texas.
The Senate still needs to debate this proposal and see if it rallies enough votes to pass. Then the Senate and House will have to reconcile their differences. There’s no way to know if the current Senate language will become the law of the land.
Nonetheless, this proposal changes the political landscape for clean energy advocates, by splitting clean energy into winners and losers. It also tacks on requirements around foreign influence that seem conceptually more workable than the House’s “poison pill” approach, but that could still thwart actual construction.
The idea of excluding wind and solar from receiving credits has been percolating over the last few months, though it was easy to miss in a generally turbulent news cycle. In April, U.S. Rep. Julie Fedorchak, a Republican from North Dakota, introduced a bill that she dubbed the “Ending Intermittent Energy Subsidies Act.”
“Wind and solar are no longer emerging technologies—they’re mature, market-proven, and widely deployed,” Fedorchak said in a statement at the time. “As all the grid operators are saying, we need more dispatchable resources. We must stop providing generous incentives that run contrary to that.”
The legislation didn’t get much attention at the time, and Fedorchak’s House colleagues yanked support from several of the dispatchable options anyway. But she had some historical facts on her side: Wind and solar have enjoyed federal tax structures since the George W. Bush era (incentives for wind actually go back further), when they emerged as a broadly supported Republican energy policy. Storage didn’t get its own tax credit until the Inflation Reduction Act kicked in for 2023. The technology is clearly the newest of the major power-sector players (excluding the nonexistent nuclear fusion and small modular reactor projects).
On June 3, a cohort of clean, dispatchable power providers chimed in on the debate with a letter noting that they can offer exactly the kind of on-demand power Republican senators seem to appreciate.
“Nuclear energy, geothermal, hydropower, and energy storage stand ready to deliver that reliable power,” said the group, which included novel storage startups Form Energy and Hydrostor, along with geothermal, nuclear, and hydro firms. “We believe it is possible to advance genuine deficit reduction without sacrificing the reliable, innovative power that American households, businesses, and national security require.”
They never said to throw wind and solar under the bus, but emphasized the particular value in keeping credits for dispatchable resources as senators decided where to cut spending.
The House, besides greatly shrinking the timeline for clean energy tax credits, tacked on new requirements that industry insiders decried as impossible to fulfill. The language would block incentives for projects that include any components from a “prohibited foreign entity,” legislative jargon which basically means companies in China. The state of globalized supply chains makes it effectively impossible to build a power plant with that constraint.
The Senate shares the concern about tax credits accruing to Chinese companies, but handled it differently. In its version, the company filing for tax credits cannot be literally or effectively controlled by prohibited foreign entities — that’s a test that U.S.-based developers should, in theory, have no trouble passing. But the text gets very specific on what kinds of arrangements could constitute “effective control” of a project, and calls for the Treasury secretary to issue guidance on how to qualify. That creates ample opportunities for U.S.-controlled storage companies that fulfill the spirit of the law to run afoul of certain sub-clauses.
Additionally, developers must spend a certain amount of the total project cost on products that are not from “foreign entities of concern.” The ratio starts at 40% in 2026, and increases annually from there. Lithium-ion batteries still largely come from China; if a project has to buy those, but can secure the remaining equipment for the power plant from the U.S., they may be able to hit the right ratio. On paper, this rule seems more achievable than the House version, which would penalize firms that use even small, low-value pieces like bolts or cables that originate from China, rather than focusing on critical, high-value components.
Of course, tax credit compliance is the province of well-paid lawyers, who would need to translate the details of the Senate language into actionable legal guidance for companies. The clean energy industry is still reeling from yearslong rulemakings at the Internal Revenue Service that held back many of the investments championed by the Biden administration. Today, the Trump administration has winnowed civil service staff and actively opposed clean energy; it’s hard to imagine IRS rulemaking moving more swiftly under those circumstances.
Storage developers are frantically running the numbers on whether their power plant designs can stay within the guidelines for foreign components, so that they’ll qualify for the tax credits. They also need their financiers to feel confident that they will. Highly prescriptive legislative interference in a high-tech business landscape complicates that process, and could cause investors to pull back until the dust clears.
That’s not to say battery construction will come to a halt without workable incentives. It’s arguably the only dispatchable technology that can be built quickly in the next few years. But saddling the credits with additional bureaucratic requirements would inject extra costs and delays into the industry, at a time when the U.S. desperately needs all the on-demand power it can get.
Former Minnesota House Speaker Melissa Hortman is being remembered by advocates and lawmakers as one of the most important climate and clean energy leaders in the state’s history.
From the state’s trailblazing community solar program to the flurry of energy and environmental laws adopted during Democrats’ 2023 trifecta, Hortman had a hand in passing some of the country’s most ambitious, consequential state-level clean energy policy during her two-decade legislative career.
Hortman, who was a Democrat, and her husband Mark were shot and killed in their suburban Minneapolis home Saturday in what authorities say was a politically motivated assassination. The alleged gunman, Vance Boelter, is also charged with attempted murder for shooting Democratic Minnesota state Sen. John Hoffman and his wife Yvette.
Hortman, who was 55 years old, twice tried for a state House seat before finally winning in 2004. Moving through the ranks of House leadership, the attorney served as speaker pro tempore, deputy minority leader, and minority leader before becoming speaker in 2019 and serving in that role for three legislative sessions.
“Clean energy was her first love,” said Michael Noble, who worked with Hortman for more than 20 years during his time as executive director of the Minnesota-based clean-energy policy advocacy organization Fresh Energy. “She really mastered the details and dug deep into climate and clean energy.”
Hortman chaired the House Energy Policy Committee in 2013, a standout year for solar policy in which she helped pass legislation establishing one of the country’s first community solar programs, and also a law requiring utilities to obtain 1.5% of their electricity from solar by 2020, with a goal of 10% by 2030.
“That was the year we put solar on the map,” Noble said.
Community solar advocate John Farrell recalled answering Hortman’s questions in detail concerning the benefits and drawbacks of community solar during meetings. She was preparing to defend the bill and convince others, even Republicans, that it could be something they could support.
“She wasn’t going to tell them something untrue,” said Farrell, who directs the Energy Democracy Initiative at the Institute for Local Self-Reliance, an advocacy group. “She was going to seek reasons why this policy might be something that they would care about or that it might align with their values.”
Nicole Rom, former executive director of the Minnesota-based youth climate advocacy group Climate Generation, said Hortman was committed to educating herself on climate issues. Hortman attended the United Nations’ Conference of the Parties (COP) climate conferences and was part of the University of Minnesota’s delegation at the 2015 Paris climate talks, where her vision for more ambitious state climate goals and policy may have begun to percolate, Rom said.
The result was the strong climate legislation Minnesota accomplished in 2023, Rom said.
“If she never served a day before or a day after the 2023 session, she would still go down in history as an incredible leader,” said Peter Wagenius, legislative and political director of the Sierra Club’s Minnesota chapter.
After Democrats won control of the state House, Senate, and governor’s office in the 2022 election, Hortman understood the trifecta was a rare opportunity that may not arise for another decade, he said.
The following year, Hortman combined her skills and experience as a legislator, committee chair, and political leader to push forward an agenda that would fundamentally transform clean energy and transportation in Minnesota while solidifying her reputation as one of the legislative body’s greatest leaders.
The session’s accomplishments included a state requirement of 100% carbon-free electricity by 2040, along with more than 70 other energy and environmental policy provisions that created a state green bank, funded renewable energy programs, supported sustainable building, and increased funding for transit. Other laws passed that year required the state to consider the climate impacts of transportation projects, provided electric vehicle rebates, revised the community solar program to focus on lower-income customers, and improved grid-interconnection bottlenecks.
When the trifecta arrived, she ensured her colleagues were “ready to move on a whole list of items in an unapologetic way,” Wagenius said. Hortman also practiced “intergenerational respect” by elevating and helping pass laws proposed by first- and second-term legislators, he said.
Democratic Rep. Patty Acomb said Hortman empowered others within the party, made legislators feel they were “like a team,” and had a habit of never taking credit for legislative success. “She shied away from that,” Acomb said.
Acomb, who began serving in 2019, became chair of the House Climate and Energy Finance and Policy Committee four years later. She credits Hortman with that opportunity and with making Minnesota a national leader in clean energy.
“In so many ways, she was a trailblazer,” she said.
Gregg Mast, executive director of the industry group Clean Energy Economy Minnesota, said Hortman followed up on the historic 2023 session with a 2024 legislative agenda that built upon the previous year’s success. The Legislature made the permitting process for energy projects less onerous while passing a handful of other measures promoting clean buildings and transportation.
“She knew that ultimately, to reach 100% clean energy by 2040, we actually needed to be putting steel in the ground and building these projects,” Mast said.
Ben Olson, legislative director for the Minnesota Center for Environmental Advocacy, first met Hortman 20 years ago while lobbying for an environmental bill. He found her to be kind, witty, and pleasantly sarcastic, the kind of legislator who asked questions, closely listened to responses, and offered sage advice. “Everyone liked her, and she was close to everybody who had spent time with her,” he said.
Ellen Anderson, a former Democratic state senator and clean energy champion, remembered when Hortman asked if she could co-teach a course with her on climate change at the University of Minnesota in 2015. Hortman came prepared for classes with notebooks of data and information. “She was super organized,” Anderson said.
Rom thinks Hortman’s love for nature drove her climate and clean energy advocacy. The legislator loved hiking, biking, gardening, and other outdoor activities.
In a blog post for Climate Generation before attending the UN’s 2017 climate conference, Hortman wrote about the impact of climate change on trees and how she had planted nearly two dozen in her backyard to offset her family’s carbon emissions. It was a message not lost on her two children, Colin and Sophie, who suggested in a statement that people commemorate their parents by planting a tree, visiting a park or trail, petting a dog, and trying a new hobby.
“Hold your loved ones a little closer,” they wrote. “Love your neighbors. Treat each other with kindness and respect. The best way to honor our parents’ memory is to do something, whether big or small, to make our community just a little better for someone else.”
This week, Senate Republicans joined their House colleagues in proposing to curtail a slew of clean energy incentives. Losing those could upend many a clean energy business, but the cuts would drive a dagger through the heart of the burgeoning green hydrogen sector in particular.
The Senate and House still need to agree on the final text of the bill, but both chambers would take a decade of incentives meant to incubate green hydrogen production and end them after this year. The truth is, though, even before Republican lawmakers sharpened their knives for the tax credit, the much-anticipated green hydrogen boom had quietly collapsed.
Just a few years ago, green hydrogen developers were planning to invest billions of dollars to build gigawatts of wind and solar capacity in prime locations from the Gulf to the desert Southwest, then funnel that electricity into huge banks of electrolyzers. These devices zap water and deliver pure hydrogen gas without the carbon dioxide released by conventional hydrogen production. Ambitious dreamers even proposed billion-dollar pipelines to carry the gas across Texas to ports on the Gulf, where it could be shipped to buyers in Europe and Asia.
I caught a bit of hydrogen fever myself during a reporting trip along the Gulf Coast in December 2023.
In Mississippi, leaders from a company called Hy Stor Energy showed me a vast sandy tract, framed by mastlike pines, where they intended to build a clean industrial park powered by gigawatts of off-grid wind and solar. These power plants would electrolyze hydrogen, which Hy Stor would stash in enormous subterranean storage tanks carved from the region’s salt dome formations. Then steelmakers and chemicals companies would flock there for an uninterrupted supply of undeniably clean hydrogen.
Sure, it sounded bold, but not impossible: Hy Stor’s then-CEO Laura Luce had previously developed salt dome storage for natural gas, and elsewhere in the region, salt dome tanks already store hydrogen molecules for the Gulf petrochemical corridor.
By October 2024, though, Hy Stor had canceled a contract to buy over 1 gigawatt of alkaline electrolyzers from Norwegian cleantech company Nel, and the company’s leadership had moved on, per their LinkedIn pages. (When I texted a former Hy Stor leader to request comment for this story, the phone number’s new owner told me they had nothing to do with the company. A few days later, they texted me again asking if I could give them $20.)
Other firms have canceled projects partway through construction, are holding off on final investments, or have found new customers for their renewables. A few green hydrogen projects are still moving forward, but they’re either in jeopardy, heading overseas, or far more modest than the gigawatt-scale ventures recently under development.
“I think it is overstating it to say [green hydrogen] is dead,” said Sheldon Kimber, whose firm Intersect Power spent years developing ideal wind and solar sites for hydrogen production, before pivoting to supply clean energy to data centers. But, he added, projects that get built in the next few years are likely to rank in the tens of megawatts, not the thousands, and focus on “small-volume, high-margin markets.”
Plug Power stands out as the rare company still building substantial non-fossil-fueled hydrogen production in the U.S. It recently finished a site in St. Gabriel, Louisiana, that can liquefy 15 metric tons of hydrogen daily, bringing its total production capacity to 40 metric tons per day. The company claims it runs the largest liquid-hydrogen production fleet in the nation.
Plug, however, serves as an inauspicious standard bearer for the U.S. green hydrogen industry. The 28-year-old company reported an accumulated deficit of $6.8 billion as of late March, meaning its cumulative losses outweigh any profits by that hefty amount. In February 2021, CEO Andy Marsh raised a warchest of $5 billion to build 500 metric tons per day of green hydrogen production by 2025; the stock traded above $60 a share at that time. Plug burned through that cash and completed just a sliver of the production goal. Currently, its stock trades at just over $1. (A company spokesperson did not respond to requests for comment.)
Plug Power and other hydrogen developers attracted billions of dollars from investors on the promise that success was just around the corner. Now, though, the hydrogen build-out has collapsed under the weight of several interlocking burdens. Self-defeatingly slow federal rulemaking on tax credits, soaring production costs, a dearth of major industrial buyers, and AI’s insatiable demand for power hobbled green hydrogen construction well before the Trump administration decided to go for the jugular.
The late 2010s were a euphoric time for clean energy developers. Renewables construction shot forward despite President Donald Trump’s 2016 campaign vows to bring back coal. Low interest rates paired nicely with the low but predictable returns that renewables projects could generate. Entrepreneurs imagined ways to capitalize on the imminent abundance of clean electricity by converting it into hydrogen.
The Covid-19 pandemic slowed the pace of activity, but then the Biden administration passed the 2021 infrastructure law, which designated $7 billion for a series of “hydrogen hubs” around the country. The administration chased that with the Inflation Reduction Act, which included a lucrative credit for the production of clean hydrogen, up to $3 per kilogram. A new multibillion-dollar industry was in the offing, and visionaries prepared to make their moves, as soon as the Internal Revenue Service published its guidance on how to claim that credit.
Then they waited. And waited.
“At $3 per kilogram, if your plant did not qualify for that and your neighbor’s plant did, then you’re out of business,” said Brenor Brophy, who ran development for Plug Power’s hydrogen production business in the early 2020s (he is no longer with the company). But there was no airtight way of ensuring one’s project would qualify until the final rule came out.
“The Treasury Department sat on that for two and a half years,” which was worse for the industry than if the credit were never created, Brophy added.
Paralysis seized the whole supply chain. Savvy suppliers chose a wait-and-see approach. This saved them money, at the expense of the communities they had promised to invest in.
Michigan Gov. Gretchen Whitmer (D), for instance, famously flew to Oslo to close a deal with Norwegian electrolyzer company Nel. That firm planned to invest $400 million to build a factory near Detroit, and gain $16 million in state funds for creating some 500 jobs. Nel has declined to make a final investment decision on the site. Despite that display of financial discipline, its stock was trading for pennies at the time of writing.
Plug Power, not afraid to be early to the party, went ahead and built a factory in Rochester, New York, in 2021 capable of fabricating 1.5 gigawatts of electrolyzers per year. That’s a big swing compared to today’s demand: Plug noted its Georgia plant, which it called “the largest liquid green hydrogen plant in the U.S. market” in January 2024, contains 40 megawatts of electrolyzers.
Biden’s Treasury Department didn’t release final guidance until days before Donald Trump moved into the White House. The new administration promptly held back funds appropriated by Congress for clean energy efforts and then set about dismantling the clean energy tax credit regime.
“Most of the pipeline will get abandoned if they cannot get a $3/kg subsidy,” said BloombergNEF analyst Xiaoting Wang. Some developers have put on a brave face and said they’ll plow ahead even without the tax credit, but she suspects such assertions are “more advertisement than a real business decision.”
Many of the planned hydrogen projects would have enriched solidly Republican districts, like Texas and Louisiana, the locus of legacy hydrogen production for petrochemical refining. But the prospect of self-inflicted economic pain has proven less of a deterrent for Republican lawmakers than industry insiders had hoped.
Project cancellations have continued amid the uncertainty. Major legacy hydrogen producer Air Products was supposed to build a $500 million green hydrogen production plant in Massena, in upstate New York. The company had cleared the 85-acre site and laid foundations to support 35 metric tons per day of green hydrogen electrolysis, per reporting by local outlet North Country Now.
But new CEO Eduardo Menezes took office in February, after an activist investor attacked the company’s green hydrogen strategy. Menezes promptly canceled Massena and a few other projects, incurring a cost of $3.1 billion for breaking contracts and writing down asset value. Burning that cash seemed preferable to actually finishing and operating those projects.
“Treasury was so effective at destroying the industry that it kind of seems malicious,” Brophy said.
Scaling breakthrough technologies requires faith that costs will fall and customers will want to buy. Elon Musk bet on that happening for electric cars, long before they were widely available to consumers. Solar evangelists dismissed predictions that their technology would never go anywhere; now solar is the fastest-growing new source of electricity production in the U.S. and the world.
Similarly, in that bright period before Biden-era inflation set in, hydrogen boosters saw a clear path to achieving cost declines akin to what solar and batteries had achieved. Legacy dirty hydrogen could be made for about $1 per kilogram; the green stuff cost several dollars more. But a technological learning curve could close that gap, the thinking went, and sway large industrial buyers. In 2021, the Biden Department of Energy set a goal to get green hydrogen costs down to $1 per kilogram within a decade.
Unfortunately, the cost declines that experts expected in the early 2020s never materialized. A late-2024 DOE report on clean hydrogen commercialization noted that costs had gone up, not down, by $2 to $3 per kilogram since its March 2023 analysis. The report cites higher real-world installation costs, rising interest rates, and escalating prices for clean power to meet the IRS requirements for the tax credit.
BloombergNEF analysts looked back at real-world installation costs for electrolysis plants built in 2023, and found they were 55% higher in the U.S. and Europe than the firm had predicted in 2022. Earlier estimates had assumed the core electrolysis equipment would drive most of the cost, but in practice, the seemingly incidental factors — like utility and contractor management, and contingency planning — inflated project costs considerably, Wang noted.
Researcher Joe Romm oversaw hydrogen efforts at the DOE’s Office of Energy Efficiency and Renewable Energy in the 1990s, and subsequently published a book-length critique, “The Hype About Hydrogen.” He reissued it this spring, just in time for the latest cycle of boom and bust.
“Electrolyzers aren’t like photovoltaic cells or battery cells,” he told me recently. “There’s no ‘then a miracle occurs’ thing. … If there was going to be a learning curve, we never got there.”
Solar panels and battery cells are identical units that get mass-produced economically. Electrolyzer systems require more hands-on and bespoke installation work, with pipes and pumps and compressors and water tanks.
The other problem with analogizing green hydrogen to wind, solar, and batteries is a key difference in their uses. The latter group delivers electricity, which is distributed and used across modern society. But clean hydrogen requires highly specialized infrastructure to transport and utilize the famously flighty molecule.
“Someone’s going to have to take a big gamble, and if they lose, they’re stuck with a stranded asset,” Romm noted. An electrolysis plant with no green hydrogen customers can’t do anything else. And would-be producers struggled to find any committed customers.
Michael Cembalest, chairman of market and investment strategy for J.P. Morgan Asset and Wealth Management, tallied the missing demand to damning effect in his annual global energy-market report from March (see slide 46). He calculated that only 1% of green hydrogen projects slated for completion by 2030 have a binding offtake agreement.
That’s not to say developers were crazy for trying. A few years ago, major companies in Asia and Europe seemed eager to purchase large volumes of green hydrogen for their decarbonization plans, said Kimber, from Intersect Power. Such high-volume deals were vital for justifying construction of gigawatt-scale electrolysis projects in the sunny, windy sites of the American West.
“We had plenty of negotiations for gigawatt and multi-gigawatt-scale hydrogen, but most of them were with European and Asian customers, and most of those folks have backed away from the table,” Kimber said. “Without that policy certainty, no large oil company, steel company, power company is going to move ahead purchasing green molecules globally.”
Lacking that kind of anchor customer, a developer can’t justify building big or financing a whole pipeline to market — the billion-dollar gigaprojects depend on high utilization to make any financial sense, Kimber noted. They’re not something you can build and then wait a few years for demand to materialize.
Electrolysis devours electricity, which is fine in a world of cheap and abundant power. But, suddenly, any fledgling hydrogen project has to compete with much better-funded rivals in electric gluttony: AI computing hubs.
The business calculus of clean hydrogen necessitated driving down energy costs as much as possible to compete with cheap dirty hydrogen. For green hydrogen ventures to succeed, they would need to render their product a cheap commodity.
AI customers, on the other hand, are flush with cash and willing to pay top dollar to anyone who could deliver them gobs of power as soon as possible.
“When you enable a more valuable product, the total pie of value for the supply chain to carve up is greater,” Kimber said. “That makes the whole process of dealing with your customer and your vendors and everybody just less of a fight to the death. Everybody can truly be focused on, how do we scale this industry?”
For clean energy developers like Intersect, then, the choice to swap customers was uncomplicated. They had scouted the most energy-rich acreage they could find, but the big buyers for green hydrogen never showed up, and suddenly the wealthiest tech companies in the world wanted to sign deals ASAP.
“We were never a hydrogen company,” Kimber said. “We have been, are, and will be a company that is focused on finding ways to use the massive surpluses of all forms of energy that exist in places like West Texas, the panhandle of Texas, to power new industrial loads.”
“Now, it’s very easy for us to pivot into data centers,” he continued. “We’re negotiating AI data centers on all of our large [hydrogen] projects right now.”
Plug Power CEO Marsh opened a quarterly earnings call in May by going on defense about the tax credit revisions proposed by congressional Republicans.
“My first reaction was, we’re going to have to work to start construction this year to make sure that that plant would qualify,” Marsh told investors, referencing a development in Texas.
Then, tellingly, he handed the mic to Chief Revenue Officer Jose Luis Crespo, who talked up the bounty awaiting across the Atlantic, saying “Europe today is the most dynamic electrolyzer market in the world.” The European Union’s binding hydrogen procurement rules will soon kick in, and electrolysis projects at the 100-megawatt scale are starting to move toward reality, he explained.
Instead of building gigawatts of electrolyzers in the U.S. to export hydrogen to Europe, investment might just flow there instead.
Other U.S. entrepreneurs hope to survive through a more targeted approach: building small but closer to customers. The U.S. already produces 10 million metric tons of hydrogen per year for industrial users; many of them are open to cleaner and cheaper options, said Matt McMonagle, founder and CEO of startup NovoHydrogen.
“There’s no pricing transparency in this market; it’s very opaque,” he said. “There’s no Henry Hub equivalent like there is for natural gas.”
Green electrolysis still can’t compete with the $1 per kilogram that it costs to make dirty hydrogen at huge petrochemical complexes with cheap natural gas. But companies that get smaller deliveries of super-cooled liquid hydrogen can pay anywhere from $5 to $50 per kilogram, depending on region and shipping distance, McMonagle explained.
“We try to focus on the ones where we can save the customer money,” he said, recalling prior experience selling solar and batteries to businesses that wanted to cut their utility bills. And, unlike so many giga-scale hydrogen projects, NovoHydrogen actually has signed offtake agreements. “There’s no project without a customer,” McMonagle noted.
Novo is developing 10-megawatt electrolyzer systems at customer sites, which can produce about 2 metric tons per day depending on uptime, McMonagle explained. These projects will hook up to the grid, drawing power via clean energy supply agreements from the local utility. By building on-site, Novo needn’t worry about constructing pipelines across hundreds of miles or driving a fleet of super-cold tanker trucks.
Novo’s bigger projects function more like community solar: They’re located off-site but still near customers. Novo intends to install 235 megawatts of solar production across 1,000 acres in Antelope Valley, at the outer reaches of Los Angeles County, and funnel that power into electrolysis. If it comes online as planned in 2028, this facility should make about 27 metric tons per day. That’s nothing close to the colossal projects other companies contemplated at the height of the boom times, but it’s still bigger than any single green hydrogen source in the U.S. today.
As McMonagle sees it, the lure of the $3-per-kilogram credit attracted maybe too much attention to hydrogen, beyond situations where it really makes sense.
“A lot of people may have been chasing a shiny object and didn’t understand the details,” McMonagle said. “Let’s burst the bubble. I don’t think that means green hydrogen as an industry is gone — it will play a fundamental role in certain use cases. Trying to do everything just invites criticism that’s frankly valid.”
Hydrogen’s critics have long insisted that it never made much sense, either as a decarbonization strategy or a moneymaking venture. They see the industry’s implosion as a chance to avoid plowing billions of dollars into a technological dead end. Many climate advocates have dismissed hydrogen as a guise for fossil-fuel interests to prolong the use of their planet-warming product; they won’t be shedding any tears now.
But for the contingent of hydrogen entrepreneurs who emerged from successful renewables firms, the sudden loss of momentum delivers a yearslong setback in efforts to clean up heavy-duty transport, steelmaking, and other industries that are hard to decarbonize, and a missed opportunity to head off the worst impacts of climate change.
“I worry we’ve lost a decade, and that was a decade we didn’t have,” said Brophy.
The sudden vaporization of the imagined green hydrogen economy may be the kind of healthy correction this market needed. Whichever hydrogen projects ultimately get built could prove more durable for having made it through the ringer after the days of easy money. But that’s paltry consolation for the townships and states that were promised billion-dollar projects and high-tech jobs within a couple years. Beyond the economic hit, the green hydrogen collapse removes a leading contender for cleaning up the most carbon-intensive industries — at least until the next hydrogen boom comes around.
A big-budget offshore wind project that would clean up a contaminated California port and turn it into America’s first hub for floating wind turbines is the latest target of an increasingly emboldened national anti-offshore wind movement.
Representatives of a D.C.-based conservative think tank, Committee for a Constructive Tomorrow (CFACT), and a local California community group asked the U.S. Department of Transportation early this month to cancel a $426 million grant issued last year to repurpose the Redwood Marine Terminal in Northern California’s Humboldt County for wind. If successful, they could stymie the state’s plan to generate up to 5 gigawatts of offshore wind by 2030 and 25 gigawatts by 2045.
Anti-wind activists told Canary Media they are looking to capitalize on the “timing” of a recent implosion of offshore wind plans in Maine, which — like California — sought to pioneer floating turbine technology in this country. Currently, all turbines operating or under construction in U.S. waters are fixed to the seafloor.
The move represents a westward spread of anti-wind activism from the East Coast, where longtime organized opposition has found sympathetic ears as it petitions the Trump administration to tank permitted projects.
For example, in February, groups lobbied for a halt to offshore projects already being built, an approach the Trump administration tested out in April by freezing New York’s Empire Wind installation, though construction was already underway. President Donald Trump reversed that decision after a month, but the move signaled that opposition groups have gained traction.
“They are clearly feeling emboldened by Donald Trump,” said J. Timmons Roberts, a professor of environmental studies and sociology at Brown University, who studies networks of anti-wind activists. “They are taking these local victories on the East Coast and continuing to move along.”
Both CFACT and the California community group, Responsible Energy Adaptation for California’s Transition (REACT) Alliance, are part of the National Offshore Wind Opposition Alliance, a coalition formed last year to broaden the fight against offshore wind, which had previously played out mostly at the local level.
The Humboldt project was awarded the DOT grant in January 2024 and a developer has not yet been announced, but it’s been five years in the making. Humboldt Bay Harbor, Recreation, and Conservation District has already used nearly $20 million in state and federal funds to design and permit much of the planned wharf. The federal grant includes additional funds for port expansion as well as environmental restoration, a solar array, trails, public kayaking access, and a fishing pier.
Earlier this month, CFACT and REACT Alliance sent a letter to DOT Secretary Sean Duffy challenging the project’s “public interest” grant requirement, citing the “lack of viability of the floating offshore wind ‘industry.’” The letter also points to Trump’s anti-wind directive, which halted federal permitting and leasing for wind projects but did not mention grants for supporting wind infrastructure, like ports.
“We decided that the timing and the political will was there for us to go ahead and write this letter and to ask for the grant to be terminated,” said Mandy Davis, REACT Alliance’s president.
Davis told Canary Media that two recent setbacks in Maine’s pursuit of floating offshore wind motivated the group to act. First, Maine’s application for the same DOT grant awarded to the Humboldt Bay Harbor project was rejected in October. Those funds would have helped finance a port for floating offshore wind on Sears Island, Maine. Secondly, this spring, the Department of Energy clawed back a grant to the University of Maine to build and test the state’s first floating turbines.
Davis leads both REACT Alliance and the National Offshore Wind Opposition Alliance. She insists that neither of those groups receive any monetary support from CFACT, though the D.C. think tank co-signed the letter. According to the research group DeSmog, CFACT has received hundreds of thousands of dollars from fossil-fuel groups over the years.
“CFACT has, for decades, been undermining the science of climate change and attacking efforts to address the issue. This is just their latest effort to destroy a climate solution,” said Roberts.
A recent pact between North Dakota and the Trump administration shows how coal-friendly states could enshrine lax standards and block future federal enforcement on toxic coal ash pollution.
North Dakota earned preliminary approval from the U.S. Environmental Protection Agency last month to regulate coal ash — a byproduct of burning coal — at the state instead of federal level. Indiana environmentalists fear that their state will follow the same path.
The distinction may seem moot under President Donald Trump — whose administration did not enforce federal coal ash regulations during his first presidency — but if his EPA approves so-called primacy arrangements allowing states to run their own programs, it could lock in weaker enforcement even if a future administration wants to take a tougher stance on coal ash contamination.
“What primacy would do is cement a situation that, depending on the state, could be very detrimental,” said Lisa Evans, senior counsel for the law firm Earthjustice, calling the North Dakota decision “precedent-setting.”
Under 2015 federal rules, coal ash is not allowed to be stored in contact with groundwater, and contamination caused by the substance must be reported and remedied. A 2016 law allows states to adopt their own coal ash rules that are at least as protective as the federal standards, after which states can petition the EPA to gain primacy and take responsibility for issuing coal ash permits and enforcing regulations.
EPA Administrator Lee Zeldin has encouraged states to do this, citing the administration’s commitment to “clean beautiful coal.”
This raises concerns when a state’s government is known to be friendly to the coal industry and lenient on pollution. Indiana consumer and environmental leaders have long described their state this way, and indeed, Indiana lawmakers have proposed and passed multiple measures supporting coal, including two laws obligating the state to seek coal ash primacy.
“One reason” the possibility of primacy “is so bad in Indiana is the amount of coal they burn and the amount of coal ash that’s been mismanaged,” Evans said.
In a Jan. 15 letter to Zeldin, obtained by Canary Media, coal and energy companies asked the government to expedite state control over coal ash regulation.
West Virginia, Wyoming, and Alabama have also sought coal ash primacy, and all three are plaintiffs in a lawsuit challenging aspects of the federal coal ash rules, according to the Cowboy State Daily. In May 2024, the Biden administration denied Alabama’s request for primacy, and state officials said they would appeal.
North Dakota’s attorney general sent the EPA a notice of the state’s intent to sue over its coal ash primacy application, in January, shortly before Trump took office. The Trump administration proposed approving North Dakota’s primacy request last month.
Georgia was granted coal ash primacy in 2019, and it has issued permits allowing utility Georgia Power to permanently leave large amounts of coal ash in pits submerged partially in groundwater, a move that environmental groups say violates federal rules. Texas and Oklahoma also have primacy programs.
States can gain similar authority over the regulation of underground injection wells, and in February, the EPA approved West Virginia as the fourth state — along with Wyoming, North Dakota, and Louisiana — with such primacy.
In 2021 and again in 2023, Indiana lawmakers adopted legislation obligating the state to adopt its own coal ash rules and then seek primacy to enforce them. This upset environmental and health advocates, said attorney Indra Frank, since they feared that the state would not actually enforce coal ash standards after being freed from federal scrutiny.
“In Indiana, our industry would prefer to deal with [the Indiana Department of Environmental Management] rather than EPA,” added Frank, who serves as coal ash adviser for the Hoosier Environmental Council. “It’s a problem if the EPA approves a program like the one they just approved in North Dakota, where the state agency has a long history of ignoring noncompliance and actually issuing approvals for plans that are not compliant. Once the state has primacy, the EPA will be very hesitant to step in. And the courts will defer to the state’s primacy as well.”
In 2024, Indiana issued draft state coal ash rules akin to the federal rules and accepted public comment on them. But Frank suspects that Indiana regulators will wait to revise those standards once laxer federal rules are finalized. In March, Zeldin announced a review and planned overhauls of the coal ash rules, which were barely enforced until 2022, when the Biden administration began issuing decisions and mandates.
With revised federal rules on the books, Indiana could enshrine state rules that are similarly weakened.
And even if the federal rules are beefed up again in the future, the federal government would be hard-pressed to impose those rules on a state that gained primacy with weak rules, explained Evans and Frank.
“The trifecta would be that EPA weakens the current regulations, and the states adopt those weak regulations and issue permits based on those weak regulations,” said Evans. “Then I think we’re in a really terrible situation. Because if the regulations are again strengthened under a new administration, the states have three years to change their programs to be consistent, but who is going to enforce that deadline? I think it would be more than three years before corrections would be made to state programs, and in the meantime a lot of damage is being done.”
Indiana is home to more than 73 million cubic yards of coal ash stored on at least 16 sites, according to data compiled by Earthjustice in 2022 based on companies’ own reporting required under federal rules. That’s the equivalent of more than 22,000 Olympic swimming pools. And that number doesn’t even include ash not covered by the federal rules until a 2024 update.
All the coal ash ponds noted in the data are unlined, and most of them have contaminated groundwater with elements including arsenic, molybdenum, and lithium, according to the companies’ own reports.
Companies have proposed to close many of the ponds in place — without removing the coal ash from the unlined repositories. Ben Inskeep, program director for the consumer group Citizens Action Coalition, said he would expect state regulators to approve such plans.
“The track record in Indiana has been lax enforcement, not particularly focused on ensuring good environmental quality outcomes and more focused on doing the bidding of industry,” he said, noting that’s a reason to oppose primacy on coal ash.
“We certainly would be very concerned by that path forward, given we think the EPA is the right entity to implement those regulations and ensure enforcement,” Inskeep said. “The Trump administration is a four-year term, and managing coal ash is going to be decades into the future. This is a long-term issue that requires federal oversight for the duration; it’s absolutely critical the federal government keep that ability.”
It was supposed to be the United States’ grand entry to the global race to make green steel — a symbol of a return to American innovation and of revival in the nation’s rusting industrial heartland.
Instead, Cleveland-Cliffs’ plan to replace coal-based blast furnaces with cleaner, hydrogen-ready technology at its Middletown Works facility in Ohio — the same mill that Vice President JD Vance described as his grandparents’ “economic savior” in his “Hillbilly Elegy” memoir — now risks being swept away in the undercurrent of Washington’s shifting partisan tides.
Neither the Cleveland-based steelmaker nor the Department of Energy, which put up $500 million to back the project, has formally pulled the plug on the plan to build a direct reduced iron plant capable of using hydrogen and two electric melting furnaces. But updates from the company in recent weeks suggest the ambitious carbon-free version of the project is all but dead.
On a first-quarter earnings call with investors last month, Cleveland-Cliffs’ CEO Lourenco Goncalves said the company was negotiating with the Department of Energy to “explore changes to the scope to better align with the administration’s energy priorities.”
Rather than use hydrogen, the green version of which remains expensive and in limited supply, Goncalves said the project would “instead rely on readily available and more economical fossil fuels.” At an event earlier this month hosted by the lobbying group American Iron and Steel Institute, Goncalves said the lack of a hydrogen-generating hub nearby made it impossible to source the fuel on the project’s timeline.
“Without hydrogen, the entire thing falls apart,” Goncalves said, according to E&E News. “At the very least, I will not have hydrogen at the time I need for that specific project.”
Cleveland-Cliffs did not reply to Canary Media’s emailed questions on Friday, nor did the Energy Department return a request for comment on the status of the federal funding.
But Goncalves could announce the fate of the project as soon as Tuesday, when he’s set to speak at the Global Steel Dynamics Forum in New York City.
“Before all this uncertainty, this project was going to be, potentially, the first green-steel plant in the U.S.,” said Hilary Lewis, the steel director at the climate research group Industrious Labs. “With all this uncertainty, and particularly with this potential pivot toward fossil fuels, the future of clean iron and steelmaking in the U.S. is much less clear, and that puts our competitiveness at risk.”
The up-front costs of installing entirely new equipment always outweighed those of simply renovating the existing coal-fired unit.
Relining a blast furnace costs up to $400 million, according to RMI estimates. The total cost of building the DRI plant and electric melting furnaces came out to $1.6 billion, meaning Cleveland-Cliffs was on the hook for $1.1 billion even with the federal grant the Biden administration finalized last September.
The traditional coal-based method of making steel — which involves melting iron ore in a blast furnace then refining the iron into steel in a basic oxygen furnace — produces the cheapest metal, at roughly $390 per metric ton, according to an October report from Columbia University’s Business School. Scrap melted down in an electric arc furnace came out to $415 per metric ton. Steel made with iron from DRI fueled with natural gas and then refined in an electric arc furnace averaged out to $455 per metric ton.
Producing the iron through DRI with entirely green hydrogen, instead of gas, spiked the price to around $800 per metric ton.
The cost of making hydrogen with electrolyzers powered by certifiably clean electricity is among the biggest challenges to green steel in the U.S. That hurdle is now poised to become even higher as congressional Republicans seek to repeal the Inflation Reduction Act’s 45V tax credit, which aimed to make green hydrogen cost-competitive with the gas-derived version of the fuel. The Senate Finance Committee on Monday released its version of the budget bill, which aligned with the recently passed House version in eliminating the incentive at the end of this year.
That isn’t an issue for Europe’s leading green steel project. Formerly known as H2 Green Steel, the newly renamed Stegra plant benefits from the vast amount of carbon-free energy in Sweden, where the overwhelming majority of power is generated from hydroelectricity, wind turbines, and nuclear reactors.
In the U.S., by contrast, green hydrogen plants hinged on massive projects to construct wind turbines and solar panels that needed to be 70% larger in capacity to make up for the intermittency of the renewables, according to Elizabeth Boatman, a lead consultant at the Michigan-based clean energy consultancy 5 Lakes Energy. A dedicated nuclear reactor to generate the power for electrolysis could do so more efficiently, she said, noting that the availability of underground salt caverns to store hydrogen for later use could also further bring down the cost of projects.
“I don’t think anyone on any side of this thought hydrogen at scale wouldn’t be a barrier,” Boatman said. “The amount of new renewables the company would have to build out, along with transmission infrastructure, was clearly going to be expensive.”
In 2022, the Biden administration set a target of $1 per kilogram of green hydrogen within the next decade. (Last fall, a Florida-based geothermal startup called Magma Power filed patents that claimed it could generate green hydrogen for less than $1 per kilogram. The company did not immediately respond to an inquiry from Canary Media on whether that figure banked on the 45V tax credit.)
If the U.S. managed to achieve a supply at that price, steel made with green hydrogen-powered DRI and an electric arc furnace could come out to $544 per ton, according to a report published last July by Transition Asia, a nonprofit think tank focused on climate research. That’s marginally less than the cost of steel from gas-powered DRI and an electric arc furnace, at $550 per ton, or blast furnace steel at $565 per ton. If the U.S. were to institute even a modest carbon price, it could reach cost parity with coal-fired steel.
But if the 45V tax credit disappears, those numbers will be near-impossible to achieve.
Regardless of cost challenges, Boatman said, “it’s still an attractive solution, not just because of the potential to curb climate-warming emissions but also criteria air pollutants and other hazardous air pollution tied to the production process from a blast furnace with coal.”
The original, low-carbon version of the Cleveland-Cliffs project also has significant potential economic benefits.
The plant overhaul would have spurred $373 million in economic activity around the facility and brought 2,300 jobs to Middletown, according to analysis shared with Canary Media by the Center for Climate and Energy Solutions, a think tank. It’s not clear how a relining project would stack up.
That’s what made the project so significant, not just as a potential climate solution but as a way to revitalize a town in the heart of America’s steelmaking region, said Brad Townsend, the Ohio-based vice president of policy and outreach at the Center for Climate and Energy Solutions.
“Middletown is sort of the quintessential Midwest steel- and paper-making town that is looking for a way to leverage that history and infrastructure and know-how to chart a path forward,” he said. “This project would have done exactly that.”
.svg)
