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New York just took a big leap toward zero-emissions buildings.
On July 25, the State Fire Prevention and Building Code Council approved an all-electric building standard, making New York the first state in the nation to prohibit gas and other fossil fuels in most new buildings. Legislators and climate advocates celebrated the move, which had been mandated under the pathbreaking 2023 All-Electric Buildings Act.
“I’m excited that we are finally tackling, statewide, our largest source of fossil-fuel emissions,” said state Assemblymember Emily Gallagher, who sponsored the 2023 legislation. Buildings account for 31% of the Empire State’s planet-warming pollution.
New York is forging ahead on building decarbonization at the same time the federal government is backtracking, yanking support for renewable power and home energy efficiency and providing the fossil-fuel industry with new subsidies.
The state’s rules will apply to new structures up to seven stories tall and, for commercial and industrial buildings, up to 100,000 square feet beginning Dec. 31, 2025. Buildings bigger than that will need to be built all-electric starting in 2029. The new code will spur installations of heat pumps and heat-pump water heaters — ultra-efficient electric appliances that are good for the planet and, typically, pocketbooks.
The council left room for exceptions, though, including new laboratories, crematoriums, restaurants, and large buildings whose owners can prove the grid isn’t ready to accommodate their sizable all-electric heating needs. Michael Hernandez, a policy director at electrification advocacy nonprofit Rewiring America, said he doesn’t think the exemptions will eat away at the code’s efficacy, however.
With the rules finalized, “I’m relieved,” Gallagher told Canary Media. Fossil-fuel interests — such as the utility front group, New Yorkers for Affordable Energy — “really worked overtime to try to stop this,” she said.
The new regulations come on the heels of a recent legal victory: On July 23, a federal district court in New York upheld the state’s ability to implement the All-Electric Buildings Act.
The groups challenging the law in court — including the New York State Builders Association, National Association of Home Builders, National Propane Gas Association, and a few local union chapters for plumbers and electricians — alleged that it’s preempted by the federal Energy Policy and Conservation Act, the same justification used to overturn Berkeley, California’s pioneering ban on gas hookups in new construction. The New York judge was unconvinced by this argument, noting that the Berkeley decision relied on “deficient interpretations” of terms like “energy use,” and is “simply not persuasive.”
Opponents of the standard haven’t quit, though. An industry coalition that includes many of the organizations that brought the lawsuit sent a letter on June 26 to U.S. Attorney General Pam Bondi requesting that the Department of Justice move to block the code from taking effect. Michael Fazio, lead author of the letter and the executive director of the New York State Builders Association, declined to comment on the request’s status to Canary Media.
The state’s new energy code is expected to raise the cost of residential construction but also lower energy bills substantially for homeowners and renters, making it cost-effective overall with a payback of 10 years or less, according to a report commissioned by the New York State Energy Research and Development Authority. Over 30 years, households are expected to save an average of about $5,000 due to a 17% reduction in energy use.
Other research indicates all-electric construction is typically less expensive than that for buildings equipped to burn gas or fuel oil. Electric-only projects allow developers to forgo installing costly fossil-fuel infrastructure alongside the electrical systems requisite in modern buildings. A 2022 analysis by the decarbonization nonprofit New Buildings Institute, for example, found that building an all-electric single-family home in New York costs about $8,000 less.
The all-electric code will improve air quality by reducing reliance on fossil-fuel-fired boilers, furnaces, water heaters, and stoves. These conventional appliances spew harmful byproducts such as carbon monoxide, particulate matter, benzene, nitrogen oxides, and more, which can cause respiratory and cardiovascular issues — to lethal effect. In 2017, fossil-fuel use from New York buildings caused $21.7 billion in health impacts and nearly 2,000 premature deaths, more than in any other state.
Gas stoves, typically the largest sources of exposure to indoor air pollutants, are linked to nearly one in five asthma cases in children in New York, according to a 2022 study. “Places like the Bronx have the highest rates of childhood asthma in the country,” said Jumaane Williams, public advocate of New York City, in a call with reporters on Friday. “We know this is a life-and-death situation.”
“Numerous studies … show that both air pollution and climate change disproportionately impact low-income communities and communities of color,” said Lonnie Portis, director of policy and legislative affairs at the community-based nonprofit WE ACT for Environmental Justice. The state’s all-electric building standard “is a significant step forward for environmental and climate justice.”
The new rules will not only get heat pumps into new construction but help boost adoption in existing homes, according to Jay Best, CEO of home energy-efficiency company Green Team Long Island.
“We’re always telling people about heat pumps … solutions that are going to save them money and make their homes more comfortable,” Best told Canary Media. “But people are apprehensive because it’s something they’re not used to,” despite heat pump units outselling gas furnaces nationally.
“The code … sets a bar; this is the minimum that the state says is legal to build,” Best said. That “changes people’s view of the technology.”
Alex Beauchamp, Northeast region director at Food & Water Watch, underscored that passing the All-Electric Buildings Act and getting it into the state code was a victory of David-and-Goliath proportions, with “fossil-fuel companies, plus the gas utilities, plus big real estate” rallied in opposition, he said.
“When New Yorkers come together … we can win even in the face of opponents with an almost-limitless budget,” he said. “That is how we won this bill. It’s also how we are going to continue the fight to get fossil fuels out of all the existing buildings in the state.”
The Trump administration just dealt another blow to U.S. environmental regulations — one that could allow more contamination of drinking water from toxic coal ash contamination.
The Environmental Protection Agency proposed on July 17 to extend deadlines for required reporting and groundwater monitoring at coal ash landfills and dumps.
Any delay of these rules would be harmful in its own right, experts say, and they fear the announcement is just the beginning of further efforts to undercut coal ash regulations. During his first term, President Donald Trump largely ignored federal coal ash rules that took effect in 2015. This time around, his administration is widely expected to roll them back.
Advocates suspect that updates made last year to include so-called legacy coal ash, which wasn’t covered by the original rules, and coal ash landfills are especially vulnerable. That’s why alarm bells have been ringing for advocates following the EPA’s latest move to delay enforcement of one key aspect of the updated rules: the regulation of dry coal ash dumps and landfills, known as coal combustion residual management units, or CCRMUs.
The EPA’s July 17 announcement included a direct final rule and a companion proposal that would extend deadlines for these CCRMUs.
The EPA said it wants to extend the deadline by one to two years for the “facility evaluation reports,” which companies have to file if they own coal ash that meets the definition of a CCRMU, and therefore makes the sites newly subject to regulation. The EPA also proposes extending the deadline to start groundwater monitoring at these sites for an additional 15 months, from May 2028 to August 2029. The direct final rule issued by EPA would extend the deadline for the facility report to February 2027.
As it stands, utilities and other owners of coal ash sites are required to report by February 2026 whether they have any coal ash in landfills, berms, dumps, or other dry repositories that would be considered CCRMUs newly subject to regulation under the updated rules.
“We assume what EPA did was give themselves time to make significant changes to the legacy coal ash rule,” said Lisa Evans, senior counsel at Earthjustice. “The amount of time given to utilities to comply with the CCRMU portion of the rules [was] extremely generous. The utilities were given years, and now they’re coming back for more, thinking this EPA will grant them more time.”
The initial coal ash rules took effect in 2015 and were heralded as a major step toward cleaning up the toxic coal ash located at more than 700 sites at over 300 power plants nationwide. But those rules did not cover coal ash that was used to fill in earth or build up berms, or was simply scattered about; nor did they cover ash at coal plants closed before the rules took effect.
The environmental law organization Earthjustice filed a lawsuit on behalf of environmental groups seeking to expand the 2015 rule’s coverage, and after a federal court decision in 2018, the updated rules were eventually adopted in May 2024. These updated rules cover CCRMUs as well as “legacy ponds” — coal ash stored in water at coal plants closed before 2015.
Under federal administrative procedures, the EPA’s new direct final rule will take effect six months after being published in the Federal Register if no “adverse comments” are filed by the public. Groups including Earthjustice are almost certain to lodge adverse comments, in which case the rule would not take effect, and instead the companion proposal — to extend the facilities report deadline to February 2028 — would undergo a public comment process.
This poses a bit of a conundrum for environmental groups: If they challenge the rule, they may end up with an even longer delay.
“If you get a year or two years, you get another two years to put in groundwater monitoring. Then that delays the determination of contamination, which then delays development of a cleanup plan and final remedy,” said Evans. “You’re pushing everything into the future.”
An EPA press release says, “These actions advance [EPA] Administrator [Lee] Zeldin’s Powering the Great American Comeback Initiative,” which includes energy dominance, among other pillars.
Evans said the EPA’s announcement came immediately after a July 17 meeting that she and other advocates had with EPA officials, along with residents who live near some of the country’s hundreds of legacy coal ash impoundments. She said the officials listened to their concerns but made no mention of the delays that were about to be unveiled.
“We were all stunned,” she said. “Years do make a difference when you’re thinking about the movement of contaminated groundwater. This will allow more contaminants to get into groundwater, it will make it hard, possibly impossible, to remediate. We know these sites; we know how contaminated these sites are; we know contamination is moving in the groundwater.”
Almost a century ago, on the shores of Lake Michigan in northwest Indiana, the utility NIPSCO mixed coal ash from its Michigan City coal plant with sand and sod to help fill in the space behind steel retaining walls. On the other side of those now-corroding steel walls is the lake, which provides drinking water for the region and is a hub of both human recreation and aquatic life.
Environmental leaders have serious concerns that waves will pound away at the decaying wall, further weakening it, to the point that tons of toxic coal ash will spew into the lake. Coal ash contains heavy metals and other contaminants known to cause cancer and other serious health problems, as the EPA notes.
The Michigan City coal plant is among more than 300 sites covered by the updated rules, according to Earthjustice’s analysis, meaning NIPSCO should be required to file a CCRMU facilities report by February 2026 and then groundwater monitoring results and cleanup plans. Any delay in the reporting deadlines means a delay in the site being remediated — and extends the risk of coal ash contaminating the lake and possibly the groundwater too, environmental leaders say.
“Having the delay in some of those requirements is pretty devastating to hear,” said Ben Inskeep, program director of the Citizens Action Coalition, an Indiana consumer protection group. “These are coal ash waste dumps that have been there for decades. For all this time, they are just leaching really nasty things into our water supplies, putting us in grave danger of a catastrophic failure of the coal ash, all that coal ash getting into our waterways or drinking water supplies.”
NIPSCO is in the process of repairing one of the steel seawalls adjacent to a creek that empties into Lake Michigan by the Michigan City plant, but local leaders say that is less a solution and more a sign of the risks.
“The utilities have had a long time to figure out what kind of coal ash they have on their properties, what damage has been done, what remedies are possible,” Inskeep said. “Further delay is certainly harmful to communities who have been forced to endure living next to these toxic sites for so long.”
Owners of legacy coal ash ponds were required in November 2024 to file inspection documents for their sites. Those documents show serious groundwater, lake, and river contamination concerns from sites in Alabama, Georgia, Illinois, Indiana, and West Virginia, among other states, according to Earthjustice’s analysis.
The Widows Creek plant on the Tennessee River in Alabama may be the “dirtiest” site subject to the updated rules, according to Earthjustice. The plant was retired shortly before the 2015 rules took effect, meaning that it was not regulated until the update last year. Also unregulated until the 2024 update was the Morrow Lake plant in Michigan, whose location puts coal ash in direct contact with a recreational lake, according to its recently filed inspection reports.
Also troubling, advocates say, is that multiple companies known to have legacy ponds on-site did not file any reports by the November deadline or within an allowed six-month extension period. An EPA website compiling reports includes 46 sites filed under the legacy rule, out of at least 84 sites known to have legacy ash, according to Earthjustice’s analysis.
“It’s unfortunately not surprising, considering the industry’s general noncompliance,” said Mychal Ozaeta, Earthjustice’s clean energy program senior attorney. “It’s nothing new. We’re going to continue to monitor it, utilize our internal resources, work closely with our partners to track it just so the public is aware of various sites across the country failing to make publicly available this critical information and comply with requirements.”
The EPA press release about the deadline extensions also refers back to “March 12, 2025, the greatest and most consequential day of deregulation in the history of the U.S., [when] EPA committed to taking swift action on coal ash, including state permit program reviews and updates to the coal ash regulations.”
It’s a reference to another move the EPA is making to further undercut federal coal ash rules: Giving states, including those with lax records on the environment, the power to enforce their own coal ash rules.
On July 10, the EPA had issued another announcement that could weaken the legacy coal ash rules. It essentially said an earlier memo from the EPA — aimed at defining “free liquids” causing contamination concerns in coal ash repositories — should be ignored.
“It’s pretty nefarious,” said Evans. “This is all just the start of the Trump administration’s attempted unraveling of coal ash protections.”
State legislators pushing to unravel North Carolina’s climate law say their bill will give utility Duke Energy more leeway to build new gas and nuclear power plants and save its Tar Heel customers billions of dollars.
But Gov. Josh Stein disagrees: He vetoed Senate Bill 266 on Wednesday, prompted by data showing that the legislation would cost households and slow the state’s energy buildout. The GOP-sponsored measure would repeal a requirement that Duke slash carbon pollution 70% by 2030 compared to 2005 levels, while leaving a 2050 carbon-neutrality deadline intact.
“This summer’s record heat and soaring utility bills has shown that we need to focus on lowering electricity costs for working families — not raising them,” Stein, a Democrat, said in a statement. “My job is to do everything in my power to lower costs and grow the economy. This bill fails that test.”
In issuing his veto, Stein pointed to a new study from researchers at North Carolina State University, which builds on projections from the state customer advocate, Public Staff. That modeling showed SB 266 could cause Duke to build less generation capacity over the next decade, just as electricity needs are expected to surge.
That means Duke would have to lean harder on aging plants and burn almost 40% more natural gas between 2030 and 2050, experts at N.C. State University say. Under a worst-case but plausible scenario for gas prices, customers could pay $23 billion more on their electric bills by midcentury as a result.
“As our state continues to grow, we need to diversify our energy portfolio so that we are not overly reliant on natural gas and its volatile fuel markets,” Stein said.
A complex measure that’s faced little public debate, SB 266 easily cleared both chambers of the Republican-controlled General Assembly in June with a handful of Democratic votes. With Stein’s action, advocates now turn their focus back to state lawmakers, who are on break for at least another week. The GOP has the three-fifths majority needed to override the veto in the Senate, but is one member shy of that margin in the House.
“Governor Stein is championing working families all across North Carolina who would be harmed by this new law,” said Will Scott, Southeast climate and clean energy director for the Environmental Defense Fund. “Legislators should reconsider the harmful consequences of this law for the working families in their districts.”
The N.C. State study underscores a surprising finding from Public Staff’s modeling: SB 266 does little to prepare North Carolina for ballooning electricity needs expected from an influx of data centers, manufacturers, and new residents. In fact, removing the 2030 goal would prompt Duke to build 11,700 fewer megawatts of new power plants in the next decade than its current plans.
“In talking with legislators, I found that almost all of them emphasized economic growth and the need for power generation to meet that demand,” said Scott. “But Public Staff’s analysis found that the most likely short-term impact of SB 266 is to build less new generation and storage and instead to lean harder on aging coal and gas facilities.”
The Public Staff forecast shows renewable energy would be the main short-term casualty of SB 266, just as its backers intend. By 2035, Duke would construct 7,200 fewer megawatts of solar and battery storage, and no offshore or onshore wind farms whatsoever — a 4,500-megawatt decrease compared with the status quo.
But new “always-on” nuclear and gas resources — the same ones SB 266 champions seek to promote — would also suffer. Without a near-term carbon reduction deadline, Public Staff says Duke would develop just 300 megawatts of nuclear power in the next decade, half as much as it currently plans. The utility would build 1,400 fewer megawatts of large, efficient combined-cycle gas units.
Only gas “peaker plants” — simple-cycle combustion turbines that are relatively cheap to build but expensive to operate — would become more abundant, Public Staff forecasts. Duke would build 3,800 megawatts’ worth instead of 2,100.
The model’s underlying assumptions haven’t been made public. But experts say the reason for this short-term impact is likely that without a carbon constraint, it’s simply cheaper to run existing coal and gas plants more often than it is to build new ones.
The same Public Staff study predicts that removing the 2030 target would yield $13 billion in present value in customer savings by 2050 — a figure much vaunted by SB 266 supporters.
But detractors have long pointed out that the discount comes from avoided construction costs only and doesn’t account for the price of fuel, 100% of which is passed to utility customers through a “rider” on monthly bills.
As it happens, the $23 billion in added fuel costs estimated by N.C. State translates to $13 billion in present value.
“That is a pure coincidence,” said Jeremiah Johnson, one of the researchers. “It completely negates the claimed savings.”
Duke might also have to buy more power from utilities in neighboring states to meet electricity needs, another blow to residential consumers, who under SB 266 would pay a higher fraction of those costs than they do today.
“This bill not only makes everyone’s utility bills more expensive,” Stein said, “but it also shifts the cost of electricity from large industrial users onto the backs of regular people — families will pay more so that industry pays less.”
Advocates also point to the simple public health rationale for keeping the state’s 2030 pollution-reduction goal intact. Relying on existing coal and gas plants instead of building more solar means millions of tons more climate pollution released into the atmosphere every year, plus pollutants that lead to smog and soot.
Then, there’s the commonsense argument, said Matt Abele, executive director of the North Carolina Sustainable Energy Association: “You don’t establish a 30-year goal without milestones along the way.” Achieving emissions reductions is like saving enough money for retirement — it takes planning and can’t be done in just a couple of years. “These things do not happen overnight,” he said.
Abele’s group analyzed the 24 states, plus D.C. and Puerto Rico, with zero-carbon targets around the middle of the century. Just one, Nebraska, lacks any sort of interim goal.
The reason, according to state Rep. Maria Cervania, a Democrat from Wake County who voted against SB 266? “Deadlines matter.”
At a news conference last week, she said that the 2030 goal has given “us a clear, science-based target to hold the utilities accountable. … Without it, progress slows and polluters face no urgency to act.”
An update was made on July 2, 2025: This story has been updated to reflect that Gov. Stein vetoed SB 266 after this story was published.
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.”
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.”
A Chicago-area startup says its technology could shave emissions from the global metal industry by allowing companies to recycle grimy metal slivers and sludge left over from steel and aluminum production.
Steel and aluminum production account for about 7% of the world’s carbon emissions, according to the International Energy Agency. Decarbonizing the sector is expected to be a huge and costly undertaking, involving the overhaul of industrial processes more than a century old and the retrofitting of sprawling mills.
Sun Metalon aims to take smaller bites of the steel-decarbonization apple with an oven-sized box that promises to extract recyclable metal from a waste stream that would otherwise be sent to a landfill.
“You’ve got a company throwing something away, in some cases paying to throw it away because it’s contaminated with toxic materials. [Sun Metalon is] offering a way to create value from that,” said Nick Yavorsky, senior associate for the climate-aligned industries program at the clean energy nonprofit RMI, which is providing Sun Metalon 18 months of mentorship as part of its Third Derivative cleantech business accelerator.
On May 21, the company announced it had raised a total of $9.1 million in second-round startup funding from four investors, including Japanese steelmaking giant Nippon Steel.
The great majority of steel and aluminum in the U.S. is made from recycled metal, not raw ore. That’s fortunate, since creating this recycled metal emits much less carbon emissions than forging it from scratch. And that means increasing the amount of metal that can be recycled is one means of decarbonizing the industry.
“Some companies are looking at making steel in a new way, fully electrified,” as opposed to powered by coke, an energy-dense substance derived from coal, Yavorsky said. “Maybe there is not as much sexiness around folks reducing demand [for new steel], thinking about alternative materials. Yet these often are the fastest and most direct way to reduce emissions.”
Sun Metalon CEO and co-founder Kazuhiko Nishioka said he got the idea for the technology while working at Nippon Steel and studying for a PhD at Northwestern University near Chicago with Nippon’s support. In 2021, he and two colleagues at Nippon founded the company as they did DIY experiments to clean up tiny scraps too contaminated with oil or other substances to be recycled.
They received two patents on the heating technology in 2024. Sun Metalon’s units are modular “ovens” that can be placed on a factory or foundry floor; the metal waste fed into them is basically cleaned with intense heat and turned into “pucks” or “coins” that can be recycled in metal-making processes.
“We apply our heating, evaporate fluids, condense [impurities] back to liquid, and collect it,” explained Nishioka, noting the process involves reaching the boiling point of oil. The whole thing is powered by electricity, making it carbon-free if renewable energy is available.
“Sometimes scrap has a negative value, especially for sludges — no one can recycle it, so they have to pay for disposal,” he said. “We can bring it up to best or second best” in the value chain of recycled metal feedstock. “Then the profit can be shared among customers.”
The pucks can be sold to electric arc furnaces — essentially steel mills making recycled steel — or other metal recycling operations. Or they can be used onsite; for example, a car factory could channel metal waste from one part of the production line back into making new engine blocks.
“We are reducing new metal, and secondly, we are reducing logistics — nobody has to come pick it up” in diesel-burning trucks, said Nishioka.
Iulian Bobe joined Sun Metalon as chief strategy officer after co-founding a textile recycling company called Circ. He said steel and aluminum manufacturers are very eager to reduce their waste streams and their emissions; meanwhile, in Europe, decarbonization mandates drive demand.
“They’re really trying to get to a situation where they have zero landfill,” Bobe said. “They’re looking for solutions that can be implemented in the factories. You really don’t want to haul all that waste to another location. Our solution is very modular — we can put it on the site, achieving the circularity.”
Sun Metalon says it has received a total of $40 million from investors. Both Toyota Motor Co. and the construction equipment manufacturer Komatsu have purchased its equipment, tested it in their facilities, and promised to work with Sun Metalon to scale up the technology.
A 2024 press release from Komatsu explains that making the high-chromium cast-iron sealing rings used on undercarriages of its equipment produces a lot of polishing sludge — “a difficult-to-handle mixture of fine metal particles, oil, and water.”
Each year, Komatsu produces 150 tons of the sludge, which is hard to safely melt and recycle, according to the release — but Sun Metalon could change that.
“This endeavor not only promises significant resource conservation and waste treatment cost reductions but also aligns with broader decarbonization efforts in metal processing,” says the press release.
Toyota Motor Co. and Sun Metalon presented results of their tests at a May 2023 conference of the Japan Foundry Engineering Society, according to a Sun Metalon press release. (Nishioka declined to put Canary Media in contact with representatives of those companies, other investors, or potential customers.)
The Round A funding announced recently included Airbus Ventures, a Japanese bank, and an innovation fund, along with Nippon Steel, which is seeking to acquire U.S. Steel, including its Gary Works mill in Northwest Indiana. In recent weeks, President Donald Trump has expressed his support for an acquisition that would include decision-making power for the federal government — a sharp turn from promises he made on the campaign trail to block the move.
The Recycled Materials Association, a trade group that represents metal recycling, noted that over 70% of steel and 80% of aluminum in the U.S. is made from recycled material.
“Compared to the processing and transportation needed for mining, drilling, harvesting, or other methods of extracting natural resources for manufacturing, the use of recycled materials typically produces fewer greenhouse gas emissions,” Rachel Bookman, a spokesperson for the organization, said by email.
The trade association declined to comment specifically about Sun Metalon, which is one of its members.
Nishioka said the technology could be useful for “automotive and aerospace, construction machinery, any product using metal,” adding that he plans to pitch to steel mills and foundries in the Midwest and South.
“Any process melting metal can benefit,” he continued, “either companies that are melting metal or companies purchasing from those companies.”
Nishioka imagines that with more innovation, the modular technology could be used not only to prepare metal for recycling but to actually create metal products.
He’s also hopeful that new industrial processes could spur manufacturing in developing nations, an idea inspired by his time volunteering in Kenya as an undergraduate student.
“My original vision was to bring compact steelmaking processes into a couple different boxes,” he said. “We can bring those boxes wherever we want. It could be in Africa, or on Mars.”
The 79th Street corridor is one of the busiest thoroughfares on Chicago’s Southeast Side. But many of its adjacent side streets are poorly lit at night, posing hazards ranging from inconvenient to dangerous.
For instance, obscured house numbers can confuse both delivery drivers and emergency responders. And higher levels of crime have been correlated with poorly lit streets, making it feel unsafe for children to play outdoors after sunset or for pedestrians to walk alone in the dark.
“For those people who are going to work in the winter at five o’clock in the morning and it’s pitch black out there, yeah, they’re scared. They’re walking down the middle of the street,” said Sharon “Sy” Lewis, founder and executive director of Meadows Eastside Community Resource Organization, commonly referred to by its acronym of MECRO.
But block by block, things are changing, in no small part due to Light Up the Night, administered by MECRO in collaboration with the energy-efficiency program of Chicago utility ComEd. The initiative aims to solve the problem of dark streets by outfitting the front and back of homes with energy-efficient lights that automatically turn on at night and off during the day.
Light Up the Night was launched in 2019 as a pilot program in the South Shore community of the city’s South Side with an initial goal of providing Energy Star-certified LED light bulbs for up to 300 residences.
The program had to pause during the height of the Covid-19 pandemic, but eventually, Light Up the Night was able to achieve that goal and then some. Lewis said it has served more than 500 homes so far, and she is pursuing funding to expand.
MECRO staff or volunteers install the bulbs into existing outlets at no charge to residents. Lewis said this proactive approach yields better results than just distributing packages of light bulbs and other energy-saving devices that may or may not get used.
For Lewis, the installation process provides an opening to talk to residents about other energy-efficient measures, like weatherization or purchasing new appliances. The upgrades, often eligible for rebates to offset the cost, can dramatically reduce utility bills. This is particularly impactful in communities like those surrounding the 79th Street corridor, in which many residents spend a big portion of their income on energy bills, largely due to predominantly older and often poorly insulated housing stock.
“Light Up the Night is not just a gateway to safety, it’s a gateway to energy savings. And it starts with the little things. And because we installed it, instead of sending them an ‘energy box,’ then we know that it’s working. When you drive down that street, you know that it’s working, you see that impact,” Lewis said.
A minimum of 75% participation is required per block, and each homeowner or renter must provide consent before installation can begin, Lewis said.
“If the average block has 36 homes on it, if we get 15 on each side, at minimum, we have really created an impact for the block,” Lewis said. “So now you have the whole community lighting up at once [at dusk], and then they all go off in the morning.”
A legacy of segregation and disinvestment has left residents of predominantly Black communities like the Southeast Side with a strong distrust of outsiders. As a lifelong resident and visible activist, Lewis has an advantage when it comes to engaging with residents, but obtaining initial buy-in around South Shore was still a challenge.
“Getting people to sign up, that was a problem because we can’t not have data on where we are leaving the lights. … [But] people didn’t want to provide their information,” Lewis said.
To get the program up and running, Lewis worked with neighborhood block clubs to overcome apprehension and to identify particular streets in the South Shore community that would benefit the most from the new lights. She also worked with other community organizations, especially those focused on violence prevention.
It was easier to start up the program in Austin, a neighborhood on the city’s West Side, where, also in 2019, Lewis collaborated with Steve Robinson, executive director of the Northwest Austin Council, with whom she had worked previously on a number of initiatives. Chicago police officers assigned to that community were also enthusiastic about the program, and helped Lewis identify blocks where adding lights would be especially impactful, she said.
“[Robinson] invited me over there. It was a whole change. It was a sea change. It was amazing. [The police] were excited about it. They were looking forward to the change we were doing,” Lewis said.
Wherever it has been implemented, this small-scale program has had an outsized positive impact, Lewis said. Additional lighting on front porches and entryways also enhances safety for visitors to the community, including service providers like mail carriers, delivery people, and rideshare drivers. Likewise, floodlights installed at the rear of a home or apartment building add to the ambient lighting in often dark alleyways, which results in fewer garage break-ins and instances of illegal dumping of garbage, Lewis said.
MECRO does much more than install lights. The organization also helps guide new and existing small business owners, conducting educational seminars and offering technical assistance. And it provides residents with referrals for energy-efficiency improvements and other sustainability-related resources they might not otherwise know about.
But Light Up the Night remains part of the organization’s core mission.
While illuminating areas that used to be dark is the program’s first objective, once the new bulbs have replaced older, less-efficient lights, the lower utility bills can be eye-opening for residents.
When people see those savings, “they start thinking, ‘Well, what if I get all energy-efficiency light bulbs? Hmm. Okay, now my bill has gone really down. What if I do the weatherization program? Now my bill is really down,’” Lewis said.
Massachusetts-based Boston Metal is on the verge of earning its first revenue as it continues honing a novel steelmaking process so clean it can vent emissions into a parking lot the company shares with a day care center.
“It just proves how different the future of steel can be,” said the firm’s senior vice president for business development, Adam Rauwerdink.
The technique, which was developed at the Massachusetts Institute of Technology and is now being scaled up for commercialization, uses electricity to remove contaminants from iron ore, producing a small fraction of the emissions generated by traditional fossil fuel–fired blast furnaces. Indeed, the technology releases no carbon dioxide — just oxygen — and the only greenhouse gas emissions are those associated with the electricity used to power the system.
Promoting green steel was a major element of former President Joe Biden’s economic and environmental agenda. However, the Trump administration’s desire to boost fossil fuels has already undermined these efforts and left the future of the sector in question.
Against that backdrop, Boston Metal, with its carefully calibrated business plan and lack of dependence on increasingly unreliable federal funding, seems to have unusually bright prospects.
The company was founded in 2013 to take on the challenge of reducing the tremendous amounts of greenhouse gases released by the steel industry, a sector responsible for 7% to 9% of global emissions. Boston Metal has since received some $400 million in investments from a range of backers including global steel giant ArcelorMittal, the venture-capital arm of oil company Saudi Aramco, global investment manager M&G Investments, the World Bank’s International Finance Corp., and major climatetech funds such as Breakthrough Energy Ventures and Microsoft’s Climate Innovation Fund.
The possible payoff is significant: Demand for low-emissions steel is expected to increase by at least 6.7 million tons by 2030, though production of green steel is still very limited globally, said Kaitlyn Ramirez, senior associate with energy transition think tank RMI.
“The demand for green steel is there,” Ramirez said. “We’re seeing the momentum … even when there are challenges on the supply side that need to be resolved.”
The task of greening steel production is daunting. Globally, nearly 1.9 billion metric tons of steel are produced each year, and on average, each ton of steel is responsible for 2 tons of carbon dioxide emissions.
Roughly 90% of the emissions associated with steelmaking are generated by refining iron to use as a base material, Rauwerdink said. And that step has historically depended on burning a fuel — usually coal — to create the high temperatures at which iron ore can be melted and impurities removed. Seven such coal-fired plants remain in operation in the United States, contributing to high pollution levels in the cities where they are located.
Another process, known as direct reduction of iron, or DRI, burns natural gas to remove contaminants from iron ore. DRI systems can also be configured to burn hydrogen, though the current supply of green hydrogen — hydrogen created using renewable energy — is too scant and too expensive to be a reliable source of low-emissions fuel right now, Ramirez said. Still, she noted that hydrogen-fueled DRI is currently the most promising emerging alternative to traditional, emissions-intensive steel production.
“They can start using more hydrogen as it becomes available,” she said.
Boston Metal sidesteps that complication by refining iron through a process called molten oxide electrolysis. Iron ore is poured into a brick-lined chamber, where it dissolves in an electrolyte solution. An electric current runs through the liquid, melting the ore. Contaminants in the ore — like alumina, silica, and calcia — are left behind in the solution, while the molten purified metal settles to the bottom of the chamber.
When enough iron has accumulated, the chamber is tapped, in a sort of fiery, industrial analog to tapping a maple tree for sap. A meter-long bit drills into the cell, allowing the molten iron to flow out. Then the hole is plugged with a ceramic clay until the next tapping.
Though the equipment runs constantly at a temperature of about 1,600 degrees Celsius, the air just a few feet away remains cool. The entire production floor is light and clean, and the only noise is a low buzz from the machines — a far cry from the traditional sweltering, clamorous steel mills.
The electricity powering the process runs from an anode at the top of the chamber to the molten metal, which acts as a cathode. The anode is one of Boston Metal’s major technological innovations. For the equipment to produce significant quantities of molten iron, the anode must be made of a material that can resist corrosion in the oxygen-rich environment. MIT researchers developed an alloy that can do just that.
The anode “can run for a month and it comes out the same shape and size,” Rauwerdink said, noting that the company relies on laser imaging to precisely find and measure even the most miniscule changes.
The first trial runs in the MIT lab used an anode about the size of a marble and produced a roughly 1-gram nugget of purified iron. At Boston Metal’s 38,000-square-foot facility in a Boston suburb, five of these small-scale systems are still in operation, allowing technicians, over the course of several hours, to see how variations in the electrical current or the electrolyte composition affect the process.
Several midsize systems also run in the facility as does one full-scale cell that can produce roughly a ton of purified iron per month using 10 anodes, each roughly the size and shape of half a basketball. When expanded to production scale, each cell can be fitted with more anodes, and each operation can have multiple cells running. Rauwerdink estimates that commercial producers will be able to put out multiple tons every day.
As Boston Metal continues to refine its system, it is also trying to work its way toward profitability. To get there, company leaders have decided on a strategy that, perhaps unexpectedly, puts steel on the back burner for the moment.
The key is niobium, a metal that is valuable as an alloying element in steel production and that can be extracted from other materials using molten oxide electrolysis. Niobium sells for about $82 per kilogram (about $74,000 per ton) right now, according to the Shanghai Metals Market, while steel goes for roughly $900 per ton. Boston Metal plans to focus on extracting and selling the metal for now, to start bringing in money while continuing to finesse its method for producing green steel.
In 2023, the company began building a facility in Brazil to extract niobium from mining waste and industrial slag. The first cell in the operation should come online this month, and revenue is expected to start flowing later this year.
“That’s a big milestone for us,” Rauwerdink said.
This graduated approach gives the company some stability at a time when the future of green steel in the U.S. is anything but certain.
Last year, the Biden administration awarded $500 million each to two projects aiming to make low-emissions steel using hydrogen for DRI. However, one recipient, Cleveland-Cliffs, has announced that, in light of the Trump administration’s preferences, it will instead be relying on “more economical fossil fuels” and also prolonging the life of an existing coal-burning blast furnace. Further, as Japan’s Nippon Steel looks to acquire U.S. Steel, Trump has touted the possibility of keeping the operation’s coal-burning blast furnaces up and running for another 10 years. The Trump administration has also halted or rolled back much of the funding Biden had dedicated to green steel development.
Boston Metal, however, is somewhat insulated from these headwinds. While Trump’s funding moves have created economic uncertainty, the company is not directly supported by any federal grants, though it has received some federal support in the past. The company is waiting to hear the fate of a $50 million grant related to chromium production, but the outcome will have no effect on its plans to commercialize the molten oxide electrification process. And because the system doesn’t use any fossil fuels, the political battles over coal and natural gas have little relevance.
Boston Metal plans to build a demonstration plant for steel production by 2028 — it’s still looking for the right site — then take the system to market. The company intends to license the technology to steel-making operations, rather than owning and operating facilities itself, and is already exploring opportunities in the United States, Europe, the Middle East, and Asia, Rauwerdink said.
Producers using Boston Metal’s technology are likely to seek out locations with a clean, low-priced electric supply to maximize the economic and environmental advantages, he said.
Boston Metal’s technology and that of other companies exploring the use of electricity hold a lot of promise, but plenty of questions and hurdles remain, Ramirez said.
“They’re very exciting, and they definitely have a role to play,” she said. “The questions are timeline and scale.
A correction was made on June 5, 2025: This story originally misidentified Boston Metal’s initial source of revenue. It will be from the sale of niobium, not from steelmaking. The story also originally misstated the material from which Boston Metal will extract niobium. The firm will extract niobium from mining waste and industrial slag, not iron ore.
Modern farming depends on massive amounts of ammonia fertilizer, almost all of it made from fossil gas in enormous chemical plants. These facilities use high heat and pressure to split that gas, mostly made up of methane, into hydrogen and carbon dioxide. The carbon dioxide goes into the atmosphere, and the hydrogen is mixed with air, where it bonds with the nitrogen under high pressure via the century-old Haber-Bosch process.
The resulting ammonia is a carrier for the nitrogen that plants crave, but producing it this way is highly carbon-intensive, accounting for nearly 2 percent of global carbon dioxide emissions today. And that ammonia can be costly. The farmers who purchase it are subject to severe price spikes tied to the volatile fossil gas market. Transporting the fertilizer to farmers from where it is produced also adds hundreds of dollars per ton.
Outside the town of Boone, Iowa, startup Talusag and Landus, one of the state’s biggest farming cooperatives, are working on a new method for producing ammonia — tapping electricity to make the chemical from water and air, using technology that could be deployed at modular scale across the country and around the world.
Talusag’s first pilot-scale facility in North America, built at a cost of about $5 million and powered by on-site solar, is capable of producing 1 to 2 tons of ammonia per day, said Talusag CEO and co-founder Hiro Iwanaga. Earlier this year, a test batch was applied to farm fields, marking the first commercial delivery of “green ammonia” from a small-scale facility in North America, according to the partners.
Talusag has already started building a larger project in the nearby town of Eagle Grove, Iowa, that will be capable of producing up to 20 tons of ammonia per day. That facility, which Iwanaga said will cost about $15 million and be running later this year, will tap into grid supplies of wind power, which provides nearly three-fifths of Iowa’s annual electricity generation.
Twenty tons per day is a drop in the bucket compared to the roughly 14 million metric tons of ammonia produced in the U.S. last year or the approximately 240 million metric tons produced globally. But Iwanaga is hoping that his company’s modular systems, which can run on intermittent renewable electricity and be sited closer to farms, can start to provide an alternative to fossil-derived ammonia that’s cheaper and more reliable.
“We only deploy projects where we are cost-competitive or better with the incumbent competition,” he said.
That’s fairly straightforward in the markets that Iwanaga and his team initially targeted. The startup launched in 2021 “largely as a philanthropic venture” to help farmers in developing countries, he said, where fertilizer is far more expensive due to shipping costs. Its first project uses solar power at a nut farm in Kenya, for example. Talusag is pursuing more projects for remote farms, as well as for mining operations that use ammonia to produce explosives, where transportation costs are a significant burden.
But even in America’s agricultural heartland, Talusag can propose long-term contracts at set prices at or below the cost of ammonia shipped via pipeline from the Gulf Coast and then by tanker trucks to further-flung farms, Iwanaga said.
There’s an important caveat to that, however. Talusag’s ammonia is only cost-effective in U.S. markets if generous federal incentives for producing hydrogen with low or zero carbon emissions remain in place — a prospect that is looking increasingly uncertain.
Talusag’s facilities use electrolyzers to split water into oxygen and hydrogen. The gas, commonly called “green hydrogen,” is then fed into miniaturized versions of the gigantic Haber-Bosch reactors at industrial ammonia plants. That chemical process yields no greenhouse gas emissions — and if it uses clean electricity, it’s completely carbon-free.
Those green credentials are a nice “ancillary benefit” of the green ammonia that Landus plans to obtain from Talusag’s two Iowa facilities, said Brian Crowe, the cooperative’s vice president of strategic initiatives. But far more important to Landus and its farmer-owners are the prospects of securing a lower-cost source of fertilizer that’s made closer to home, he said.
Landus was first introduced to Talusag back in 2022, when ammonia prices rose to nearly double their typical levels, due in large part to the global disruptions to fossil fuel supplies caused by Russia’s invasion of Ukraine, Crowe said. Landus buys, stores, and transports tens of thousands of tons of ammonia per year for its farmer-members, and the agriculture industry at large was “kind of scrambling to figure out, how do we hedge against this?”
The Talusag offering “seemed like a practical solution,” he said. “Make it close to where it’s needed, do it modularly, and lock in the price to create more price stability. They produce it, we take it and pay them for it — or they don’t, and we don’t.”
Iwanaga noted that Landus isn’t taking on financial risk with these projects. Talusag pays for building and producing its green ammonia. That structure puts the pressure on Talusag to deliver on the quality and the low price it has promised to buyers.
But it also potentially provides the company with the long-term revenues it needs to secure project financing, rather than relying on equity capital. Talusag raised a $22 million Series A round in 2023 and is exploring projects with other farmer cooperatives in the Midwest and Pacific Northwest, as well as outside the U.S., Iwanaga said.
Shorter supply lines and fixed long-term prices are valuable features of Talusag’s modular model for producing green ammonia. But Iwanaga conceded that the company’s future in U.S. markets hinges on a key federal incentive that may not be around much longer — the 45V hydrogen production tax credit created by the Inflation Reduction Act.
Last week, Republicans in the House of Representatives passed a reconciliation bill that calls for all but eliminating the federal clean energy tax credits created under the IRA. That includes ending 45V credits for any project that can’t begin construction before the end of 2025.
Talusag’s two projects in Iowa would squeak under that deadline, and the company may be able to start additional projects before year’s end, Iwanaga said. But if the final bill does kill the 45V credit, that would rule out starting up any other U.S. projects for the foreseeable future, he said.
Robin Gaster, research director at the Center for Clean Energy Innovation at the Information Technology and Innovation Foundation think tank in Washington, D.C., noted that would-be commercial-scale producers of ammonia fertilizer made from green hydrogen face a tough road in U.S. markets.
“It’s an interesting idea for developing countries, partly because there are supply-chain issues so often,” he said. But “I would be surprised if there were places in the United States where the supply chain and commodity costs were so bad that green ammonia is a competitive option.”
The economics of green hydrogen production do not stand up on their own without subsidies like the 45V tax credit, he said. Today, hydrogen produced in the U.S. with fossil gas — referred to as “gray hydrogen” — costs between $1 and $2 per kilogram, depending on the price of fossil gas, whereas green hydrogen costs $5 per kilogram and up. “The first question is obviously on cost, and whether they expect this to rely on subsidies forever.”
Crowe noted that there’s an important distinction between green hydrogen used to make ammonia for agriculture and green hydrogen that could potentially be used for industries such as trucking, shipping, and steelmaking. Farmers need ammonia now, and enormous quantities of gray hydrogen are already being used to produce it, while retooling industries like trucking and shipping to use hydrogen would require massive investments in new systems and infrastructure.
The on-again, off-again nature of U.S. clean hydrogen policy has made long-term commitments to green ammonia a tough sell. Some companies that announced ambitious plans to produce green ammonia in 2023 and early 2024 failed to follow through with real-world investments after the Biden administration instituted more stringent clean-energy tracking rules for the 45V credit than industry groups had hoped for. Cutting off the tax credit completely would make the economics of such projects even worse.
Iwanaga pointed out that Talusag’s technology has some advantages over large green ammonia projects, however. For one, the company’s modular systems can be manufactured and deployed in small increments, an advantage over gigantic chemicals facilities, so that exposes Talusag’s investors to less risk, he said.
Talusag’s systems were also designed expressly to run on intermittent clean power, like the solar power serving off-grid or remote farms that were its initial target customers, he said. Most electrolyzer technologies don’t perform as efficiently when they’re forced to ramp up and down frequently to follow fluctuations in power supply. Talusag must deal with those challenges as well, but has incorporated several design features that minimize the efficiency losses, he said.
Talusag’s green ammonia technology isn’t the only one designed to use solar and wind power when it’s available. But being able to do that is a prerequisite not just for systems that rely on their own solar power, but also for grid-connected systems trying to capture the cheapest power available — which more and more frequently is also the cleanest.
Take the wind energy that makes up an increasing share of the electricity flowing across Midwest power grids. Iowa is the second-largest wind power producer after Texas, with 59% of its annual net generation coming from wind in 2023. Other Upper Midwest states heavy on wind power as of 2023 include South Dakota at 55% of annual net generation, North Dakota at 36%, and Minnesota at 25%.
Wind farms produce when the wind is blowing, which isn’t always when most customers are using electricity — and the more surplus wind power is available, the cheaper it is, Iwanaga said. That creates strong long-term prospects for using excess wind energy to make hydrogen, which could eventually make up for the absence of federal clean-hydrogen incentives, Iwanaga said — even if the economics aren’t there yet.
A similar concept has informed a long-running green ammonia project being conducted by the University of Minnesota West Central Research and Outreach Center, the Minnesota Farmers Union, and other groups. Since 2013, an on-site wind turbine has generated power used to electrolyze hydrogen and turn it into green ammonia. In 2023, the Minnesota state legislature created a $7 million grant program to incentivize farmer ownership of green ammonia.
Rural electric cooperatives — member-owned and -operated entities that supply power to the most sparsely populated parts of the country — may also be interested in green ammonia projects that can capture the value of wind power that might otherwise need to be curtailed, Iwanaga said. “If we can absorb some of those peaks, there are cases we are looking at where the rural electric cooperatives think it could potentially lower the cost of power.”
Gaster noted that access to cheap electricity could allow green hydrogen to compete economically with traditional ammonia production. “The cost of generating hydrogen is almost all in inputs — it’s all in the electricity,” he said.
It’s hard to say how the climate benefit of making green ammonia might stack up alongside the benefit of producing green ammonia locally, Iwanaga said. “It’s up to each customer to judge how valuable that is.”
Crowe said that Landus hasn’t yet considered the prospects of earning money from the carbon emissions prevented by buying Talusag’s green ammonia. “We don’t know exactly how it’s going to be monetized yet. But to have that in our back pocket in the future is, I think, valuable.”
A correction was made on May 29, 2025: A previous version of this story misattributed a statement regarding Talusag’s Series A fundraising and its work with prospective customers to Crowe. The information was shared with Canary Media by Iwanaga.
The global chemicals industry is big, and it’s dirty. Chemical plants consume lots of fossil fuels, both to power the high-temperature, high-pressure processes involved and often as a feedstock for the chemicals produced. And to maximize production, those plants are typically built to be as large as possible.
Todd Brix, CEO of startup OCOchem, has a different vision for how to build a modern chemicals industry: Manufacture lots of small machines that are powered by electricity instead of fossil fuels to do the work.
“The way we make cars, the way we make TVs, the way we make semiconductor chips should be the same way we make chemicals plants,” Brix said.
Last week, the company’s pilot plant in Richland, Washington, started producing a class of chemicals known as formates, used in everything from deicing airplanes to preserving animal feed. But instead of the conventional hot, dirty method of combining methanol with carbon monoxide derived from fossil fuels, OCOchem makes formate with just water and carbon dioxide inside four 1.5-meter electrolytic modules.
OCOchem fills those modules with water and carbon dioxide and then zaps the solution with electricity, causing an electrochemical reaction that yields formic acid, a combination of hydrogen, oxygen, and carbon. Chemically speaking, it’s “one of the simplest molecules you can imagine,” Brix said — basically, “CO2 with two hydrogen atoms attached to it.”
The $5 million project can make up to 60 tons of formic acid per year. That’s not a lot, compared with the roughly 1 million tons per year of formates produced globally. But being able to deliver an industrial chemical cost-effectively in such small amounts is one of the selling points, Brix explained.
“Once you want to scale out and make more formate, you just make more modules. That’s the power of economies of scale of mass production,” he said. “We can rapidly scale that technology out, and make a lot of little chemical plants, and stack them together.”
Factory-built modular devices are being tried out across various industries, from fertilizer to steel — and they are even being considered for nuclear power. It’s already a winning pathway in the renewable energy sector, where mass-produced solar panels and lithium-ion battery cells have seen costs drop steeply as production volumes increase and manufacturers consistently improve each new generation of products.
“What the solar industry does is mass-produce solar panels — and what we are trying to do is mass-produce chemical plants,” Brix said. “That allows you to dramatically lower the costs over time.”
Tiny chemicals-production cells are a bit more complicated than solar panels, of course. But OCOchem’s electrolytic cells aren’t taking on anything as dangerous as nuclear fission. Brix described the process as akin to “artificial photosynthesis.” Plants use water, carbon dioxide from the atmosphere, and the energy from sunlight. OCOchem cells, which operate at ambient temperatures and pressures, electrify water and carbon dioxide and emit only formic acid, which is corrosive but not flammable or explosive.
Using electrolysis to produce formate is far from a unique idea, said Brix, who worked at Chevron, Intel, and Microsoft before founding OCOchem in 2020. In fact, researchers have been trying to do it for decades. But the efforts he’s aware of have struggled to expand cells to a size that can support commercially viable volumes.
“We started with a reactor that was 10 square centimeters in size,” Brix said. “We’ve scaled that up by a factor of 1,500.” OCOchem has developed patented technologies that can handle the required current density, or electrical throughput, to achieve this increased size and manufactures these key components itself. It then works with a contract manufacturer to assemble them into cells, which otherwise use off-the-shelf equipment from other electrolysis-based industries.
OCOchem raised $5 million in 2023 and has secured federal and state grants for its early technology development, as well as an undisclosed amount of early-stage support from Halliburton Labs, the tech accelerator of oil services company Halliburton. The four cells in the pilot facility are the first it’s produced via this assembly-line process, Brix said, but the company is preparing to scale up its manufacturing to meet orders for more than $300 million in prepurchase contracts.
Those contracts are for the formate it will make, not for the equipment itself, he noted. “Our goal is to be the developer of the technology and operator of the plant and share ownership of the plant with various partners.”
OCOchem’s process emits no carbon dioxide, unlike the fossil-fuel-based processes used to make formates today, Brix said. Much of the world’s supply of the chemicals is from factories that are part of China’s expanding coal-fed chemicals industry. Whether OCOchem’s formate is considered low-, zero-, or negative-carbon depends on two key factors: the carbon footprint of the electricity used to make it and the carbon dioxide going into its cells.
Right now, OCOchem plans to get its CO2 “from the highest purity and cheapest sources we can find,” Brix said. “That turns out to be biogenic CO2,” or gas captured from ethanol plants, breweries, wastewater-treatment facilities, and similar sources. Some of that CO2 is used today as coolant in refrigeration and for carbonating beverages. CO2 that can’t find industrial purchasers is either captured at the expense of its emitter or, far more often, vented into the atmosphere, which contributes to climate change.
Plenty of industries, ranging from sustainable aviation fuel to lower-carbon cement, are planning to rely on captured CO2 to decarbonize. Consulting firm EcoEngineers studied OCOchem’s process and found that every ton the company produces could avoid a combined 7.2 tons of CO2 emissions, compared with fossil-fuel-fed formate production, both by displacing fossil fuels and fixing captured CO2 in the formic acid it makes.
But OCOchem doesn’t need a “green premium” for its low-carbon bona fides, Brix said. Instead, it’s relying on offering customers a cost-competitive alternative to formate shipped from overseas. That’s not possible with its pilot-scale facility today, he stressed. But “even at 10,000 tons per year, which is a small chemical plant, we’ll have lower cost of production” than typical fossil-fuel-fed plants. “We can say, ‘Whatever your market price is, we’ll meet it.’”
More chemical markets beckon. Formic acid can be processed into a number of organic compounds, including many now made from fossil fuels, he said — “not because they’re higher performance, or cleaner, or cheaper, but because they do the job good enough.”
Formates and formic acid could also serve as “hydrogen carriers,” Brix said. Hydrogen, when it’s produced in ways that don’t cause greenhouse gas emissions, can be used to cut the carbon impact of industries from steelmaking to shipping. It’s unlikely that OCOchem’s formates would be a cost-effective source of hydrogen at large volumes, but they could serve as a convenient medium for transporting hydrogen in trucks, he said.
The trick is to find cost-effective ways to separate the hydrogen molecules from the formates once they reach their destination, said Ye Xu, associate professor of chemical engineering at Louisiana State University. Xu specializes in research in surface chemistry and heterogeneous catalysis — the fundamental study of the interaction of solid catalysts with molecules. He’s been working on a project to crack hydrogen from formates in a way that’s economically viable—one of many being funded by the U.S. Department of Energy.
“If you need to transport huge quantities of hydrogen atoms, you have to compress hydrogen gas under extremely high pressure. That causes cost problems and safety problems,” Xu said, especially for chemicals being transported by truck or train. Hydrogen-bearing formates, by contrast, are “not flammable. They don’t explode. They are not toxic. These are some very attractive characteristics.”
When it comes to separating the hydrogen atoms from formate molecules at the end of the journey, so far “the stumbling block is the speed of the reaction,” he said. “Formates are stable substances and slowly decompose on their own.” Speeding up the process requires a catalyst, and “according to the scientific literature, the only catalyst that works is palladium” — a costly metal, which, like the chemically similar platinum, is already in high demand for electronics, automotive, and many other industrial uses.
Xu’s search for substitute catalysts to make formate a viable hydrogen carrier involves massive computational research as well as collaboration with scientists doing real-world research. In a way, Brix noted, it’s a similar process to the years of research that have gone into OCOchem’s core technologies, such as the gas-diffusion electrodes that allow it to electrolyze water and CO2 at commercial-scale volumes.
Taking such experiments from laboratory to pilot project to commercial production may be labor-intensive and costly. But building, testing, and redesigning the next generation of technologies is a lot easier and faster on an assembly line than as part of a complicated, yearslong engineering, procurement, and construction project to build large-scale facilities, Brix said.
“We’ve built the best little Lego block we can. Now we want to stack the Lego blocks together,” Brix said, and “just build more and more stacks. And from there, it’s rinse, lather, repeat.”
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