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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.”
Supporters of a major clean energy bill that fell short in the final days of Illinois’ legislative session are licking their wounds and trying to figure out what went wrong — and what comes next.
Solar and battery companies, clean energy groups, and consumer advocates just months ago had high hopes for the Clean and Reliable Grid Affordability Act, which would have created a bonanza of state incentives for energy storage and other grid investments, building on the success of 2017 and 2021 laws that have made the state a clean energy leader.
The legislation failed to pass as the legislature wrapped up at the end of May.
“There were some pretty significant wrenches” thrown in the works in the final days of negotiations, said Hannah Flath, spokesperson for the Illinois Environmental Council, an advocacy group. “Some things we just couldn’t untangle.”
The bill would have made Illinois one of a number of states offering subsidies for battery storage on the grid, with the goal of spurring 6 gigawatts of storage by 2030. Solar industry leaders enthusiastically backed the bill, seeing it as a way to build on the solar boom sparked by the two previous state laws, by facilitating solar-plus-storage projects.
Solar and batteries may also be the nation’s best bet to quickly meet growing electricity demand, as equipment backlogs slow down plans to build gas-fueled power plants. “The only resource that we believe can [be deployed] in a time frame of a few years is energy storage,” said Andrew Linhares, the Solar Energy Industries Association senior manager for the Central U.S. “And of course, pairing it with solar is by far the cheapest new generation you can bring online.”
Cost concerns appeared to be the main reason that some powerful groups opposed the bill and that legislators didn’t embrace it. Utility customers would have picked up the tab for incentives paid to storage developers, which spooked some large industrial consumers and the labor unions representing their workers, according to people involved in the bill negotiations.
Groups that filed witness slips to the legislature in opposition of the bill include the American Petroleum Institute-Illinois, a labor union representing electrical workers in Southern Illinois, the Illinois Farm Bureau, the Illinois Chamber of Commerce, a chemical industry group, and an Illinois manufacturers’ trade group.
But investing in battery storage should actually lower energy bills, according to bill proponents, since it could be cheaper for utilities to develop storage than to supplement their power supply with pricey energy from regional markets.
Now proponents wonder whether expected energy-price spikes this summer could ironically persuade lawmakers to revisit the storage plan. Prices are expected to rise in coming months because the grid operators that cover Illinois recently reported high capacity costs to ensure that the grid has enough power-generating capacity if demand suddenly spikes. In the Chicago area, that’s expected to raise customers’ power bills by an average of over $10 a month.
An analysis by the Illinois Power Agency, which procures power on behalf of ComEd and Ameren, found that customers would pay less for electricity under the legislation. By 2035, the average Ameren residential customer could see bills drop by up to $20 a month, and the average ComEd residential customer could see monthly bills drop by up to $8.50.
“All the cost estimates were how much this [bill] would help lower costs. That is the big tragedy here,” said MeLena Hessel, Midwest deputy program director for the national clean-energy advocacy organization Vote Solar. “This bill would have saved people money. It would have immediately enabled us to deploy renewables and storage and energy efficiency too, which are the fastest, cheapest ways to address the rising capacity costs.”
Legislators aren’t scheduled to meet again until a short veto session in the late fall, but Gov. JB Pritzker, a Democrat, could reconvene the legislature sooner. The 2021 Climate and Equitable Jobs Act, which created expansive solar incentives and equity provisions, was passed in such a summer special session.
“The consensus language around energy storage and solar is a response to this crisis, and we have broad buy-in from lawmakers. We’re pretty confident at the end of the day this will happen,” said Linhares. “We just need everybody to be pulling in the same direction. We’re eagerly awaiting an announcement about when this might be taken up, whether in the veto session or special session, and we’ll be ready when that announcement comes.”
Illinois’s two previous big energy laws — the Climate and Equitable Jobs Act in 2021 and the Future Energy Jobs Act in 2017 — were passed after clean-energy developers and advocates squared off with fossil-fuel companies and utilities. In both cases, incentives for nuclear energy provided the political push over the finish line.
This time around, there is no incentive for nuclear on the table; nor is the industry seeking one since increased electricity demand — including from data centers — has boosted the fortunes of the state’s once-financially-ailing nuclear plants.
The bill did call for lifting a moratorium on new nuclear development, but that was considered largely symbolic since a 2023 law allowed development of small modular nuclear reactors.
Labor unions and workers groups helped push for the state’s 2021 climate law, but this time around, some unions opposed the bill. People involved in legislation negotiations said it seemed the unions had allied with oil refineries and utilities that were concerned about cost increases to fund battery storage.
“There were an incredible amount of stakeholders,” said Kady McFadden, legislative strategist for the Illinois Clean Jobs Coalition. “Advocates, consumer groups, environmentalists, utilities, generators, clean-energy companies, dirty-energy companies, data centers, towns, cooperatives. It’s a lot of work to run a process that involves them all and gets them all where you need them to be politically to pass a package.”
“This is the first energy bill of its size that didn’t have a big trade-off,” meaning incentives for nuclear, McFadden continued. “The recipe was a little different here. This is a really big jobs bill, but organized labor was neutral. The utilities would be getting a ton from the energy-efficiency programs, but they were neutral.”
Julie Russell, the chief county assessment officer in central Illinois’ Fulton County, said the bill would help county governments by creating uniform tax-assessment standards for battery storage projects.
“It removes the guesswork from how to value really complex projects such as this, plus it helps remove these from going to the property tax appeal board or getting caught up in court for several years being in limbo, with all the taxing districts involved,” Russell said.
Russell is also the county’s zoning supervisor (“fortunately or unfortunately for me” as she put it), and said a provision capping permit fees at $75,000 for energy projects could be problematic, since it “might not cover all the fees associated with making sure we are doing our due diligence” on sprawling proposals. “It would have had the potential to be a financial strain on counties.”
Along with installing large-scale batteries on the grid, the legislation would have created a “virtual power plant” program, allowing the networking of batteries scattered across homes and businesses that could be called on to provide power to the grid in times of high demand. The bill would have also created incentives to help low-income people get batteries in combination with solar arrays, potentially allowing them to earn revenue from a virtual power plant program.
McFadden said “the secret coolest part of the bill” was the mandate for state regulators to develop an energy generation and transmission inventory plan similar to the type of “integrated resource plan” that utilities are required to carry out in many other states. This planning process would alleviate the need for arduous legislative efforts, advocates said.
“It would be a transformation in how we would do energy planning and modeling in the state,” McFadden said. “It’s so significant because passing a giant energy omnibus bill every four to five years is a very poor way to do energy planning and modeling.”
An integrated resource plan would also be mandated for the many rural cooperatives and municipal utilities in Illinois. That would “increase transparency for people receiving power from these utilities, really putting the people power back into public power,” Vote Solar Illinois campaign manager Kavi Chintam said.
The setback in negotiations could allow proponents of the bill to build more support for provisions that had been stripped out during the session, namely one nicknamed BYONCE, pronounced like the singer but standing for “Bring your own new clean energy.”
That would mandate that power-hungry data centers fund their own new generation capacity, protecting other utility customers from subsidizing the mushrooming demand that data centers are expected to create in the Chicago area.
Once the federal budget passes, expected cuts to clean energy could also help motivate state leaders to enact legislation to fill the gap, advocates said.
“I’d love to see lawmakers respond to that opportunity to reconvene and tackle things on the state level,” said Flath. “Ideally, we’ll come back in the fall with an even stronger package.”
Amid rising power bills and surging energy demand, Republicans in Congress are set to undermine the country’s primary source of new electricity — clean energy.
The “Big Beautiful Bill” passed in May by House Republicans and now being considered by the Senate would rapidly phase out key clean-energy tax credits, casting uncertainty over more than 600 gigawatts’ worth of solar, battery, and wind projects slated to come online in 2028 or later, according to new analysis from research firm Cleanview.
To be fair, the 600-GW figure is based on what’s currently in the interconnection queue, and a good number of those projects won’t get built regardless of the fate of the tax credits. (Projects often drop out of the queue for all kinds of reasons.) But if the bill kneecaps even a fraction of what’s anticipated, it will have serious consequences for the U.S. energy system. For context, the entirety of the U.S. had a generating capacity of around 1,200 gigawatts at the end of 2023.
The current version of the legislation would rapidly phase out federal tax credits that encourage clean energy development. As it stands, developers would be eligible for the tax credit only if their projects begin construction within 60 days of the bill’s passage and if they come online before the end of 2028.
That puts the 318 GW worth of projects planned to be completed in 2029 and later at explicit risk of losing their tax-credit eligibility. It also jeopardizes 2028 projects that either can’t break ground with just two months’ notice or which might hit snags that push their completion into 2029.
That doesn’t necessarily mean those projects would be cancelled, but it would scramble their economics, which were calculated under an entirely different set of policy assumptions. It’s near certain that some would fall through. Many more would be delayed as developers hash out new financial terms — read: higher power prices that will be passed onto consumers.
A slowdown in clean energy construction is the exact opposite of what the moment demands.
These days, when a new energy project is built in the U.S., more than nine times out of 10 it is a solar, battery, or wind installation. That’s not an exaggeration. In 2024, solar, batteries, and wind made up 93% of new energy resources. The year before that, it was 94%. Meanwhile, construction of new large-scale fossil-gas power plants is constrained by turbine shortages that are unlikely to ease in the near term.
At the same time, electricity demand is surging and expected to climb even higher in coming years as the development of AI sets off a race to construct power-hungry data centers.
If congressional Republicans pass a bill that stifles solar, batteries, and wind, study after study predicts the same outcome: higher energy bills — and more planet-warming emissions.
On Wednesday, the U.S. EPA proposed repealing Biden administration rules that limit toxic pollutants and planet-warming emissions from coal and gas plants across the country. These plants “do not contribute significantly” to “dangerous” air pollution, the EPA claimed — something that many, many studies have shown isn’t true. Power plants are the second-largest source of carbon emissions in the country, and they’re responsible for a lot of health-harming pollutants like sulfur dioxide, nitrogen oxides, and mercury, too.
When the Biden administration first announced the rules last year, the EPA estimated they would stem 1.38 billion metric tons of carbon pollution through 2047. That’s the equivalent of taking 328 million gas cars off the road for a year, and amounts to an estimated $370 billion in climate and public health benefits.
Those benefits would’ve helped communities surrounding gas and coal plants around the U.S., according to the Sierra Club’s Trump Coal Pollution Dashboard. For example, Montana’s Colstrip 3 plant would have to reduce its toxic pollution under the Mercury and Air Toxics Standard, while a slew of plants across the Midwest and Southwest would have to install carbon-capture systems or shut down under the greenhouse gas rules.
The changes will allow coal plants around the country to keep burning. In North Dakota, some state officials are celebrating what they say is a big step toward protecting jobs and the coal industry. But in Georgia, health advocates and scientists warn the preservation of coal plants in their state will fall hard on vulnerable communities, especially those surrounding the facilities.
Still, none of this is set in stone. The EPA’s proposals are vulnerable to several legal pitfalls, including challenges involving the Clean Air Act, the agency’s insistence that power plants don’t produce “significant” emissions, and the health, economic, and other costs of increasing pollution, E&E News reports. Analysts with TD Cowen expect the EPA to finalize the rules by early next year, but say legal challenges and uncertainty will continue through all of 2026.
“Big, Beautiful Bill” threatens rooftop solar
President Donald Trump’s “Big, Beautiful Bill” is already having big impacts on the rooftop solar industry. The bill, now undergoing negotiations in the Senate, looks to repeal tax credits for solar installations and other clean energy projects. That includes credits that allowed a North Carolina food bank to install solar panels on the roof of its headquarters, which it anticipates will save the organization $143,000 each year. Other nonprofits are looking to follow suit — but they probably won’t be able to if they can’t access federal incentives, Canary Media’s Elizabeth Ouzts reports.
The bill is also causing problems for two solar companies. Lender Solar Mosaic filed for bankruptcy last week, specifically citing “legislation that threatens to eliminate tax credits for residential solar” as a forthcoming challenge. Residential solar giant Sunnova followed with a bankruptcy filing over the weekend.
While both companies’ difficulties predate the Trump administration, it’s clear that the residential solar sector is facing a difficult and uncertain moment, one analyst told Canary Media’s Jeff St. John. An analysis by Ohm Analytics estimates that the House’s version of the bill would lead rooftop solar installations across the country to drop by half next year, and another from Morgan Stanley projects an 85% decrease through 2030.
Bright spots for clean energy
Amid a sea of bad news for clean energy companies, some are still finding success.
Take Sublime Systems, which recently had its $87 million federal grant cancelled: Sublime says private-sector support is allowing its $150 million low-carbon cement factory in Massachusetts to move forward anyway.
Solar panel manufacturer Qcells said it’s launching a new recycling operation in Georgia to repurpose retired panels. Heirloom Carbon is meanwhile keeping its operations rolling by winning over Republican state leadership in Louisiana, where it aims to build a facility that extracts carbon dioxide from the air. Developer Intersect Power got the green light Wednesday to build what would be the biggest solar-and-storage plant in the nation.
And in the Chicago area, Sun Metalon just raised $9.1 million from investors — including Japan’s Nippon Steel — to build its steel decarbonization business, Canary Media’s Kari Lydersen reports. The startup has created an oven-sized box that melts down waste metal and sludge from steel and aluminum production, churning out pucks of reusable, recyclable metal.
Vehicle emissions blowback: A group of 11 states sue after President Trump signs a congressional resolution rolling back California’s vehicle emissions standards, which several other states have adopted. (The Hill)
Budget bill update: Democrats — and some Republicans who voted for the House-passed version of the “Big, Beautiful Bill” — look to convince Senate Republicans to preserve clean energy tax credits as budget discussions continue. (The Hill, Politico)
Community electrification: California researchers report success and lessons learned from an experiment aimed at cutting electrification costs by upgrading multiple households in a single neighborhood, which saved contractors time and allowed residents to buy products in bulk. (KQED)
GM reverses on EVs: While General Motors is still ramping up EV production, its new plan to spend $4 billion on mostly gasoline-powered cars means the company has given up on a goal to make only EVs by 2035, analysts say. (E&E News)
Texas’ gas commitment: A study finds developers have proposed more than 100 gas-fired power plants totaling 58 gigawatts in Texas, which have the potential to emit an estimated 115 million metric tons of greenhouse gases every year. (Inside Climate News)
Charging forward: A J.D. Power survey finds fewer attempts to charge at public EV stations are ending in failure than in years past, and that the total number of public chargers is rapidly expanding. (New York Times)
Batteries’ battle: U.S. battery recyclers face“a limbo moment” because the Trump administration has endorsed efforts to produce critical minerals while also imposing tariffs and threatening to repeal clean energy tax credits. (Grist)
A legislative proposal in Maine that would impose new fees on community solar projects is having a chilling effect on solar developers, some of whom say they may stop working in the state, or even already have.
“The problem is that they’re looking to change the rules of the market after the fact,” said Brendan Bell, chief operating officer of Aligned Climate Capital, which owns several community solar projects in the state. “We’ve already stopped investing in Maine because of this. Simply the risk of this happening has made us stop.”
The legislation, which was approved in late May by the Energy, Utilities, and Technology Committee, aims to reform Maine’s net energy billing program — often called net metering in other states — which pays the owners of solar panels for the excess energy they share with the grid.
Nationally, net metering programs have been contentious, with states like California, New Hampshire, and North Carolina making big changes to mixed — and sometimes litigious — receptions. Maine’s system has been under scrutiny for years, as many critics say it has created excessive profits for developers while unfairly shifting costs to consumers who don’t even use solar power.
While many renewable energy advocates and developers agree that the program needs some reform, they say the current bill goes too far. The legislation outlines a new system for compensating commercial and industrial customers who own solar panels. Currently, the compensation rate is based on standard utility electricity rates, meaning solar owners make more revenue when power prices rise. The bill would require a new mechanism of gradual, annual rate increases to avoid excessive windfalls for solar owners when energy costs go up.
Of particular concern, however, are other provisions that apply to community solar developments, larger-scale installations that sell power to multiple subscribers.
In 2019, reforms to Maine’s net energy billing program paved the way for community solar to take off in the state. As of 2021, 79 megawatts of community solar capacity had been installed; as of May, that number is up to 1,008 MW.
“Community solar is incredibly important to Maine,” said Kate Daniel, Northeast regional director for the Coalition for Community Solar Access, a national trade group. “It’s been the driver of the new clean energy that’s gone onto the grid in recent years.”
The bipartisan legislation now under consideration would impose a monthly fee, paid by community solar owners to utilities. The money would be intended to cover the cost of delivering the solar power to consumers. Those “distribution costs” would otherwise be borne by utility customers.
Projects between 1 MW and 3 MW in size would pay $2.80 per kilowatt of capacity — so $5,600 a month for a 2-MW project, for example. Larger arrays between 3 MW and 5 MW would pay $6 per kilowatt — so, $24,000 per month for a 4-MW installation. These rates would be increased as needed to keep up with the cost of maintaining and expanding the grid. The goal, proponents say, is to continue supporting solar in a way that does not add to residents’ financial hardships.
“It is really important to me that we are fighting climate change in an economically just way,” said Rep. Sophie Warren, a Democrat and one of the bill’s sponsors.
However, renewable energy advocates and solar developers say the monthly fees could scare away new projects as well as put existing operations at risk.
“It basically … will consume all of our free cash flow and put us in a position where we may default on our loans,” said Cliff Chapman, CEO of Syncarpha Capital, a New York-based clean energy investment firm with eight community solar projects operating in Maine.
Opponents question the way these fees came to be included in the bill. They were not in the original draft legislation, but the idea was raised and voted on during committee debate. The language is in the process of being officially added to the bill so that lawmakers can report it out of committee and send it to the House floor. It is concerning that the fees received no public hearing, and many stakeholders and lawmakers are not even aware they are being added in, said Eliza Donoghue, executive director of the industry group Maine Renewable Energy Association.
Even if this bill fails to pass, the damage may already be done: Investors in all sorts of clean energy segments are becoming wary of doing business in a state that would even consider retroactively changing the rules for projects that were designed and financed under a different set of expectations, opponents said.
“It’s a retroactive policy proposal that many folks strongly believe would cause significant financial harm to the solar industry in Maine,” said Lindsay Bourgoine, director of policy and government affairs for Maine-based solar company ReVision Energy.
Opponents also worry that the bill sends the inaccurate message that increasing solar adoption makes energy more expensive, when research suggests the reverse is true. In 2024, solar development in Maine yielded about $1.42 in benefits for every dollar of cost, according to a report by state utilities regulators. As of the second half of 2024, net energy billing added about $7 per month to the average residential electric bill in the state.
Warren, however, says reining in even this modest increase could help some of her constituents.
“I know there are people on reverse mortgages, on fixed incomes, who are rationing their medicines,” she said. “These [compensation] rates are far too high, and unnecessarily high for what we’re getting from them.”
Bill proponents are also not convinced by claims that the new rules would cause financial problems for developers. The provisions are designed to have less financial impact on smaller companies that are less able to take the hit, said Maine Public Advocate Heather Sanborn, a supporter of the bill.
The bill also contains important consumer protections that opponents aren’t talking about, Sanborn said. Community solar operators would be required to rightsize customers’ subscriptions, preventing them from paying for more credits than they can use. Should a customer still end up with more credits than they need, the operator would be required to issue a refund. The legislation would also encourage the installation of battery storage in conjunction with solar.
“It is a responsible and balanced solution,” Sanborn said.
For opponents, however, the community solar fees are an intractable problem that outweighs any other provisions.
“What we don’t do in America is change rules retroactively and blow up existing investment,” Chapman said. “Being a state that does something like this has huge implications — they’re making themselves a pariah for investors.”
U.S. companies that install and finance residential solar have been struggling for years with rising interest rates and unfavorable policy shifts in California, the country’s biggest rooftop solar market. Now, they face an even more serious threat — Republicans in Congress, who have proposed to take away the tax credits that undergird the industry.
These mounting pressures have driven two of the most prominent firms in the U.S. residential solar sector into bankruptcy in recent days.
Residential solar provider Sunnova filed for Chapter 11 bankruptcy protection on Sunday, three months after the publicly traded company warned investors that it could run out of cash due to falling sales, rising operational costs, and a growing debt burden. The Houston-based company, which reported 3 gigawatts of solar and battery systems under management as of the end of 2024, stated on Monday that it “intends to continue operating its business in the ordinary course throughout the sale process.”
Privately held solar lender Solar Mosaic filed for Chapter 11 bankruptcy protection on Friday, stating it has taken action to “reorganize the business to meet its current liquidity needs.” The Oakland, California-based company, which claims it has funded $15 billion in loans to more than 500,000 households, cited “[m]acroeconomic challenges facing the entire residential solar industry, including high interest rates and legislation that threatens to eliminate tax credits for residential solar.”
Those two companies have unique problems that have contributed to their financial collapse, said Joe Osha, an analyst at Guggenheim Securities. “The causes of the difficulties that Mosaic and Sunnova face predate Trump,” he said.
But they also suffered from a market environment that is increasingly difficult and uncertain for every firm in the sector, he said.
The reconciliation bill passed by the House of Representatives last month and now being considered in the Senate would abruptly end a tax-credit regime that’s supported households and solar installers for the past 20 years.
The bill would terminate the 30% tax credit available to households installing solar panels, batteries, inverters, and associated solar equipment at the end of 2025, essentially making those installations about one-third more expensive than they are today.
And the legislation would eliminate the tax credit of 30% or more available to companies that lease solar panels to households and businesses. That would be a blow to firms like Sunnova and Sunrun, the country’s top residential solar company, which have made such third-party ownership structures central to their business models.
All in all, the changes in the House bill could mean U.S. households install 40% less solar over the next five years compared to current policy, according to research firm Wood Mackenzie.
That’s not just a threat to large companies like Sunrun and Tesla, but also to the regional and local businesses that are responsible for a majority of the roughly 5 million rooftop solar systems installed in the U.S. to date — and to a source of zero-carbon energy that stood at more than 50 gigawatts of generation capacity as of 2024.
That bill hasn’t been passed yet, however. Osha warned that it’s too early to extrapolate broader implications for the industry at large from these latest bankruptcies.
That’s because both Mosaic and Sunnova have fallen prey not only to challenging business conditions, but to mistakes in how they’ve reacted to the sector’s ongoing woes, he said.
“The way this business works, at the most basic level, is that you spend money now to create a long stream of contracted cash flows in the future,” Osha said. In the case of solar companies like Sunnova and Mosaic, those cash flows come from households making payments on the loans, leases, or power purchase agreements they’ve signed. The companies bundle those into asset-backed securities for sale to investment banks and other financial firms.
But those securities become far less attractive to buyers when the market for residential solar sours — and in the past year it has soured dramatically. Wood Mackenzie reported a 31% drop in U.S. residential solar installations in 2024 from the prior year.
The Solar Energy Industries Association reported in March that last year’s sales hit a low not seen since 2021. The trade group’s latest data, released this week, shows that “we have now had six consecutive quarters of year-over-year decline in residential solar installations,” Pavel Molchanov, investment strategy analyst at financial services firm Raymond James, pointed out. That includes a 13% year-over-year decline in the first quarter of 2025.
“In any industry, six consecutive down quarters is going to lead to pressure on companies across the board,” he said. “There’s just no escaping that.”
This downturn left Sunnova and Mosaic exposed to a cash crunch, Osha said.
Over the past 18 months or so, Sunnova had chosen to take on large amounts of corporate debt rather than selling off more of its portfolio to raise cash, he explained. As the market turned, finding buyers for those solar-backed assets became harder, making it difficult to raise cash to meet debt payments. The firm listed estimated assets and liabilities of $10 billion to $50 billion and debt of $10.67 billion as of Dec. 31.
Mosaic most likely experienced a similar liquidity crunch as it was unable to sell its portfolios of solar loans at the volume and price required to raise enough capital for new loans, Osha said. In a Monday analyst note, he highlighted that Mosaic had also “failed to make the transition from solar loans to third-party ownership” as interest rates climbed, making loans more expensive options compared to leases or power purchase agreements.
Molchanov emphasized that “financing is at the center of how this industry has historically functioned.” The companies in question built their businesses during the 2010s, when the country had historically low interest rates. But those interest rates have spiked in the past three years in response to the Covid pandemic’s economic disruptions and resulting inflation, driving up the cost of capital for all businesses — including companies borrowing money to install rooftop solar systems.
“There’s a very narrow pathway to navigate when the broader interest rate environment is so difficult,” Molchanov said. “Whatever strategic or tactical mistakes companies made, if we had this conversation five years ago, when interest rates were close to zero, those mistakes would not have been lethal. But now they can be lethal.”
Sunnova is the latest in a string of residential-solar bankruptcies in the past two years, which has included firms from regional installers and financing providers to icons of the industry like SunPower, which collapsed in August 2024. Solar lender Sunlight Financial, which offered lending options similar to those from Mosaic, declared bankruptcy in 2023 and emerged from reorganization later that year.
Filing for bankruptcy protection doesn’t necessarily mean that the companies will cease to exist. Some of SunPower’s business was purchased by Complete Solaria, which has since rebranded under the SunPower name, for example.
Nor does bankruptcy mean that customers will be bereft of customer service support for the solar systems these companies have financed, although that’s certainly a risk, as customers across the country have attested.
It’s also important to distinguish these newly bankrupt companies from others in the space, Osha said. For example, Sunrun, the biggest U.S. residential solar installer with roughly 10% of the market as of 2023, has better managed its way through the market downturn of the past 18 months or so, he said.
“What Sunrun has done in contrast to Sunnova is say, ‘We’re going to sell off those future cash flows to the greatest extent possible, so that we have money today,’” he said.
The House bill’s provision that would cut off tax credits for solar leasing does, however, pose a significant threat to Sunrun’s predominant business model of offering leases and power purchase agreements to residences, Osha said.
The House bill would not cancel tax credits for power purchase agreements, the other primary mechanism for companies that offer third-party-owned solar, Osha said. But in his Monday research note, he opined that this exclusion was “a loophole, not a deliberate plan on the part of legislators,” and that incentives for power purchase agreements would likely suffer the same fate as those for leases and homeowners in a final bill to emerge from Congress.
Whether tax credits expire abruptly at the end of 2025 or there’s an extension beyond that will have a significant impact on the financial viability of large-scale residential solar companies like Sunrun.
“Today, Sunrun’s business model is entirely centered on third-party ownership and tax credits,” he said. “But you can also say that they are a very well-run company that has surely thought about this, and [it] is likely, if the hammer does come down, they have a plan.”
At the same time, thousands of smaller companies that make up the majority of residential solar installations would almost certainly suffer from the tax-credit changes, even if their challenges go less noticed than those of industry stalwarts, said Kristina Costa, former clean energy adviser for the Biden administration.
That would have negative consequences for those working in the industry. Residential solar installation accounted for just over 100,000 jobs in the U.S. at the end of 2023, according to the most recent survey from the Interstate Renewable Energy Council. The current market downturn has already had a negative impact. The California Solar and Storage Association estimated that roughly 17,000 people, or 22% of the state’s distributed solar and storage workforce, lost their jobs between April 2023, when the state reduced incentives for rooftop solar owners, and the end of that year.
“You have a lot of mom-and-pop small business outfits in the solar residential space that are going to be profoundly affected by this bill that’s being debated in Congress right now,” Costa said. “It will be harder and more expensive to install solar and storage in homes — and it may or may not still make sense for somebody to do so, depending on what their state’s energy prices are looking like.”
Given that the House bill is expected to drive up electricity prices already being pushed higher by President Donald Trump’s tariff and energy policies, undermining the economics of rooftop solar “is a pretty direct attack by the House on energy prices in the wrong direction,” Costa said.
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