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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.
This story was originally published by Floodlight.
Republicans and Democrats alike are less likely to support renewable energy than they were five years ago, according to a survey released last week by the Pew Research Center.
The results mirror growing pockets of opposition to solar farms, reignited political support for coal plants, and moves by President Donald Trump and congressional Republicans to kill federally funded clean energy projects.
This shift in opinion dates back to when Democratic President Joe Biden took office, said Brian Kennedy, Pew senior researcher and one of the study’s authors. “This isn’t a new trend,” he said.
Still, Kenneth Gillingham, professor of environmental and energy economics at the Yale School of the Environment, was surprised.
“I see this shift … as a successful effort to link climate change and renewable energy to broader culture war issues,” Gillingham said. He added that in the past, “prominent” Republicans supported renewables and sought solutions to climate change, but those stances could now be seen as “disloyal” to Trump.
The survey of 5,085 U.S. adults taken April 28 to May 4 revealed that while 79% of Americans favored expanding wind and solar production in 2020, that number has dropped to 60%. And 39% of Americans today support expansion of oil, coal, and natural gas — almost double the 20% that supported it in 2020.
Combustion of fossil fuels — in transportation, energy generation, and industrial production — is the No. 1 cause of climate change.
Much of the change in opinion is driven by Republicans, whose support of oil and gas grew from 35% in 2020 to 67% today. But Democrats also indicated less support for renewable energy and more for fossil fuels than five years ago.
While many results reflect Trump’s policies opposing most renewables and boosting fossil fuels, Pew found a few notable exceptions: 69% of all respondents favor offshore wind — a technology Trump has specifically targeted.
Both Democrats and Republicans indicated stronger support for nuclear power, with Republicans’ favorable opinions increasing from 53% in 2020 to 69% in 2025. Democrats’ support rose from 37% to 52%. The Trump administration has signaled support for a nuclear renaissance, despite its high cost.
There were wide partisan splits on several topics. In March, the U.S. Environmental Protection Agency announced it would scale back environmental regulations. Pew asked whether it was possible to do that and still protect air and water quality: 77% of Republicans said yes, and 67% of Democrats said no.
Pew didn’t ask the respondents why their attitudes have shifted. But Kennedy said in Pew’s past surveys, Republicans have expressed concern about the economic impacts of climate change policies and transition from fossil fuels to renewable energy sources.
Mike Murphy, a Republican consultant and electric vehicle backer, said when the environmental benefits of clean technologies are touted, it polarizes Republicans. Instead, Murphy said messages should be about pocketbook issues — like lower fuel costs — and jobs.
“It’s hard for pro-climate people to understand,” said Murphy, who has advised dozens of state and national GOP campaigns, including John McCain’s 2008 presidential bid. “[They think] we just need to shout louder and hit people over the head about climate, climate, climate. The key is you want to talk about jobs and national security and other events that naturally resonate a lot more with right-of-center people.”
That’s what Murphy’s groups, the EV Politics Project and the American EV Jobs Alliance, are trying to do to depoliticize electric vehicles. “Whenever electric cars are seen through a climate lens,” Murphy said, “their appeal narrows.”
It’s a strategy also being used by the Electrification Coalition, a left-of-center pro-EV group. Ben Prochazka, the coalition’s executive director, echoed Murphy’s strategy, adding that EVs have “become overly politicized and caught in the culture wars, impacting markets and ultimately hurting our ability to realize their many benefits for all Americans.”
Prochazka noted that once introduced to EVs, consumers support them: “EV drivers love their vehicles, with more than eight out of 10 reporting that their next car will also be electric.”
Perhaps those practical messages are getting through. In the Pew survey, electric vehicles were the one item that saw an uptick in support — 4 percentage points in the past year.
But popular support might not be enough to stop Congress from killing a $7,500 electric vehicle credit, which Murphy said would be “policy disaster.”
Republicans, he said, are in a “real squeeze,” because “they don’t have enough money for the tax cuts the president has promised.”
Said Murphy: “It’s easier for Republicans to cut Biden electric cars … than it is for them to cut more Medicaid.”
Gillingham is still optimistic that solar, wind and other greenhouse gas-reducing technologies will move forward — because they are the cheapest.
“The continued decline in the price of renewable energy and battery technologies, as well as other new technologies, is a reason to continue to have hope that the worst impacts of climate change can be addressed,” he said.
Floodlight is a nonprofit newsroom that investigates the powerful interests stalling climate action.
Residential customers of Duke Energy in North Carolina could pay $87 million more per year for electricity under a proposal rocketing through the state legislature, a new study shows. The figure represents about a 4% jump in household bills.
The legislation, Senate Bill 266, would change how Duke distributes the cost of electricity it buys to supplement generation from its own power plants — significantly hiking the share paid by residential consumers and cutting the portion paid by industrial electricity users, like chemical manufacturers and textile mills.
The analysis shows the legislation is a better deal for industrial customers than the status quo, said Will Scott, Southeast climate and clean energy director for the Environmental Defense Fund. “They will pay less to use the same amount of energy, and residential ratepayers will pay more,” he said.
SB 266 is the latest version of a Senate-passed measure that would unravel the state’s climate targets. It was publicly unveiled moments before it was debated and approved by the House Energy and Public Utilities Committee last week, and received fulsome praise from Duke, industrial groups, and others in testimony.
On Tuesday, despite protests from clean energy advocates and some Democratic lawmakers, the bill easily cleared the Republican-controlled House and now returns to the Senate, also run by the GOP.
The study, conducted by independent analysis group EQ Research, has a narrow scope, homing in on the ramifications of just one section of the 30-page bill — the part that covers how purchased power is billed to customers.
“We were pretty laser-focused,” said Justin Barnes, president of EQ Research, “because that’s the analysis we could do with readily available information quickly.”
While Duke generates much of its own electricity from a fleet of fossil fuel and nuclear plants, it also contracts to buy some of its solar power from independent producers and purchases energy from other generators under certain conditions, such as when demand spikes.
Under current law, the entire cost of this purchased power is passed on to customers annually along with a charge for natural gas and other fuels. The utility divvies up the costs of this fuel “rider” between residential and industrial customer groups based partially on their peak electricity demand and partially on their overall energy use.
According to EQ’s analysis of Duke’s latest filings with regulators, the fuel rider totals about $2.75 billion for the company’s two North Carolina entities, Duke Energy Progress and Duke Energy Carolinas. The purchased power portion is around $1.1 billion.
Of the purchased power portion, residential customers currently pay about 41.2%, and use just over 40% of the energy.
SB 266 eliminates any weight given to overall energy use in allocating purchased power costs, according to EQ, shifting charges from large industrial users of electricity to residential consumers. The result is that households would pay just under 49% of those costs while using the same 40% of energy, the group’s study found.
“It is not going to be a savings for us ratepayers,” said Rep. Pricey Harrison, a Guilford County Democrat, speaking against SB 266 on the House floor. “It is going to be an increase.”
The EQ study does not incorporate the potential effects of other parts of the bill, including alleged savings from eliminating a 2030 deadline by which Duke must cut its carbon pollution, and the impact to customers of allowing the utility to recoup some costs for power plants not yet delivering electricity.
Rep. Dean Arp, the Union County Republican championing SB 266, said last week in committee that erasing the 2030 climate target would save all customers a total of $13 billion by 2050. He said allowing Duke to recover plant-construction financing costs early would net them another $1.4 billion. He echoed those claims Tuesday on the House floor, rounding up the total savings by over half a billion dollars.
“A vote against this legislation is a vote to make all ratepayers pay $15 billion more in electricity costs,” Arp said.
But opponents of the bill reject the allegation that striving for more wind and solar energy in the near term will contribute to rising rates, an assertion stemming from an elusive study from the state-sanctioned customer advocate, Public Staff, that hasn’t been provided widely to legislators or members of the public.
Clean energy advocates say the Public Staff analysis considers only the cost of building new power generation, not the rising price of fossil fuels. And they continue to question the wisdom of allowing Duke to charge consumers for costs related to nuclear and gas plants that may never come online.
Perhaps above all, EQ’s findings show why more time is needed to vet the bill with all interested parties, including clean energy and consumer advocates, not just Duke and large industrial customers, critics contend.
“When we rush processes like these and don’t include all the stakeholders, we can end up with results that unfairly burden North Carolina households,” said Scott with the Environmental Defense Fund. “I hope that we can slow down and make the adjustments we need so that this bill doesn’t cause unnecessary pollution or unnecessary costs.”
But the House’s public deliberation of the measure has been anything but slow. In less than a week, it cleared two committees and two required floor votes. It could appear on the desk of Gov. Josh Stein, a Democrat, as soon as this week.
“There are all kinds of reasons to vote no on this bill,” Harrison said to the full House on Tuesday, including its treatment of residential customers, its abdication of climate targets, and the process by which it was rushed through the chamber.
As the House prepared to vote around 7 p.m., she said, “It’s not clear why we’re doing this tonight.”
The Texas Legislature ended its biennial session without passing a slew of bills that could have killed the state’s booming solar and battery sector, and by extension, the ability to keep the Texas grid running amid extreme weather and surging demand for electricity.
It did pass a law that could strengthen the state’s electricity reliability by encouraging the construction of more microgrids — combinations of small-scale gas-fired power, solar, and batteries that can be built quickly. Last week, Texas lawmakers authorized a long-awaited $1.8 billion fund to support microgrid deployment at hospitals, nursing homes, water treatment plants, police and fire stations, and other critical facilities across the state.
The Texas Backup Power Package Program has awaited funding since 2023, when it was created as part of a broader legislative package. The goal is to help Texans protect themselves against extreme weather-driven grid emergencies like the disastrous blackouts during 2021’s Winter Storm Uri, or the widespread power outages after 2024’s Hurricane Beryl.
Lawmakers failed to authorize the $1.8 billion in microgrid funding in 2023, however. Instead, the state pushed ahead with $5 billion for the Texas Energy Fund, which offers low-interest loans to developers of large-scale gas-fired power plants. That program has struggled. One project that applied for funding was found to be fraudulent. Others were denied loans. And many more projects have dropped out of contention, as developers deal with the same gas turbine shortages and rising costs that are dogging gas build-outs across the country.
This year, lawmakers finally approved the microgrid funding, which is part of the remaining $5 billion in Texas Energy Fund spending officially authorized during the just-concluded session. That’s a big deal, said Doug Lewin, president of Texas-based energy consultancy Stoic Energy and author of The Texas Energy and Power Newsletter.
“Now those funds will presumably begin to flow — and I think that puts us in the upper echelon of states for microgrid policy,” he said.
Among the bills that failed this session in the face of opposition from environmental, business, and consumer groups were two — SB 388 and SB 715 — that would have forced new solar, wind, and battery projects to pay for a massive and equivalent amount of new capacity from fossil-gas power plants.
The problem with such policies is not just the fallacy that building more planet-warming gas power plants guarantees a more reliable grid, industry experts say. It’s also that companies simply can’t build gas power plants fast enough to meet booming energy needs, not just in Texas, but across the country. Because those bills would have required gas to be built alongside renewables — and because gas power plant construction is seriously constrained — the legislation would have amounted to a block on many gigawatts’ worth of new solar, wind, and battery developments in the state.
”I think one of the most important things that happened this session is this really broad-based business coalition communicating to anyone who would listen that these policies trying to restrict development of renewables aren’t helpful,” Lewin said.
Low-cost power from renewables and batteries “is a big deal to manufacturers, to industrial customers, and to the oil and gas industry that’s been working off diesel generators for decades and are now connecting to the grid,” he said.
For years now, Lewin has been calling on state leaders to focus on helping customers save energy and keep power flowing during hurricanes, heat waves, and winter storms. He thinks microgrids are a good way to do that.
When the broader grid is functioning well, facilities equipped with microgrids can use their solar, batteries, and generators to reduce their use of grid power. But when the grid goes down or experiences serious stress, those facilities can rely on those resources to continue running.
Microgrids could also help meet ballooning power demand from homes, businesses, factories, and especially data centers chasing the AI boom that make up a massive share of future load growth forecasts, he said. The Electric Reliability Council of Texas, the grid operator for most of the state, forecast in April that peak electricity demand could more than double in the next five years. The number of data centers that end up getting built in Texas will ultimately determine how much new power the state actually needs.
The microgrid program limits individual projects to no larger than 2.5 megawatts, Lewin said. That’s far smaller than the hundreds of megawatts of capacity that can come from a single gas-fired power plant. But what microgrid projects lack in size they make up for in speed of construction, and many smaller-scale backup power projects will do more to meet demand than big power plants that take five or more years to build, he said. That’s especially true if the microgrids are located at data centers themselves.
To be clear, data centers aren’t the target of the Texas Backup Power Package Program. Instead, the fund is set up to help sites that can’t otherwise afford on-site backup power, explained Joel Yu, senior vice president of policy and external affairs at Enchanted Rock. The Houston-based microgrid operator runs 500 megawatts’ worth of projects at grocery stores, truck stops, and other large power customers in Texas. Enchanted Rock has also deployed gas-fired generators at water utilities and irrigation districts, including Houston’s Northeast Water Purification Plant.
“The $1.8 billion is a huge amount of money, and more ambitious than programs we’ve seen in other jurisdictions,” Yu said. “But it’s very much in line with state policy to improve resilience at critical facilities since Winter Storm Uri,” which knocked out power to more than 4.5 million people for up to a week in February 2021, leading to the deaths of an estimated 200 people and more than $100 billion in property damages.
Enchanted Rock’s existing customers tend to be larger entities that can secure financing and clearly quantify the financial value of backup power generation, Yu said. The $1.8 billion microgrid program “unlocks opportunities for customers who aren’t as sophisticated, and don’t have the wherewithal to pay that extra cost,” he said.
Assisted living facilities are particularly good candidates for state-funded microgrids, given how deadly power outages can be to older adults or medically compromised people. Alexa Schoeman, deputy of the state’s long-term care ombudsman’s office, told the Public Utility Commission of Texas in a March statement that the more than 80,000 residents of assisted living facilities in the state are at risk from extended power outages, and that “operators have cited cost as the reason they are not able to install life-saving backup power at their locations.”
Yu declined to name any customers that Enchanted Rock is working with to take advantage of the fund. “But there’s been a lot of interest from critical facilities that might want to make use of this. We’ve talked to folks in nursing homes, assisted living industries, and low-income housing, and other critical infrastructure, trying to get into the program.”
Enchanted Rock has joined other backup generation providers including Bloom Energy, Base Power, Cummins, Generac, Mainspring Energy, and Power Secure in what Yu called an “informal group of like-minded companies.” Dubbed Grid Resilience in Texas, or GRIT for short, the coalition is working with the Electric Reliability Council of Texas and the Public Utility Commission on the $1.8 billion microgrid program, he said.
Most of these companies focus on gas-fueled power generation systems, whether those are reciprocating engines like those Enchanted Rock uses, linear generators from Mainspring, or fuel cells from Bloom Energy. Others specialize in battery backup systems, as with startup Base Power, or combine solar, batteries, and energy control systems with generators, as with Generac.
The legislation creating the Texas Backup Power Package Program allows projects to tap up to $500 of state funding per kilowatt of generation capacity installed, and requires solar, batteries, and either fossil gas or propane-fueled generation, Yu said. But it “isn’t prescriptive about what proportions are in the mix,” he added.
Different combinations could offer more favorable economics for different types of customers. Some may find that lots of solar panels are useful for lowering day-to-day utility bills, while others may want to maximize gas-fueled generation to cover multiday winter outages, when solar-charged batteries are less useful.
The legislation creating the program does limit projects from actively playing in the grid operator’s market programs, Yu added, meaning microgrid owners will face restrictions on selling the power they generate or the grid-balancing services they can provide to the market.
Still, that “does leave some room for customers to leverage the assets for behind-the-meter value,” such as using solar to offset utility power purchases, Yu said. “That’s going to be very important to making the economics work.”
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