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The Trump administration just dealt a blow to the biggest transmission line project currently underway in the United States.
The U.S. Department of Energy has canceled a $4.9 billion federal loan guarantee for the Grain Belt Express, a massive transmission line project seeking to carry wind and solar energy from the Great Plains to states farther east. It’s the latest in a series of Trump administration actions aimed at undermining the U.S. clean energy sector in the name of protecting taxpayer dollars.
In its Wednesday cancellation announcement, the DOE claimed that “the conditions necessary to issue the guarantee are unlikely to be met and it is not critical for the federal government to have a role in supporting this project.”
Energy Secretary Chris Wright is also scrutinizing several other loans made under the Biden administration by the DOE’s Loan Programs Office, which issued its conditional guarantee to the Grain Belt Express in November. He has pledged to closely review and potentially cancel tens of billions of dollars more in financing from the office, citing a need to more responsibly steward federal dollars. However, in its 20-year history, the office has turned a profit for taxpayers by collecting interest and principal payments from the companies that receive loans.
The Grain Belt Express has been in the works for more than a decade. It’s one of only a handful of major transmission projects underway in the U.S., and once built it will be able to support the development of gigawatts of new wind and solar projects and deliver $52 billion in energy cost savings over 15 years, according to Invenergy, the Chicago-based developer that’s building it. Around the country, more projects like the Grain Belt Express are needed to expand the grid fast enough to meet surging demand and to bolster electricity reliability.
The cancellation comes a week after Sen. Josh Hawley, a Missouri Republican, told The New York Times that he had made a personal appeal to President Donald Trump to take action to halt the project, and that Trump had promised to instruct the DOE to do so.
“He said, ‘Well, let’s just resolve this now,’” Hawley told The New York Times. “So he got Chris Wright on the line right there.”
Invenergy did not immediately respond to requests for comment Wednesday morning. The developer had sought the loan guarantee to reduce the expense of borrowing for the project, which will cost $11 billion in total and has already secured agreements with utilities in Missouri as part of its efforts to find buyers for the power it will make available across the regions it will connect.
It’s unclear to what extent the loss of federal loan guarantees will derail or slow down the project’s timeline. In May, Invenergy signed a nearly $1.7 billion contract with contractors Kiewit Energy Group and Quanta Services, and construction is slated to begin next year.
In a statement earlier this month responding to a social media post from Hawley criticizing the project, Invenergy accused the senator of “trying to deprive Americans billions of dollars in energy cost savings, thousands of jobs, grid reliability and national security, all in an era of exponentially growing demand.”
The U.S. faces a looming crisis as new data centers, factories, and broader economic growth cause electricity demand to rise faster than supply is forecast to grow.
Solar, wind, and batteries have made up more than 90% of new energy built in recent years, and are the only resources that can be constructed rapidly enough to meet surging demand in the near term. Other energy resources have far slower development times, including fossil-gas power plants, which currently face manufacturing bottlenecks that will take years to resolve.
In addition to headwinds from Trump and the GOP-led Congress, which just eliminated federal tax credits for solar and wind, the main factor that threatens to hold back clean-energy development is a lack of space on the grid.
The U.S. lags in building the new high-voltage transmission lines that grid experts say are necessary to bring even more new solar, wind, and batteries online. These lines carry clean power from where it’s cheap to produce to where the most energy is consumed, like cities, and building more of them can reduce grid congestion, improve power system reliability, and lower electricity rates.
The Grain Belt Express has won approval from utility regulators in Kansas, Missouri, Illinois, and Indiana, and has received support from lawmakers and organizations representing farmers and large electricity consumers. But the project has also faced multiple challenges from landowners and farmers. Invenergy is currently contesting an Illinois court’s 2024 decision to overturn state regulatory approval for the project, made in response to a challenge from the Illinois Farm Bureau and landowner groups.
Missouri’s attorney general, a Republican, launched an investigation into the project earlier this month, accusing Invenergy of inflating economic benefits and overstating cost savings it would deliver. Invenergy contested the validity of that challenge in a letter to Energy Secretary Wright, saying that all relevant issues have already been decided by state courts and regulators.
It’s common for large-scale transmission projects, which traverse hundreds of miles across many different municipalities, counties, and states, to get bogged down in court battles. It’s a big reason why it takes so long to build new power lines in the U.S. But the Trump administration’s decision to cancel financing for the project is uncharted territory, and the impact is still unclear.
Should the project be delayed, it’d be a major setback for the U.S.’s already-sluggish transmission buildout.
The U.S. needs far more transmission to be built to lower energy costs and reduce the increasing threat of blackouts caused by extreme weather, according to reports from groups ranging from the Department of Energy and the North American Electric Reliability Corp. to the Massachusetts Institute of Technology and Princeton University.
Over the past decade, the number of miles of long-range, high-voltage transmission built across the country has fallen, even as utility transmission spending has risen. A report released this week by advocacy group Americans for a Clean Energy Grid and consultancy Grid Strategies found that only 322 miles of high-voltage transmission lines were completed last year, the third-lowest buildout of the past 15 years, and well below the nearly 4,000 miles built in 2013.
“The Grain Belt Express represents a critical opportunity to modernize the grid, lower electricity costs, and deliver reliable energy across multiple states,” Christina Hayes, executive director of Americans for a Clean Energy Grid, told Canary Media in a Wednesday email. “We encourage the administration to take a fresh look at the value this project brings to achieving its own goals for economic growth and energy dominance.”
Southern California’s grid needed help in the fall of 2016. The region was still reeling from the calamitous Aliso Canyon gas leak, and its power plants faced a potential shortfall of that fuel to meet air-conditioning demand when the next summer rolled around. The state took a chance on a new grid technology, lithium-ion batteries, to fill in the gaps.
Big names like Tesla and AES stepped in to help, installing storage at record speed, but so did a little-known firm called Powin. Joseph Lu had founded the Oregon-based company years earlier to import consumer products from China and Taiwan. Sensing a new business opportunity, Powin won a bid and installed 2 megawatts of batteries in a warehouse it owned in Orange County.
This proved to be a launchpad for the firm, which rose to the upper echelons of the booming U.S. battery industry before crashing down to earth last month.
After that Orange County installation, Powin refocused on importing battery cells from China and integrating them into grid storage systems, fully packaged with inverters, controls, and safety systems. Powin went on to deliver battery enclosures for many pathbreaking projects: It supplied the first utility-scale battery in Mexico, a landmark utility-endorsed battery fleet in Arizona, and a truly mammoth system in Australia, to name just a few of Powin’s self-reported 11.3 gigawatt-hours of installed systems. It raised some major outside equity rounds to keep growing and last fall obtained a $200 million debt facility from investment giant KKR.
And then in June, Powin filed for bankruptcy, alerting the state of Oregon of mass layoffs at its Tualatin campus, outside Portland. The news jolted the storage industry, since so many major grid storage plants run on Powin’s hardware and software. The bankruptcy proceedings are ongoing, but storage software specialist FlexGen has placed a bid to buy Powin’s assets at auction in early August, offering Powin customers a way to keep their batteries running.
Cleantech bankruptcies have flourished under the second Trump presidency, and the storage sector is uniquely exposed. The industry runs almost entirely on imported battery cells from China, making it vulnerable to rapidly shifting trade policies. The Biden administration raised tariffs on Chinese batteries, and President Donald Trump cranked the overall rate on Chinese imports as high as 145% in April, though he has altered the rate repeatedly in the opening months of his presidency. Trump’s budget law preserved tax credits for installing grid batteries but added a new bureaucratic regime to regulate the amount of China-derived equipment in those storage plants.
“The business model of integrating batteries into a full storage system is one of these classic high-volume, low-margin businesses,” said Pavel Molchanov, a Raymond James analyst covering cleantech companies. “Margins were low even before Trump and these new tariffs on China, and now it’s a safe bet that their margins have been squeezed even further.”
Nonetheless, Powin’s collapse stands out for the scale of the company’s reach — and raises serious questions. Is Trumpian chaos enough to unseat a leading battery supplier, even as the market for grid batteries continues to surge? Or did Powin’s leadership make choices that ultimately led to its early demise? And perhaps more important, what’s going to happen to those 11.3 gigawatt-hours Powin installed before it went bankrupt?
Powin got to the big leagues by spotting technological trends before they hit the energy-storage mainstream.
That started with the rapid-fire California installations in 2016, when hardly anyone was building large-scale storage. At the time, American developers looked to a handful of Tier 1 battery suppliers, like LG, Samsung, and Panasonic. Powin instead scoured China for manufacturers that American buyers hadn’t discovered yet but that could match key quality metrics. Powin signed an early supply deal with a firm called Contemporary Amperex Technology Co., or CATL, which has since become far better known in the West as the world’s largest battery maker.
Powin also focused on the then-lesser-known lithium ferrous phosphate (LFP) chemistry, which executives hailed as safer and longer-lasting than the mainstream nickel-based chemistries handed down from the electric vehicle supply chain. Powin imported these LFP cells from trusted vendors in China, installed them in engineered metal cabinets in Tualatin, then delivered them to project sites across the U.S. and, later, the world.
By the 2020s, U.S. storage installations were growing at a shocking rate. To keep pace with soaring demand, Powin raised $100 million in February 2021 from investors Trilantic Capital Partners and Energy Impact Partners, followed by $135 million in 2022, led by Singapore’s sovereign wealth fund GIC.
The firm’s first major public setback came when a Powin-supplied battery system in Warwick, New York, burst into flames after a summer storm in 2023. Days later, authorities responded to fumes emerging from another Powin-supplied system in that town.
Developer Convergent Energy and Power owned both systems, and its investigation concluded that a manufacturing flaw in that generation of Powin’s Centipede battery container let water leak in and start electrical fires. Those incidents prompted the Warwick Village Board to freeze local battery development, and they undercut Powin’s reputation for safety, which the company previously had promoted after other companies’ battery fires elsewhere in the country. A spokesperson for Convergent did not respond to requests for comment.
It’s unclear what kind of financial impact the fallout from those fires had on Powin, but the firm subsequently found itself locked in a legal dispute with none other than its longtime supplier, CATL. That company sued Powin in Oregon Circuit Court in December 2024 for $44 million in allegedly unpaid bills, following an earlier arbitration on the matter in Hong Kong.
The circuit court noted in February that Powin “does not deny that they owe money to CATL” and that “it is apparent to the court that the amount of money Powin owes to CATL exceeds the value of the assets Powin holds in Oregon.” That’s not a great sign for a company’s metabolism.
In a subsequent filing, Powin’s lawyers asserted that, actually, CATL was refusing to honor the contracts and instead tried to spring non-contracted price hikes at the last minute: “CATL effectively held Powin hostage to choosing between negotiating a solution with CATL or breaching contracts with its customers.”
In the same suit, the Powin lawyers proposed a nefarious explanation for the souring relationship with CATL, one that sheds light on a broader challenge Powin faced in the maturing storage market.
“Powin finds it highly suspect that the timing of this filing for pre-judgment remedies comes as CATL is aiming to compete directly with Powin to supply complete energy storage systems, moving beyond its historical business model of supplying subcomponents to Powin and others like Powin.”
Powin championed CATL’s battery cells to the U.S. market when buyers still had hang-ups about sourcing high-quality batteries from China. But CATL, recently valued at more than $180 billion, did indeed move beyond simply shipping cells and began competing directly with Powin. CATL launched a containerized storage product in 2023, and in May it rolled out a new 9-megawatt-hour, double-decker grid battery enclosure called TENER Stack.
“The past few months have presented considerable headwinds for system integrators, even without considering company-specific challenges,” said Ravi Manghani, senior director of strategic sourcing at data firm Anza Renewables. “The increasing number of battery [original equipment manufacturers] entering the U.S. market with attractively priced DC blocks and AC solutions has put pressure on the traditional value proposition of system integrators.”
Other sources in the grid storage industry noted that Powin’s quality had suffered in the scale-up, lowering customer interest in its products. The company had always had a smaller balance sheet than competitors like Tesla, Fluence, and Wärtsilä, all of which are publicly traded and worth billions.
Longtime Powin CEO Geoff Brown, who led the company from 2016 through its dynamic growth phase, departed in 2023. He was replaced by Jeff Waters, who touted his leadership at solar panel manufacturer Maxeon during its spin-off from SunPower. Those accolades look less auspicious from today’s standpoint: SunPower went bankrupt last year, and Maxeon’s valuation has tumbled precipitously from its 2023 levels.
Last fall, Powin turned to the credit business at KKR, a private-equity trailblazer famous for record-busting leveraged buyouts like RJR Nabisco in the 1980s and utility TXU in the 2000s.
“The facility will be instrumental in supporting Powin’s working capital needs, driving continued innovation, and further enhancing the company’s financial flexibility as it expands its leadership position in the storage industry,” KKR said in a press release from October announcing the $200 million facility.
It’s a strange thing when a company that just secured ample working capital then runs out of working capital just a few months later. Sources familiar with Powin’s business said the debt package, paradoxically, hastened the company’s demise.
Powin drew on only about $25 million of the available debt, but the deal company leadership accepted was “very ugly” and “poorly structured” for Powin’s purposes, said one former Powin customer granted anonymity to speak on sensitive business matters. Another grid storage veteran, who also spoke on condition of anonymity, likened the situation to a payday loan: “They got upside down, and KKR called it in.”
KKR declined to comment on the specifics of Powin’s debt facility.
Powin wouldn’t be the first cleantech company that failed after getting behind on its debt payments. Major rooftop solar provider Sunnova increasingly turned to corporate debt to raise cash as the market soured, then struggled to find cash for debt payments and fell into bankruptcy in June. Electric bus maker Proterra piled up corporate debt before its bankruptcy filing in 2023. When it’s time to pay the tab, even a promising customer pipeline is no legal tender.
Powin’s financial collapse triggered an existential question for all the storage plants out there running on its hardware and software.
“Everyone’s trying to figure out how to maintain their products and solutions and not have bricked systems,” the former customer said.
Software needs updates, as anyone with an iPhone is repeatedly reminded, and the same goes for the systems that tell huge banks of batteries when to charge and discharge. Energy market rules change; hardware trips up. If Powin simply ceased to exist, it would jeopardize the reliability of all the critical power plants running on its control systems.
But those anxious battery owners may soon get some relief now that software startup FlexGen became a stalking horse bidder in June, proposing to buy “substantially all” of Powin’s assets for $36 million. It’s also lending money to keep Powin operating in the meantime. There will still be an auction, and other firms could bid more. But if all goes according to plan, this process will conclude by early August.
FlexGen CEO Kelcy Pegler said he had great respect for Powin, and “gratitude for them being an early mover” in the grid storage industry.
“Powin was such a substantial part of the market,” Pegler told Canary Media. “FlexGen’s interest is in making sure the customers have a successful path to continuous operations.”
FlexGen, based in Durham, North Carolina, employs some 120 software engineers to constantly maintain and improve its storage management software, Hybrid OS, Pegler noted; that product works on whatever storage hardware the customer wants to operate. If the bid goes through, FlexGen will first provide Powin customers with a “continuity plan” that keeps systems running as they are, and customers will have the option to sign new long-term service agreements with FlexGen.
Customers will have good reason to switch over to FlexGen’s flagship product, Pegler added: An independent market study by cleantech data firm Orennia found that batteries running on FlexGen software performed better than those running on that of Powin (and other competitors) in the wholesale markets of Texas and California in 2023.
As for the business of buying battery cells and turning them into storage plants, Pegler is happy to leave that to the existing field of storage manufacturers. He plans to stick to software and services.
Powin has let go of much of its staff. The founders will lose their stakes, and the venture capitalists and private-equity investors won’t rake in a multiple on their few hundred million dollars invested. But a sale to FlexGen would protect Powin’s physical legacy: The gigawatt-hours of batteries installed across the world could keep on humming, as the energy storage market careens ever onward.
As temperatures across New England soared above 100 degrees Fahrenheit in recent weeks, solar panels and batteries helped keep air conditioners running while reducing fossil-fuel generation and likely saving consumers more than $20 million.
“Local solar, energy efficiency, and other clean energy resources helped make the power grid more reliable and more affordable for consumers,” said Jamie Dickerson, senior director of clean energy and climate programs at the Acadia Center, a regional nonprofit that analyzed clean energy’s financial benefits during the recent heat wave.
On June 24, as temperatures in the Northeast hit their highest levels so far this year, demand on the New England grid approached maximum capacity, climbing even higher than forecast. Then, unexpected outages at power plants reduced available generation by more than 1 gigawatt. As pressure increased, grid operator ISO New England made sure the power kept flowing by reducing exports to other regions, arranging for imports from neighboring areas, and tapping into reserve resources.
At the same time, rooftop and other “behind-the-meter” solar panels throughout the region, plus Vermont’s network of thousands of batteries, supplied several gigawatts of needed power, reducing demand on an already-strained system and saving customers millions of dollars. It was a demonstration, supporters say, of the way clean energy and battery storage can make the grid less carbon-intensive and more resilient, adaptable, and affordable as climate change drives increased extreme weather events.
“As we see more extremes, the region still will need to pursue an even more robust and diverse fleet of clean energy resources,” Dickerson said. “The power grid was not built for climate change.”
On June 24, behind-the-meter solar made up as much as 22% of the power being used in New England at any given time, according to the Acadia Center. At 3:40 p.m., total demand peaked at 28.5 GW, of which 4.4 GW was met by solar installed by homeowners, businesses, and other institutions.
As wholesale power prices surpassed $1,000 per megawatt-hour, this avoided consumption from the grid saved consumers at least $8.2 million, according to the Acadia Center.
This estimate, however, is conservative, Dickerson said. He and his colleagues also did a more rigorous analysis accounting for the fact that solar suppresses wholesale energy prices by reducing overall demand on the system. By these calculations, the true savings for consumers actually topped $19 million, and even that seems low, Dickerson said.
In Vermont, the state’s largest utility also relieved some of the pressure on the grid by deploying its widespread network of residential and EV batteries. That could save its customers some $3 million by eliminating the utility’s need to buy expensive power from the grid and reducing fees tied to peak demand.
“Green Mountain Power has proven that by making these upfront investments in batteries, you can save ratepayers money,” said Peter Sterling, executive director of trade association Renewable Energy Vermont. “It’s something I think is replicable by other utilities in the country.”
Green Mountain Power’s system of thousands of batteries is what is often called a “virtual power plant” — a collection of geographically distributed resources like residential batteries, electric vehicles, solar panels, and wind turbines that can work together to supply power to the grid and or reduce demand. In Vermont, Green Mountain Power’s virtual power plant is its largest dispatchable resource, spokesperson Kristin Carlson said. The 72-MW system includes batteries from 5,000 customers, electric school bus batteries, and a mobile, utility-scale battery on wheels.
The network began in 2015 with the construction of a 3.4-megawatt-hour storage facility at a solar field in Rutland, Vermont. Two years later, the utility launched a modest pilot program offering Tesla’s Powerwall batteries to 20 customers, followed in 2018 by a pilot that paid customers to share their battery capacity during high-demand times. In 2022, a partnership with South Burlington’s school district linked electric school buses to the system, and in 2023, state regulators lifted an annual cap on new enrollments it had imposed on a Green Mountain Power program that leases batteries to households. The number of customers with home batteries has since grown by 72%.
“We’ve had a really dramatic expansion,” Carlson said. “It is growing by leaps and bounds.”
The network saved consumers money during the heat wave by avoiding the need to buy power at the high prices the market reached that day, but also by helping to lower the “capacity fees” charged by ISO New England. These charges are determined by the one hour of highest demand on the grid all year, and then allocated to each utility based on their contributions to that peak. By pulling power from batteries rather than just the grid, Green Mountain Power lowered its part of the peak.
If the afternoon of June 24 remains the time of peak demand for 2025, Green Mountain Power’s 275,000 customers will save about $3 million in total and avoided power purchases, the utility calculated. Looking ahead, more hot weather and further expansion of the utility’s virtual power plant will likely continue to put money back in customers’ pockets, Sterling said: “When you play that out over many years, that’s real savings to ratepayers.”
In late spring, the Department of Energy ordered two aging and costly fossil-fueled power plants that were on the verge of shutting down to stay open. The agency claimed that the moves were necessary to prevent the power grid from collapsing — and that it has the power to force the plants to stay open even if the utilities, state regulators, and grid operators managing them say that no such emergency exists.
More of these orders could be on the way. The DOE published a report this week, in response to one of the “Beautiful Clean Coal” executive orders issued by President Donald Trump in April, that lays out the case for Energy Secretary Chris Wright, a former gas industry executive who has denied there is a climate change crisis, to demand that more fossil-fueled plants remain open past their scheduled closures.
But state regulators, regional grid operators, environmental groups, and consumer groups are pushing back on the notion that the grids in question even need these interventions — and are challenging the legality of the DOE’s stay-open orders.
Last month, state utility regulators and environmental groups filed rehearing requests with the DOE, demanding that it reconsider emergency orders to force the J.H. Campbell coal plant in Michigan and the Eddystone oil and gas-burning plant in Pennsylvania to stay open through the summer.
The DOE claimed that the threat of large-scale grid blackouts forced its hand. But state utility regulators, environmental groups, consumer advocates, and energy experts say that careful analysis from the plant’s owners, state regulators, regional grid operators, and grid reliability experts had determined both plants could be safely closed.
These groups argue that clean energy, not fossil fuels, are the true solution to the country’s grid challenges — even if the “big, beautiful” bill signed by Trump last week will make those resources more expensive to build. Some of the environmental organizations challenging DOE’s orders have pledged to take their case to federal court if necessary.
“We need to get more electrons on the grid. We need those to be clean, reliable, and affordable,” said Robert Routh, Pennsylvania climate and energy policy director for the Natural Resources Defense Council, one of the groups demanding that DOE reconsider its orders. Keeping J.H. Campbell and Eddystone open “results in the exact opposite. It’s costly, harmful, unnecessary, and unlawful.”
The groups challenging the DOE’s J.H. Campbell and Eddystone stay-open orders point out that the agency is using a power originally designed to protect the grid against unanticipated emergencies, including during wartime, but without proving that such an emergency is underway.
“This authority that the Department of Energy is acting under — Section 202(c) of the Federal Power Act — is a very tailored emergency authority,” said Caroline Reiser, NRDC senior attorney for climate and energy. “Congress intentionally wrote it only to be usable in specific, narrow, short-term emergencies. This is not that.”
For decades, the DOE has used its Section 202(c) power sparingly, and only in response to requests from utilities or grid operators to waive federal air pollution regulations or other requirements in moments when the grid faces imminent threats like widespread power outages, Reiser said.
But the DOE’s orders for Eddystone and J.H. Campbell were not spurred by requests from state regulators or regional grid operators. In fact, the orders caught those parties by surprise.
They also came mere days before the plants were set to close down and after years of effort to ensure their closure wouldn’t threaten grid reliability. J.H. Campbell was scheduled to close in May under a plan that has been in the works since 2021 as part of a broader agreement between utility Consumers Energy and state regulators, and which was approved by the Midcontinent Independent System Operator (MISO), the entity that manages grid reliability across Michigan and 14 other states.
“The plant is really old, unreliable, extremely polluting, and extremely expensive,” Reiser said. “Nobody is saying that this plant is needed or is going to be beneficial for any reliability purposes.”
To justify its stay-open order, the DOE cited reports from the North American Electric Reliability Corp. (NERC), a nonprofit regulatory authority that includes utilities and grid operators in the U.S. and Canada. NERC found MISO is at higher risk of summertime reliability problems than other U.S. grid regions, but environmental groups argue in their rehearing request that the DOE has “misrepresented the reports on which it relies,” and that Consumers Energy, Michigan regulators, and MISO have collectively shown closing the plant won’t endanger grid reliability.
Eddystone, which had operated only infrequently over the past few years, also went through a rigorous process with mid-Atlantic grid operator PJM Interconnection to ensure its closure wouldn’t harm grid reliability. The DOE’s reason for keeping that plant open is based on a report from PJM that states the grid operator might need to ask utility customers to use less power if it faces extreme conditions this summer — an even scantier justification than what the agency cited in its J.H. Campbell order, Reiser said.
As long as the DOE continues to take the position that it can issue emergency stay-open orders to any power plant it decides to, these established methods for managing plant closures and fairly allocating costs will be thrown into disarray, she said.
“We have a system of competitive energy markets in the United States that is successful in keeping the lights on and maintaining reliability the vast, vast majority of the time,” Reiser said. “The Department of Energy stepping in and using a command-and-control system interferes with those markets.”
Utility regulators from MISO states including Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, and Wisconsin made a similar argument in their rehearing request to the DOE. “This expansive use of emergency powers sets a troubling precedent, enabling intervention in routine, state-approved planning decisions without an actual crisis,” they wrote. “Such preemptive action risks undermining the credibility of future emergency orders, distorting market signals, and eroding the statutory balance between federal and state authority.”
Dan Scripps, chair of the Michigan Public Service Commission, highlighted the years of work that went into enabling the J.H. Campbell plant to safely close, and the hundreds of millions of dollars that replacing it with fossil gas, solar, and battery resources would save.
“For DOE to substitute its judgment of what’s necessary for the work that’s done by the states and the regional grid operators is something that a large number of states of different political makeups find most troubling,” he said.
Forcing aging and expensive power plants to stay open past their long-planned retirement dates also threatens to drive up costs for utility customers at a time when energy prices are already set to rise due to GOP policies. Think tank Energy Innovation forecasts the megabill passed by congressional Republicans last week will lead to a 25% increase in wholesale electricity prices by 2030, as cuts to tax credits stifle investment in solar, wind, and battery projects and force power grids to rely on older, costlier resources.
This week’s DOE report “is another attempt to push the false narrative that our country’s energy future depends upon decades-old coal- and gas-plants, rather than clean renewables,” Greg Wannier, senior attorney at the Sierra Club, said in a statement. “The only energy crisis faced by the American public is the catastrophic increase in costs that the Trump Administration is forcing on the country’s ratepayers.”
Coal has fallen from nearly half U.S. generation capacity in 2011 to just 15% last year, and more than 120 U.S. coal plants are expected to close over the next five years. Coal industry groups and many Republicans blame state climate regulations for that trend. But energy experts agree that the primary driver is that coal plants are unable to provide power at prices that can compete with fossil gas or renewables.
Aging power plants like J.H. Campbell and Eddystone, which were built roughly 60 years ago, are among the most expensive to run — one of the main reasons why those two were both slated for retirement. Forcing them to restart and stay open for three months on the eve of their planned closures involves additional costs to secure new fuel contracts, undertake deferred maintenance, and rehire workers.
Utility customers in the Midwest and mid-Atlantic grid regions those plants are connected to will now bear all of those costs. While the total dollar amount has yet to be calculated, it could run into the tens of millions for each plant, or as much as $100 million for J.H. Campbell, Scripps told reporters in June.
Under its Section 202(c) authority, the DOE doesn’t have to deal with the costs its emergency orders incur, said Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based utility customer watchdog group. Instead, it gets to delegate the method of recovering those expenses to grid operators and regulators.
But the DOE has failed to show that keeping those plants open will benefit customers, which puts those entities in a bind.
“There is a standard in ratemaking that costs should be prudently incurred,” Summers said. “Since these costs are manufactured emergencies and are not prudently incurred, they are not just and reasonable.”
That’s the argument that environmental and consumer watchdog groups have made in filings with the Federal Energy Regulatory Commission, the agency tasked with overseeing the U.S. power grid. The groups have asked FERC to reject plans to recover costs from DOE’s J.H. Campbell and Eddystone orders on the grounds that the DOE has failed to show how keeping the plants open will benefit consumers.
“What’s especially frustrating about that is that we already have capacity markets that are there to make sure that we have enough electricity, and consumers already pay for that,” Summers said. Those costs to utility customers are rising dramatically in PJM, where years of backlogged interconnection processes have prevented new solar, wind, and battery projects from coming online to help replace power plants being closed. MISO also saw prices spike in its most recent capacity auction.
“The whole function of those markets is to ensure we have enough electricity — and those markets procure enough electricity,” Summers said. “This is something PJM agrees with, that MISO agrees with, that NERC agrees with.”
The DOE has 30 days from when the rehearing requests were filed to open a review of its stay-open orders, Reiser said. If the DOE doesn’t issue an order within that time, “it basically opens up the option for us to go to court.”
The DOE has never used its Section 202(c) authority in this way before, which means it has never been challenged in court on the issues at hand, Reiser said.
But “the fact that there are related executive orders kind of directing the Department of Energy to do these things doesn’t change the basic standards of how our legal system works and how courts interpret statutes,” she added. “No matter the reasoning, they still have to comply with the law.”
RENO, Nev. — I was supposed to be looking at the largest energy-storage installation ever assembled from used electric-vehicle batteries, the tantalizing new side project of former Tesla Chief Technology Officer JB Straubel’s recycling juggernaut, Redwood Materials. Instead, all I saw was a dusty field strewn with oddly shaped boxes wrapped in some kind of plastic sheeting. The boxes were propped up on cinder blocks, in the manner of rusted cars in a forgotten yard. It looked a bit like a garbage dump.
My Redwood tour guide assured me, however, that we were in the right place. Underneath those white shrouds were 792 individual EV battery packs, wired up in long rows and spread across two acres on the firm’s campus outside Reno, Nevada. The plastic wrapping was meant to protect them from the dust. Nearby was a field of solar panels laid flat on the ground, making it hard to gauge just how far back they went. These panels convert sunlight to electricity and store it in the array of old car batteries, to power a miniature data center that a startup named Crusoe built in the same field as the batteries. Any surplus power flows to Redwood’s own facilities surrounding the installation.
Redwood hailed the installation as a breakthrough in the sleepy field of second-life batteries, which has been around for a while but failed to move beyond initial proofs of concept to repeated, large-scale deployments. The firm has indeed broken a record for that stunted sector, certainly in the U.S. and likely the world, delivering 63 megawatt-hours of second-life grid storage in its own backyard. That’s a very deep reservoir of storage for the diminutive onsite data center, which has just 1 megawatt of computing load. The goal is to guarantee 24/7 clean power even with days of inclement weather.
Given the initial success, Straubel sees the energy storage business as a key growth area for Redwood, which was founded in 2017 to recycle battery materials into the domestic supply chain.
“This is, in a way, a first of its kind, and to be able to have a profitable project as a first one is pretty cool,” Straubel said prior to a sunset celebration of the project, held on the desert outcropping above it. “You will absolutely see much larger deployments of this in well under a year, and we are actively engineering and working on those projects today.”
Assuming the concept scales up further, it could be a game changer for data centers that prize speedy new energy construction. But it could further reshape the clean energy transition. Dozens of startups have toiled for years to invent new batteries for long-duration storage. Redwood has already beaten them to a large-scale deployment, without inventing anything new and risky — all it took was some clever reimagining of what others viewed as waste.
Using old EV batteries to store energy for the grid makes intuitive sense. Diminished battery capacity is a bigger deal for a vehicle than it is for grid storage; stationary stuff doesn’t need to work as hard as EV batteries, and it can take up a lot more space. A battery with just 80% of its original capacity left may get plucked from a vehicle, but it can still function fine for storing solar power. In theory, these secondhand batteries should be cheaper than new ones, reducing the cost of much-needed grid storage to accompany the rise of renewables.
Yet few second-life grid storage installations exist.
Most of the people who have actually installed second-life batteries have approached it as a small-scale research project, typically grant-funded. A scrappy company called B2U Storage Solutions broke that mold in 2020, when it built an array of old packs to deliver solar power into California’s energy markets in the most lucrative evening hours. I verified that with my own eyes in 2021, since it went far beyond the sector’s accomplishments at the time. B2U has since expanded the capacity to 28 megawatt-hours, but I haven’t seen a repeat project at that scale yet (though the company did build a 12-MWh project elsewhere in California).
Another startup called Element Energy obtained a bounty of lightly used packs, quite possibly through their investor LG, which endured a billion-dollar recall for units it supplied to General Motors a few years back. Element installed a couple dozen containers in West Texas last year, filled with 53 megawatt-hours of second-life storage. Next, it plans to build a factory to mass-produce enclosures for second-life installations.
Now, Redwood has entered the scene with its sprawling Nevada installation.
All of these developers have had to grapple with the same initial challenges. They need to get their hands on old EV packs and then sort out the ones that aren’t going to catch fire. Then they have to figure out how to safely control a patchwork fleet of batteries cobbled together from several manufacturers.
Redwood immediately stands out for its ability to handily source old packs. The company is, officially, a battery recycler, and it says it receives more old batteries than any of its U.S. competitors. All week long, trucks drop off pallets of everything from toothbrush batteries to electric-truck packs, which workers sort and stash in a 32-acre open-air depot. (Redwood says the safety benefits of super-dry air outweigh any risks associated with the bludgeoning Nevada sunshine.)
“If you ever used a lithium-ion battery, it’s probably going to end up coming through here in one way, shape, or form,” Straubel said. EV packs have been shooting up as a portion of total intake, from less than 1 gigawatt-hour per year in 2023 to more than 5 now, he added.
“That’s really one of the keys, is having the scale and having the access to the partnerships and the ability to move and transact and just physically harness that much material,” Straubel said.
Another differentiator might as well be called moxie. Founder Straubel sets the tone as a clean-energy nerd who just likes to give things a shot. He tried second-life microgrids at home before making it a focus for the workplace. His engineers hacked together a universal controller box that connects to each type of EV pack and operates it according to its unique needs. When the time came to test the concept, Straubel oversaw construction of the biggest second-life storage project in the world, all in five months from clearing ground to completion. No grant applications required.
Lastly, the Redwood approach bucks conventional opinion in ways that save time and money.
The storage industry, as a rule, puts its batteries in big metal boxes. Redwood engineers saw that as unnecessary, given how painstakingly ruggedized the packs had to be for vehicular use. No big boxes means no pouring concrete pads. The approach saves on labor, time, and materials.
“There’s almost no poured concrete, frankly — it’s a very light touch on the ground,” Straubel said. “You can pick up and move everything. You can deploy it very fast. Solar was the same way. We actually used this type of architecture specifically because we could deploy it very fast.”
On the solar side, Redwood went with a company that shares the “just throw it on the ground” mentality: Erthos, a scrappy new alternative to the highly engineered trackers that eke every last electron out of the day’s solar arc. This flat-on-the-ground installation also allows a handful of cleaning robots to circumnavigate the array daily and wipe the dust away; their little headlights peeked through the night as Redwood’s celebration cast laser lights across the battery field.
Redwood launched Redwood Energy, its business line for second-life storage, at a precarious time for the battery recycling industry, which has promised to recover nearly all the useful materials from old EV batteries.
Redwood succeeded in raising nearly $2 billion in equity investment since its founding in 2017. It seems to have plenty of resources for the time being. But a leading competitor, Li-Cycle, declared bankruptcy this year after failing to raise the money to complete its recycling facility in upstate New York. Another top contender, Ascend Elements, has pushed back its timeline for a facility in Kentucky, citing delays from its anchor customer.
The actual task of economically recovering the most valuable battery materials appears to have proven harder in practice than it looked in the pitch decks. Setting aside the technical challenges, there are serious business obstacles. Many key battery commodities have fallen steeply from high prices a few years back, undercutting the value of the recycled products. And there isn’t yet a critical mass of cathode makers to sell to in the U.S., so any recovered materials are just going to generic metals markets for now.
“In a way, we started Redwood almost too early,” Straubel admitted. He was talking about how used EV packs were hard to come by a few years ago. But Redwood and the other recyclers are also now too early for the domestic EV-battery-materials market they would like to sell into.
While that market for recycled materials develops, Redwood can pull in “almost an order of magnitude” more value from its batteries by deploying them for energy storage needs.
“Every battery that we can possibly redeploy, even for as short as a few months, we see a compelling financial case to do that,” Straubel said. In fact, he noted, “This definitely has the potential to grow faster and even to contribute more revenue than the core recycling business.”
That’s somewhat jarring to hear from the battery recycling startup with the most money behind it. The investors funded a battery materials business, not a second-hand battery purveyor. But Straubel stressed that he sees the energy business as additive, not competitive with the original business.
“We’re not getting rid of that material — we’re actually keeping ownership of it,” he said. “We’re keeping the rights to recycle it, and we’re excited to recycle it when it’s done doing its second life in energy storage.”
Redwood Energy is talking with AI customers around the country, but it’s also well-positioned in a desert valley east of Reno that has become something of an industrial and telecom hub. A particularly energetic trick-or-treater could leave Redwood’s campus and knock on the doors of Google, Apple, and Switch, the owner of a fortress-like data center. Microsoft just acquired 300 acres in the neighborhood.
“Those would be logical targets,” Straubel allowed.
A clarification was made on July 7, 2025: This article has been updated to clarify that B2U built a 12-MWh second-life storage facility in California, in addition to its initial 28-MWh installation.
The U.S. battery supply chain just got a little stronger.
LG Energy Solution, a division of the major Korean battery manufacturer, is now producing battery cells for grid-scale energy storage at a site in Holland, Michigan. The company spent $1.4 billion to expand the factory, which previously made electric vehicle batteries. At full capacity, the new lines will produce 16.5 gigawatt-hours of lithium iron phosphate cells per year.
“That’s a sizable portion of annual domestic demand for energy storage battery cells,” said Noah Roberts, vice president for energy storage at the American Clean Power Association trade group, who toured the LG factory Tuesday. “It’s a testament and demonstration of the industry’s commitment to onshoring manufacturing and ramping it up in short order.”
The lithium iron phosphate chemistry, often abbreviated as LFP, has grown increasingly popular for stationary storage and EVs; it offers fire-safety benefits, durability, and lower costs compared to the typical electric vehicle chemistries, at the expense of some energy density. Until now, American battery customers had to turn to China for any LFP supplies. LG’s facility appears to be the largest giga-scale LFP production in the U.S. Japan’s AESC recently launched LFP production at its factory in Smyrna, Tennessee, and Tesla is working to onshore LFP production as well.
As such, LG’s investment is strengthening the U.S. clean energy supply chain at a time of great precariousness, when several other would-be battery manufacturers have failed to deliver.
The plan originated as a way to bolster local supply chains, before Congress passed concerted battery manufacturing incentives, said Jaehong Park, CEO and president of LG Energy Solution Vertech, which focuses on stationary grid storage. But when the Inflation Reduction Act of 2022 created incentives for manufacturing and grid storage deployment, LG upped its planned capacity from 4 gigawatt-hours to the eventual 16.5.
The company initially intended to install these manufacturing lines in Arizona, but relocated them to a portion of its Holland facility that had been developed to expand EV battery production, which LG has done there since 2012. By shifting the LFP equipment to the space in Holland, LG could open commercial production a full year earlier than originally planned, noted Tristan Doherty, chief product officer at the storage division.
Now the Holland manufacturing space covers the area of 42 football fields, and will employ 1,700 people when fully staffed.
“It is very clearly a state-of-the-art facility with the most advanced manufacturing that you can have in the United States,” Roberts said.
The LFP products are booked up six months out, and LG is already looking at doubling the production capacity next year, Park said.
Manufacturers took a gamble in betting that the U.S. could reshore the battery production that China has cornered with dedicated industrial policy over the last decade or more. Companies need to build new industrial hubs and train American workers, and then try to match the quality and consistency of the incumbent industry in China.
The Biden administration passed several incentives to reduce the cost premium for “Made in the USA” batteries, including tax credits for purchasing electric vehicles with domestic batteries, and bonus credits for grid storage developers who buy domestic content.
But the current Republican majority in Congress is working to eliminate those policies, to save money for much more costly deficit spending in President Donald Trump’s signature policy bill. Companies like LG that greenlit multibillion-dollar factory investments under one tax credit regime no longer know which rules will apply when they start production.
Doherty acknowledged there’s a great deal of uncertainty at the moment, but said he’s confident in the long-term bet on U.S. battery production.
“It’s clear that the industry is here and it’s here to stay — the question is just what it looks like and what are the nuances to make it work,” he said. “There’s a lot of very big deals that are in the works. Everyone understands, you need to get U.S. battery supply in your supply chain as quickly as possible.”
Trump’s massive tariffs on China could in theory support domestic producers. But the president has changed his tariff plans from week to week, denying would-be manufacturers the stable business environment they like to see before committing billions of dollars to a yearslong endeavor. Blanket tariffs on China also inflate the cost of battery materials, which are almost entirely processed in that country, as well as the cost of battery manufacturing equipment, which also largely originates there.
LG, as a South Korea-based conglomerate, has been able to avoid the negative scrutiny that American politicians have increasingly leveled at Chinese clean energy manufacturers. LG now sources its battery materials for Holland from outside China, and its manufacturing equipment came from Korea and Japan, Park said.
When Trump came into office, the U.S. was on track to achieve self-sufficiency in battery cell production, per a 2024 analysis by Argonne National Laboratory. The U.S. could make 74 gigawatt-hours of lithium-ion battery cells in 2023, but was set to grow that to 1,133 gigawatt-hours by 2030, comfortably more than expected demand.
During Trump’s tenure, though, new manufacturing investments have plummeted compared to the Biden years, and project cancellations surged to nearly $8 billion in the first quarter of 2025. In that time, for instance, Freyr Battery canceled a planned battery factory in Georgia (and later rebranded itself as T1 Energy), and Kore Power axed a lithium-ion factory slated for Arizona.
Elsewhere in Michigan, startup Our Next Energy has been laboring to build the first large LFP factory in the U.S. But it has yet to secure the funding necessary to fill out the cavernous building it acquired west of Detroit, and the company is struggling to stay afloat.
T1 Energy, Kore Power, and Our Next Energy share something in common: They are venture capital-backed startups attempting to compete with the incumbents of the global battery industry. That model hasn’t produced a standout success yet — even Tesla initially tapped an incumbent, Panasonic, to make EV batteries at its Nevada Gigafactory.
The achievement at Holland looks rather modest compared to LG Energy Solution’s global portfolio, which Doherty said has reached around 500 gigawatt-hours of annual battery production.
“As a big company with a big balance sheet, we can have the confidence to say we’ll weather this storm,” Doherty said. “We’ll make it to the other end because we see where this is going.”
LG’s customers may have more difficulty riding out the turbulence of constantly changing tariffs and tax policy.
“This is a market that is growing, and any disruption that causes it to contract is something that will harm manufacturing,” Roberts said of the grid storage construction sector.
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
Record-breaking heat swept across the eastern U.S. this week — and with millions of air conditioners whirring, power demand came close to breaking records too.
The ISO New England grid region, which covers most of New England, saw its second-highest power demand ever on Tuesday. In Maine, experts with the Governor’s Energy Office told the Portland Press Herald that New England would’ve beaten the record if it wasn’t for behind-the-meter solar power, like panels on rooftops and over parking lots that aren’t controlled by grid operators. But the region still had to activate fossil fuel-fired peaker plants — which worsen climate change and air quality — to meet demand in the evening.
The grid operated by PJM Interconnection, which includes New Jersey, Ohio, Pennsylvania, Virginia, and other mid-Atlantic states, also came close to breaking demand records both Monday and Tuesday. Power outages affecting thousands of homes were reported throughout the region, with utilities blaming many of them on the high temperatures.
One growing technology could’ve helped the grid manage the heat even better: battery storage. Take New England. Instead of switching on fossil-fuel peaker plants, batteries could’ve stored excess power generated during the day and discharged it when demand peaked — something numerous studies have suggested as a solution for the region. It’s a method that the grid operators for Texas and California rely on every day, as power generated when the sun is shining is stored for use when it sets.
But not every region is embracing the technology. PJM, in particular, has failed to take advantage of batteries in spite of its demand challenges, partly because it has one of the longest waits in the country to connect to the grid.
Battery storage is also threatened by the “Big, Beautiful Bill” currently making its way through Congress. While the Senate did extend a lifeline to the energy-storage industry in its version of the bill, a Wood Mackenzie/American Clean Power Association analysis out this week found that grid-battery installations could still dip as much as 29% next year if tax credit and tariff uncertainty continues.
New York envisions a nuclear future
New York Gov. Kathy Hochul (D) launched an ambitious quest this week, directing the state’s Power Authority to build a large nuclear reactor. The reason? Rising power demand.
“If we don’t increase our capacity over the next decade, we will see rolling blackouts,” Hochul warned at a press conference. “This is the best technology to meet this demand.”
New York is already home to three nuclear power plants, and until just a few years ago, it had four. The Indian Point power plant shut down in 2021 over environmental contamination concerns. But since then, New York has had trouble making up Indian Point’s lost generation capacity, leading the state to rely on more gas power — which has in turn raised greenhouse gas emissions.
In Texas, a company led by Rick Perry, former Republican governor and Trump administration energy secretary, is proposing a nuclear project of its own. Fermi America aims to build four 1-gigawatt nuclear reactors to power a massive data-center campus.
It’ll be years before either one of these proposed plants would come online. But at the very least, it’s yet more evidence of nuclear power’s rebounding popularity on both sides of the aisle.
Senate parliamentarian rescues some energy measures from the “Big, Beautiful Bill”
Some of the Senate’s efforts to roll back Biden-era energy and environmental measures were knocked down a peg this week, courtesy of the body’s parliamentarian. The nonpartisan adviser to the Senate ruled that many “Big, Beautiful Bill” provisions can’t be passed via the 50-vote budget reconciliation process, and instead will need 60 votes to pass. Senate Republicans have only 53 seats.
The parliamentarian’s critique includes a measure that would force the U.S. Postal Service to sell all 7,200 of its newly purchased EVs and scrap its charging infrastructure — a move the USPS said would cost it $1.5 billion. The parliamentarian also ruled against provisions to speed fossil-fuel project approvals, repeal the EPA’s tailpipe-emissions rules, and sell off public lands.
In response, Senate Republicans unveiled new language on Wednesday that omits the tailpipe-emissions rollback and makes other energy-related edits.
Also this week, several groups — including car dealers, energy investors, and even Georgia Republican state legislators — wrote to the Senate urging it to protect clean energy tax credits.
EV funds restored: A federal judge orders the Trump administration to release billions of dollars of frozen funding for 14 states to build a public EV charging network, but leaves out Minnesota, Vermont, and Washington, D.C., which had also sued to get funding restored. (Associated Press)
Building more batteries: LG Energy Solution cuts the ribbon on its expanded battery plant in Michigan, where it’ll now produce utility-scale battery cells that utilize lithium iron phosphate chemistry. (Canary Media)
Coal’s deadly impact: The “old man’s disease” of black lung has been affecting younger coal miners at rates not seen since the 1970s, and advocates worry cuts to federal health and mining safety offices Trump’s attempt to revitalize the mining industry could exacerbate the problem. (New York Times)
Green lawns, greener mowers: Colorado landscapers are making the transition to electric lawn equipment after new state regulations went into effect this month to help curb noxious fumes that contribute to poor air quality. (Canary Media)
Fishing for electrification: Electric boats and solar-powered processing equipment are starting to create environmental and financial benefits for Maine’s growing shellfish industry, but uncertainties around federal funding could slow progress. (Maine Monitor)
A geothermal community: A suburb of Austin, Texas, aims to power 7,500 planned homes and commercial buildings with a sprawling geothermal energy project. (Texas Tribune/Floodlight)
Weatherization paradox: Many low-income households can’t access the free, energy-saving Weatherization Assistance Program because they can’t afford to make basic but expensive repairs required for qualification. (Grist)
Steel’s cleaner future: Steelmakers planning new facilities in the U.S. are embracing a cleaner technology for purifying iron ore, which can then be used in electric furnaces to finish the steelmaking process. (Canary Media)
Senate Republicans released a draft budget on Monday that presents a slightly less draconian prescription for clean energy tax credits than what the House had put forth.
In May, House Republicans voted to slash all the clean power credits, with some favorable treatment for nuclear plants. The Senate took a more nuanced approach, doing away with credits for cheap but intermittent resources, while continuing to incentivize projects that can generate power on demand.
The Senate version would crank down investment and production tax credits for wind and solar power starting in 2026, reducing them to zero by 2028. But the Senate Finance Committee threw a lifeline to other zero-carbon power plants, allowing hydropower, geothermal, and nuclear to keep their full credits until 2033. Crucially, energy storage was included in that group, which could help grid batteries keep their meteoric growth streak going.
This effort to continue supporting “firm” power sources, which provide energy even when the sun isn’t shining and the wind isn’t blowing, could be hugely consequential for America’s ability to meet spiking demand for electricity. Companies are racing to build new power plants to serve AI computing and domestic manufacturing (two avowed priorities of the Trump administration), not to mention the widespread electrification needed to address climate change.
The problem is, nuclear construction has stagnated since the woefully delayed and over-budget Vogtle expansion; hydropower has been essentially frozen for decades; and geothermal is just starting to gain traction thanks to a handful of startups developing new technologies.
Of the Senate’s chosen few, batteries are the only contender showing real dynamism in energy markets: In just a few years, they’ve jumped from the margins to become the second-biggest source of new power capacity added to the U.S. grid each year, after solar. Energy storage dominates the queues of projects waiting to hook up to the grid in the next few years in places like California and Texas.
The Senate still needs to debate this proposal and see if it rallies enough votes to pass. Then the Senate and House will have to reconcile their differences. There’s no way to know if the current Senate language will become the law of the land.
Nonetheless, this proposal changes the political landscape for clean energy advocates, by splitting clean energy into winners and losers. It also tacks on requirements around foreign influence that seem conceptually more workable than the House’s “poison pill” approach, but that could still thwart actual construction.
The idea of excluding wind and solar from receiving credits has been percolating over the last few months, though it was easy to miss in a generally turbulent news cycle. In April, U.S. Rep. Julie Fedorchak, a Republican from North Dakota, introduced a bill that she dubbed the “Ending Intermittent Energy Subsidies Act.”
“Wind and solar are no longer emerging technologies—they’re mature, market-proven, and widely deployed,” Fedorchak said in a statement at the time. “As all the grid operators are saying, we need more dispatchable resources. We must stop providing generous incentives that run contrary to that.”
The legislation didn’t get much attention at the time, and Fedorchak’s House colleagues yanked support from several of the dispatchable options anyway. But she had some historical facts on her side: Wind and solar have enjoyed federal tax structures since the George W. Bush era (incentives for wind actually go back further), when they emerged as a broadly supported Republican energy policy. Storage didn’t get its own tax credit until the Inflation Reduction Act kicked in for 2023. The technology is clearly the newest of the major power-sector players (excluding the nonexistent nuclear fusion and small modular reactor projects).
On June 3, a cohort of clean, dispatchable power providers chimed in on the debate with a letter noting that they can offer exactly the kind of on-demand power Republican senators seem to appreciate.
“Nuclear energy, geothermal, hydropower, and energy storage stand ready to deliver that reliable power,” said the group, which included novel storage startups Form Energy and Hydrostor, along with geothermal, nuclear, and hydro firms. “We believe it is possible to advance genuine deficit reduction without sacrificing the reliable, innovative power that American households, businesses, and national security require.”
They never said to throw wind and solar under the bus, but emphasized the particular value in keeping credits for dispatchable resources as senators decided where to cut spending.
The House, besides greatly shrinking the timeline for clean energy tax credits, tacked on new requirements that industry insiders decried as impossible to fulfill. The language would block incentives for projects that include any components from a “prohibited foreign entity,” legislative jargon which basically means companies in China. The state of globalized supply chains makes it effectively impossible to build a power plant with that constraint.
The Senate shares the concern about tax credits accruing to Chinese companies, but handled it differently. In its version, the company filing for tax credits cannot be literally or effectively controlled by prohibited foreign entities — that’s a test that U.S.-based developers should, in theory, have no trouble passing. But the text gets very specific on what kinds of arrangements could constitute “effective control” of a project, and calls for the Treasury secretary to issue guidance on how to qualify. That creates ample opportunities for U.S.-controlled storage companies that fulfill the spirit of the law to run afoul of certain sub-clauses.
Additionally, developers must spend a certain amount of the total project cost on products that are not from “foreign entities of concern.” The ratio starts at 40% in 2026, and increases annually from there. Lithium-ion batteries still largely come from China; if a project has to buy those, but can secure the remaining equipment for the power plant from the U.S., they may be able to hit the right ratio. On paper, this rule seems more achievable than the House version, which would penalize firms that use even small, low-value pieces like bolts or cables that originate from China, rather than focusing on critical, high-value components.
Of course, tax credit compliance is the province of well-paid lawyers, who would need to translate the details of the Senate language into actionable legal guidance for companies. The clean energy industry is still reeling from yearslong rulemakings at the Internal Revenue Service that held back many of the investments championed by the Biden administration. Today, the Trump administration has winnowed civil service staff and actively opposed clean energy; it’s hard to imagine IRS rulemaking moving more swiftly under those circumstances.
Storage developers are frantically running the numbers on whether their power plant designs can stay within the guidelines for foreign components, so that they’ll qualify for the tax credits. They also need their financiers to feel confident that they will. Highly prescriptive legislative interference in a high-tech business landscape complicates that process, and could cause investors to pull back until the dust clears.
That’s not to say battery construction will come to a halt without workable incentives. It’s arguably the only dispatchable technology that can be built quickly in the next few years. But saddling the credits with additional bureaucratic requirements would inject extra costs and delays into the industry, at a time when the U.S. desperately needs all the on-demand power it can get.
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.”
A new state law will require Ohio utilities and regulators to consider how technology might offer cost-effective options for improving the state’s aging electric grid.
Ohio’s grid, like those in many states, faces rising repair and maintenance costs, growing demand from data centers and other new customers, and increased risks as climate change fuels more frequent severe weather and outages. House Bill 15, signed last month by Republican Gov. Mike DeWine, calls for a focus on software and hardware solutions to boost the safety, reliability, efficiency, and capacity of existing infrastructure.
Clean energy advocates are hopeful the investments will also allow the grid to accommodate more renewable energy and battery storage projects, which can suffer costs and delays related to transmission bottlenecks.
“This is a really, really great inclusion in the bill,” said Chris Tavenor, an attorney at the Ohio Environmental Council, an advocacy group.
Advanced transmission technologies that utilities must contemplate under HB 15 include things like sensors that allow lines to safely carry more electricity when conditions are favorable, a concept known as dynamic line rating. Digital controllers can remotely adjust the amount of power flowing through different parts of the grid, while topology optimization software can reroute power around congested areas, like a navigation app for electricity.
A key benefit of these technologies is that they can be used with existing infrastructure. When wires do need to be replaced, advanced conductors provide an energy-saving option. Those conductors use carbon composites or other materials to carry more electricity with less loss of that energy, compared to traditional wires of similar diameter.
A high-tech approach can create space on the grid for more renewable energy to come online. That would lessen the need to run expensive, polluting coal-fired power plants, said Rob Kelter, a senior attorney with the Environmental Law & Policy Center, a legal advocacy organization based in the Midwest.
Besides helping to mitigate climate change, less pollution would help people’s health as well, Tavenor said.
Under HB 15, owners of high-voltage power lines must file annual reports showing which advanced transmission technologies they considered as part of their five-year forecasts. Those companies will also need to identify areas of the grid with congestion, and compare the cost of addressing it with traditional versus advanced technologies.
The reports will be available to the public, and interested parties may ask the Public Utilities Commission of Ohio to hold a hearing on whether utilities properly reported transmission information and whether they should be able to recover costs from customers.
The Ohio Power Siting Board must also require companies to consider technology solutions before it approves any new transmission projects. Companies would have to file reports and expert testimony to support any decision to forego advanced technologies in favor of conventional projects, Kelter said.
Advocacy groups and other stakeholders “would have a chance to similarly argue that those technologies are available and that they’re cost-effective, and that they would be able to alleviate congestion and delay the need for new transmission lines,” Kelter added.
The law requires the Public Utilities Commission of Ohio to study the costs and benefits of the various technologies, including how to streamline their deployment. That report will be due by March 1 next year.
Some Ohio utilities have already been exploring the potential for advanced transmission technologies. In 2023, AES installed 42 dynamic-line-rating sensors at towers along five transmission lines owned by its Ohio and Indiana utilities. The companies shared early results last year showing that installing the sensors was cheaper and faster than replacing power lines, and using the sensors increased the system’s electricity-carrying capacity.
American Transmission Systems, a subsidiary of FirstEnergy, is planning to spend nearly $900 million on dozens of transmission projects across Ohio in the coming years. “We are currently reviewing House Bill 15 and exploring how its provisions around advanced transmission technologies could be integrated into our planning to strengthen the power grid for Ohio customers,” said FirstEnergy spokesperson Lauren Siburkis.
Many of the law’s potential benefits hinge on how the Ohio Power Siting Board and Public Utilities Commission of Ohio implement its terms when making decisions on siting and electric rates, Tavenor noted.
The law’s advanced technology provisions only apply to high-voltage parts of the grid that move electricity over long distances. It doesn’t require utilities to consider high-tech approaches to improving the local distribution lines that deliver electricity to homes and businesses.
So, for example, AEP Ohio won’t need to consider advanced transmission technologies in its latest rate case filed on May 30, spokesperson Laura Arenschield said. That’s because AEP wants to use the 2.14% increase in base rates to pay for improvements to its local distribution system, not the AEP transmission network.
Similarly, the new law won’t address grid inequities affecting disadvantaged communities in FirstEnergy’s Ohio territory, which the Interstate Renewable Energy Council described in a report released earlier this year.
Even so, investments that use existing system capacity more effectively can still promote equity by reducing the need to build all-new transmission lines. Siting such infrastructure “can be incredibly invasive and inequitable, harming both communities and ecosystems,” said report author Shay Banton, who is a regulatory program engineer and energy justice policy advocate at the Interstate Renewable Energy Council.
Building less brand-new transmission can also save consumers money. Ohioans have generally paid for transmission maintenance and upgrades through a “rider” on their bills. For the average AEP Ohio consumer, that extra charge is roughly $40 per month. HB 15, however, aims to get rid of single-issue riders, so in the future, utilities will instead have to consider transmission costs through rate cases that consider all utility costs and expenses and are heavily scrutinized by regulators. That could also lead to lower costs or at least smaller increases.
“Ohio utility consumers already are burdened by billions in utility transmission projects,” said Maureen Willis, who represents the interests of Ohio’s utility customers in her role as the state’s consumers’ counsel. “By adopting advanced transmission technology, these costs can be reduced, staving off unnecessary ‘gold-plating’ by utilities, giving consumers more bang for the buck. We strongly advocate for this approach to transmission spending.”
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