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Two decades ago, the European Union got basically none of its power from wind and solar. Now, those are the leading sources of electricity in the bloc.
In 2025, wind and solar produced more electrons for the EU than fossil fuels did, per a new Ember report — the first time that’s ever happened over the course of an entire year.
It’s a watershed moment. Back in 2015, just under 13% of the EU’s electricity was generated from whirling wind turbine blades and sun-soaking photovoltaic panels. Fossil fuels, meanwhile, produced almost 43% of its power; coal alone accounted for nearly one-quarter of electricity.
Flash forward to 2025: The share of electricity from fossil fuels dropped below 29% while that from wind and solar jumped above 30%.
Though wind still produces more power for the EU than solar does, it was the blistering growth of the latter that drove last year’s achievement. In fact, wind generation actually declined slightly in 2025 from the year prior, but that was offset by a 20% increase in electricity from solar. All 27 EU nations saw solar generation grow last year — and globally, seven EU nations are among the countries that depend most on solar for electricity.
At the same time, coal has entered structural decline, the result of ever-cheaper renewables, an increasing reliance on natural gas, and a suite of policies discouraging coal use. Last year, coal accounted for just 9.2% of the region’s electricity, and several EU nations have already phased it out entirely or committed to doing so before 2030.
That leaves gas, a fuel that provided 16.7% of the EU’s power last year but which the region produces little of.
Europe had heavily depended on gas from Russia until 2022, when the nation invaded Ukraine and prompted a reckoning around domestic energy security in the EU. The bloc is now aiming to quit Russian gas completely by next year. It has turned to two sources to make up for that lost energy: domestic renewables and imported liquefied natural gas from the U.S.
But now, with the Trump administration destabilizing the EU-U.S. relationship, the bloc would like to reduce reliance on the U.S., too. The upshot: Expect renewable energy to keep winning in Europe.
This analysis and news roundup come from the Canary Media Weekly newsletter. Sign up to get it every Friday.
Back in 2021, Winter Storm Uri resulted in more than 240 deaths in Texas as freezing temperatures shut down gas power plants and pushed the state’s independent electricity grid to the brink of collapse.
It was an example of a worst-case wintertime scenario for the power sector — and of how fossil fuel resources, often touted for their reliability, can falter when they’re needed most.
So when the massive Winter Storm Fern was bearing down on more than half of the U.S. last week, including Texas and much of the Southeast, onlookers braced for a repeat. And while the grid was indeed pushed to its limit, it weathered the storm.
In Texas, efforts to winterize power plants following Uri paid off, and the state avoided forced shutoffs this time around. Texas also has added a tremendous amount of wind, solar, and battery storage over the past few years, helping its grid keep pace amid the blistering cold. It’s true that Fern wasn’t as intense of a storm as Uri, but University of Texas energy professor Michael Webber told KXAN that the current grid likely would’ve avoided much of 2021’s devastation.
In New England, which was hammered with snow and intense cold, the power grid was stable but dirtier than usual: It had to rely heavily on oil, a reserve fuel that is especially polluting.
One big reason? Canadian hydropower, usually a key source, was hard to come by as that nation dealt with its own cold spell, and gas was in short supply, too, as New England homes burned more of it for heating. For what it’s worth, Vineyard Wind — the nearly complete offshore wind farm that just this week defeated a Trump administration stop-work order — provided a notable boost to the grid even in its partially finished state.
But it wasn’t all good news. More than one million people lost power during the storm, particularly in the Southeast, and thousands are still in the dark as of this morning. Power plant shutoffs aren’t to blame, but rather challenges with the grid itself are, including toppled utility poles, iced-over substations, and downed transmission lines.
PJM Interconnection — the nation’s largest grid operator, which spans the mid-Atlantic — suffered the most intense impact. Data analyzed by think tank Energy Innovation suggests that frozen pipelines and other infrastructure curbed fossil-fueled power plants’ output by tens of gigawatts in the region.
This reduced power generation luckily didn’t force PJM to institute rolling blackouts. But it did, as Energy Innovation put it, underscore a clear point: It’s not viable to rely on fossil fuels alone to get through intense winter weather — and the Trump administration’s efforts to block solar and wind while propping up fossil fuels could prove dangerous if taken to their extreme.
Outside the U.S., offshore wind sails ahead
As the Trump administration turns its back on offshore wind, the rest of the world is going full speed ahead. Ten European countries formed a coalition this week to build out 100 GW of offshore wind power, Alexander C. Kaufman reports. It’s all part of an effort to turn the North Sea into“the world’s largest clean energy reservoir,” German Chancellor Friedrich Merz said.
The announcement follows China’s insistence last week that it will continue to build its offshore wind dominance, even after a dig from Trump.
Back in the U.S., there’s at least a smidgen of good news on offshore wind. On Tuesday, a federal judge ruled that Vineyard Wind can resume construction. It’s one of five offshore wind farms that the Trump administration ordered to stop work in December; judges allowed three other projects to continue building last week. Developer GE Vernova says it could face a $250 million loss this year due to Vineyard Wind’s installation delays.
Tribes press on with clean energy construction
Tribes from coast to coast have long suffered inequities in energy access and affordability. Funding issued under the Biden administration was meant to change that by financing solar farm construction, microgrid development, and other projects to help tribes take advantage of their enormous wind and solar energy potential.
That all got a lot harder when the Trump administration canceled billions of dollars in clean energy funding, Canary Media’s Jeff St. John reports. But tribes are still finding ways to push their projects forward, including with help from the Alliance for Tribal Clean Energy, which brings together tribes, charitable foundations, and clean energy financiers.
“The scale of this disruption is undeniable,” Chéri Smith, president and CEO of the alliance, told Jeff. “But we have to do something. We can’t just sit there.”
Chargers keep cruising: The U.S. built more than 18,000 new public EV-charging stations last year despite the Trump administration’s freeze on EV-charging grants and other efforts to derail the EV transition. (Canary Media)
Tesla’s solar pivot: Tesla announces plans to build its own solar panel at its Buffalo, New York, factory, marking a recommitment to home energy as it moves away from EVs. (Canary Media)
Funding climate resilience: Maine lawmakers advance a “climate superfund” bill that would require fossil fuel companies to pay for damages caused by climate change, and Illinois and Connecticut move toward introducing similar measures. (Maine Morning Star, Hartford Courant, Inside Climate News)
Solar coexistence: A new study debunks the myth that solar panels are destroying huge swaths of North Carolina farmland, finding that arrays take up just 0.28% of land that’s classified as agricultural. (Canary Media)
Data centers’ concrete impacts: Building a data center with traditional concrete can result in tons of additional carbon emissions — a fact that’s driving tech companies to start buying low-emissions versions of the material. (Bloomberg)
Nuclear changes: Internal documents show the DOE is quietly overhauling nuclear safety regulations and sharing the changes with affected companies in an attempt to speed development of next-generation reactors. (NPR)
Preserving plants: The Gemini Solar Project outside Las Vegas shows that careful planning can preserve delicate plants and other species when solar farms are built, and even help them thrive. (Grist)
First it got cold. Across New England, temperatures have been almost constantly below 20 degrees Fahrenheit since last Friday night.
Then it snowed. Winter Storm Fern swept through the region on Sunday and Monday, leaving more than two feet of white stuff in its wake in many places.
But despite the extreme weather, the lights stayed on in the Northeast, for the most part.
At a moment when there is copious debate over how, and how much, to strengthen and expand the New England electric grid, this past weekend functioned as a sort of stress test for the system, highlighting both its strengths and its shortcomings. A closer look at how the grid managed to keep us watching football games and charging our phones offers a few key lessons.
The climate challenges posed by Winter Storm Fern cropped up just a week after the long-awaited New England Clean Energy Connect transmission line started sending hydropower from Quebec into the Northeast U.S. Its purpose: to supply more than 1 gigawatt of power to customers in Massachusetts, providing clean energy and cost savings to the state, which has struck a long-term procurement deal with Canadian energy giant Hydro-Québec.
Last Friday and early Saturday, power flowed as expected. But from Saturday afternoon until Monday afternoon, the exports stopped for all but a few hours on Sunday. Quebec, also experiencing bitter cold, needed the power for its own heating systems. In fact, demand in the province was so high that New England began sending it electricity via a transmission line usually used to bring Canadian power into the U.S.
“There was an expectation that there was a higher quantity and more consistent flows than what happened in practice,” said Dan Dolan, president of the trade group New England Power Generators Association. “The timing of this is certainly drawing a lot of attention, just a week into the commissioning of the project.”
Hydro-Québec didn’t do anything illegal or unethical, Dolan said, and its CEO has indicated the company is prepared to pay the penalties outlined in its contract with Massachusetts for not sending power as obligated. Still, this weekend makes clear that the much-vaunted new transmission line might not do as much to alleviate the region’s energy concerns as had been hoped.
As Canadian hydropower stopped coming, New England also had to cope with constrained natural gas supplies. People throughout the region needed the fossil fuel to warm their houses, limiting the supply that was available to power plants and spiking prices. As a result, usually expensive oil generation became the more economical option. Rarely used oil-burning power plants were called into action, producing more than a third of the power flowing onto the grid for some periods. For a sense of scale: Oil-fired generation provided roughly 1% of the region’s power in 2025.
The sudden dependence on one of the dirtiest forms of power supply makes it clear that the region needs to generate more electricity from a wider range of resources, grid experts say. The grid will be more reliable and more economical if it doesn’t have to put so many of its eggs in an expensive, high-emissions basket like oil.
“The cold temperatures and the storm really, really highlight the importance of a portfolio approach,” said Valessa Souter-Kline, managing director of the industry association Advanced Energy United.
Planning for a future of more abundant power supply is all well and good, but the cost and high emissions of burning oil for electricity highlight the need to do more with the grid we have now, said Phelps Turner, director of clean grid for environmental advocacy group the Conservation Law Foundation.
The region needs to expand demand-response programs, he said. These initiatives compensate consumers for scaling back their energy use at times of particularly high demand, freeing up electrons for other customers. Commercial operations might power down some machines or use an on-site generator for a time, while residential customers might hold off on running their dishwashers for a couple of hours or charge their EVs overnight rather than in the early evening.
“We have to be more proactive about managing demand for electricity,” Phelps said. “Those programs aren’t going to solve all of our problems, but they are a tool that needs to be used in situations like this.”
Much of the conversation about the weekend’s grid performance has focused on the lack of power along the new transmission line and the spike in oil-fired generation. However, wind also made solid contributions to the stability of the system. Overnight Friday, into Saturday, more than 1.5 gigawatts of wind power — roughly 10% of New England’s total load — was flowing onto the grid.
Data from grid operator ISO New England does not break out the contributions of onshore and offshore wind. Energy insiders, however, are confident that Vineyard Wind — the nearly completed development off the coast of Massachusetts that’s already sending some power to the grid — played a significant role in wind’s strong performance.
The numbers suggest that offshore wind could live up to its promise of providing a robust power supply, particularly in the winter. That could go a long way in addressing the region’s energy affordability woes: An analysis released in 2025 concludes that Massachusetts utility customers would’ve saved as much as $212 million during the winter of 2024–25 if the region had had 3.5 GW of offshore wind capacity online.
Of course, this potential only matters if offshore wind developments can actually get built. Federal judges have allowed work to resume on four of the five under-construction projects stopped last month by the Trump administration, but federal policies and challenging economic conditions have stalled or scuttled at least three others in development.
This past weekend, however, made a strong case for the value that offshore wind can bring, experts said.
“Here in New England, low temperatures and strong winds tend to travel together,” Turner said. “Offshore wind can be an incredibly important and valuable resource during cold snaps like this one.”
Donica Brady has worked as a security guard, a school bus driver, and a fabricator of corrugated metal and bridge girders. But her favorite job has been helping to bring solar panels and batteries to tribal communities struggling to pay their utility bills.
“I grew up in a single-parent home,” said Brady, an enrolled member of the Northern Cheyenne Tribe. “My mom sometimes had to choose which bills to pay. One of the highest bills here is electricity.”
So when Brady got a job offer from the nonprofit group Indigenized Energy, she leapt at the chance. She started by doing community outreach for a $4 million federal grant–funded effort to bring solar to tribal homes and schools. But a much bigger opportunity opened up in 2024, when the Indigenized Energy team joined a five-state, 14-tribe coalition awarded $135.6 million from the Solar for All program, created by the Inflation Reduction Act.
The partners got to work quickly and were able to install two kickoff projects on tribal land in South Dakota and northern Montana. Some of those projects included batteries to provide resiliency against blackouts. One elderly woman in Montana equipped with a solar-battery system didn’t even realize the grid had gone out during a storm last winter, Brady said. “The battery kicked in, and the system was sized right to keep her house powered.”
But Brady lost her job this summer, after the Environmental Protection Agency clawed back the entirety of $7 billion in Solar for All funds — including Indigenized Energy’s grant. Legal challenges against this and other Trump administration rescissions of federal clean-energy funding are underway.
In the meantime, however, the six tribal-focused consortiums that received a total of $504 million in Solar for All funding, including the Tanana Chiefs Conference in Alaska, the Hopi Utilities Corp. in Arizona, and multi-tribal coalitions in the upper Midwest and Northern Plains, have had little choice but to delay projects that require ongoing federal reimbursement — and to lay off workers they can’t afford to pay, like Brady.
“There was money in there for weatherization, for roof replacements, for heat pumps, for a lot of different things to help people,” she said. “After being laid off, I still have people who reach out, and I try to help them as best I can, to point them in the direction of people who may have more answers.”
Across the country, tribal clean energy groups that have had federal funding taken away by the Trump administration are struggling with similar challenges — and looking for ways to salvage the work they’ve already begun.
Under the Biden administration, billions of dollars from the Inflation Reduction Act and the Infrastructure Investment and Jobs Act were directed to tribal projects. Now, significant portions of that funding have been canceled, including Solar for All grants, EPA environmental and climate justice block grants, and U.S. Department of Energy grants for microgrids.
Soon, the One Big Beautiful Bill Act, passed by Republicans in Congress last year, will strip tax credits for solar and wind projects unless they begin construction by this summer or are completed by 2027.
“Tribes are in a really tough place,” Cody Two Bears, the CEO of Indigenized Energy and a member of the Standing Rock Sioux Tribe, said during a November press event. He went on to note, “These incentives were put in place through the Biden administration … to really help communities like mine really flourish economic development–wise and job creation–wise while using renewable energy and alternative energy. And I think that was the vision until this new administration came in and took it all away.”
That money was aimed at addressing the inequities in energy access and affordability for tribal communities, which “suffer from higher-than-average electricity reliability issues, compounded by higher-than-average poverty levels and higher-than-average inadequate housing,” according to a 2023 DOE report.
Roughly 54,000 tribal members live in homes that aren’t connected to the grid, the report found. Many of those households that do get grid power spend disproportionately on energy.
At the same time, tribal lands have enormous solar and wind energy potential, according to a 2018 report from the National Renewable Energy Laboratory. A growing number of tribes are pushing to unlock investment in those resources — even without the support of the federal government.
“We have connections with a lot of different investors willing to put up the capital,” said Clara Pratte, a member of the Navajo Nation and co-founder and president of Navajo Power, a nonprofit that plans to develop up to 750 megawatts of solar and battery storage in the Navajo Nation. “It’s just about getting them to a place of comfort, where they can tell their investors they’re putting their money into something that’s relatively low risk.”
Finding ways to salvage projects robbed of federal funding by the Trump administration is now a top priority for Chéri Smith, president and CEO of the nonprofit Alliance for Tribal Clean Energy, which works with tribes, foundations, and clean energy financiers.
Smith, a descendant of the Mi’kmaq Tribe of present-day Maine and the Canadian Maritime Provinces, said the alliance had worked directly with tribes to secure more than $480 million in federal funding for clean energy projects in 2024. “I’d say 85% of it has been clawed back. The scale of this disruption is undeniable. But we have to do something. We can’t just sit there.”
For Smith, the loss of Solar for All grants was particularly painful. They were expected to enable hundreds of megawatts of new solar and battery systems while also boosting tribes’ workforce training, project development capacity, and utility infrastructure.
With federal funding yanked, “tribes were left with stalled projects, and the risk of losing all that planning,” she said. “We see ourselves as partners that can help preserve that progress and keep that momentum moving forward, even if it’s at a smaller scale or will take longer.”
Filling this financing gap is where entities like the Indigenous Power & Light Fund can step in.
A collaboration between the Alliance for Tribal Clean Energy and major philanthropies, the Indigenous Power & Light Fund launched in September 2024 with the goal of raising $100 million in three years; it has secured just under $40 million to date. With federal funding cuts impacting many sectors, donors have shifted limited capital reserves to other pressing needs.
The fund is now performing “triage” to determine which projects it can support, Smith said. It’s offering zero-interest and low-interest loans of up to $1 million and recoverable grants of up to $500,000 apiece.
Todd Halvorsen, the alliance’s head of energy finance and structuring and a clean energy developer with decades of experience at Solar Power Partners and NRG Energy, identified “development capital” as a key target. This stage of finance “is the hardest to source and the most expensive,” he said, since it must be provided before projects have a clear line of sight on revenues.
As an example, Halvorsen pointed to the fund’s $250,000 bridge loan to a project serving the Metlakatla Indian Community, on Annette Island in southeast Alaska. Metlakatla Power & Light, the utility owned and operated by the tribe, has won millions in grants to retrofit existing hydropower projects, build new wind power and batteries, and bring electric buses to the community, all to replace costly diesel generators and buses.
The project relied on building an underwater power line between the island and the city of Ketchikan to transfer power, Halvorsen said — and a gap in financing to pay the company laying that cable had put the project at risk. The loan from the alliance allowed the cable to be deployed last year, he said.
That, in turn, enabled Native Community Development Financial Institutions (CDFIs), including the Native American Bank and Oweesta Corp., to close a $5.2 million bridge loan to move the project to its next stage of development. Halvorsen described these groups as “critical” partners.
But Native CDFIs have also been harmed by the Trump administration.
The Native CDFI Network, a coalition serving tribal communities, in 2024 won a $400 million grant from the Greenhouse Gas Reduction Fund, the $20 billion “green bank” program created by the Inflation Reduction Act. EPA Administrator Lee Zeldin froze that funding in early 2025, and legal challenges to reverse that decision suffered a setback in September when the U.S. Court of Appeals for the D.C. Circuit reversed a lower court’s injunction on the frozen funds.
“Everyone’s reeling from the changes that have happened at the federal government,” said Alexander “Brave Journey” Sterling, CEO of Turtle Island Community Capital, a nonprofit that works with tribal groups in New England and the Eastern Seaboard. “There are a ton of projects in preengineering or early stages of procurement that are basically ready to go but need funding.”
In October, Turtle Island won a small amount of grant funding from the Tamalpais Trust, with underwriting and support from Oweesta. Sterling hopes to put that money toward early-stage work, such as technical assistance for tribal projects to do site surveys or community outreach.
Projects that have lost grant funding can offer sound long-term economic benefits for investors and tribes alike, Halvorsen said. Metlakatla Power & Light expects to save about $910,000 per year in energy costs by supplanting diesel fuel with carbon-free energy, for example.
But replacing grant funding with debt and equity investment can be complicated. The Indigenous Power & Light Fund is working with some of the tribal consortiums that have been denied their Solar for All funding, though it hasn’t announced any financing structures to date.
“Communities are having to refocus on building the capital stack to get projects together, to shift to cash-flowing projects,” Halvorsen said. “But there are no other options right now, other than hopes and prayers and lawsuits.”
Tribes are also fighting to secure their fair share of the wealth that clean energy developments can generate. That’s a legitimate concern, given the history of exploitation of tribal fossil fuel resources.
“The Navajo Nation really saw exploitative relationships with coal mines and power companies,” said Pratte of Navajo Power. “We know these for-profit entities are there to make a profit for their shareholders. But we can be clear-minded about how we work with them to enable our goals.”
Enabling tribes to own their own energy resources and create their own utilities and energy authorities is central to meeting those goals, said Robert Blake, a tribal citizen of the Red Lake Nation of Ojibwe people.
Native Sun Community Power Development, the nonprofit Blake founded, is working on these kinds of projects, such as the partnership between the Red Lake Nation and the Standing Rock Sioux Tribe, which are collaborating with Minnesota-based Open Access Technology International to install and operate EV chargers.
“We know that poverty is at the heart of all these problems communities face,” he said. “If we can battle these social ills through jobs, careers, and economic development opportunities, these communities have assets now … You can sit down and negotiate with the local utility.”
Tribes also need to build workforce and project development capacity to ensure they can expand and maintain projects after outside funders move on, said Two Bears of Indigenized Energy. His group partnered with solar installation company Freedom Forever to train and employ tribal workers for the projects it built using DOE funds.
“Many of them have been given solar jobs outside their reservation and come back to do work in their communities,” such as restoring malfunctioning solar power systems installed at the Northern Cheyenne Indian Reservation, he said. “Because of their training and expertise, they were able to fix them themselves and not have to reach out for outside contractors.”
Unfortunately, the Trump administration has also left tribal training programs for solar jobs in the lurch.
Two Bears cited the example of Red Cloud Renewable, a 2-decade-old energy efficiency and solar installation training center on the Pine Ridge Indian Reservation in South Dakota and Nebraska, which has trained more than 1,000 students, including Donica Brady.
“Solar for All was a great initiative,” said Chief Henry Red Cloud of the Oglala Lakota Nation, the center’s executive director. As part of a plan designed by the 14 tribes that had won funding under the program, “we were given the green light — ‘Go ahead and send your people out to Red Cloud, get the training you need.’”
After Solar for All was canceled, the training center scrambled to secure outside funding for about $160,000 in costs it couldn’t recover from the federal government, he said. “If it wasn’t for the funders, we wouldn’t have been able to pull that off.”
The Solar for All program is currently held up in court, and legal challenges to restore funding face an uphill battle. Blake, whose company Solar Bear led construction of the first two solar installations on the Red Lake Nation, isn’t waiting for court challenges to free up money frozen by the Trump administration.
Either way, “all this work needs to be done,” he said. “Energy prices will keep rising. Renewable energy technology will only get better and cheaper. And climate change isn’t going anywhere.”
Brady, who has since landed a job as a solar-project scheduling coordinator with Freedom Forever, said she’s not giving up on clean energy, either.
“This isn’t the first time the federal government has gone back on things. You consider the history of Native Americans and broken treaties,” she said. But “Northern Cheyennes are like the buffalo. We don’t run away from storms like every other animal. We turn and face the storm.”
Factories that make essential materials like steel and cement need scorching-hot air and steam to transform raw ingredients into finished products. Traditionally, they get that heat by burning fossil fuels. But the startup Electrified Thermal Solutions is pursuing a far cleaner approach: tapping piles of bricks.
The Boston-based company has developed a thermal battery system that uses electricity to heat metal-oxide firebricks for hours at a time. The goal is to soak up wind and solar power from the grid during cheaper off-peak periods, then deliver the stored heat to industrial furnaces, boilers, and kilns whenever manufacturers need it.
Now, Electrified Thermal is putting its technology to the test. Last week, the MIT spin-off unveiled its first commercial-scale thermal battery at the Southwest Research Institute in San Antonio. Its Joule Hive system can store 20 megawatt-hours of heat at temperatures of up to 1,800 degrees Celsius (3,270 degrees Fahrenheit).
“That is hot enough to do the job of fossil fuels in virtually any application,” said Daniel Stack, Electrified Thermal’s CEO and co-founder. “We’re talking about making cement, steel, chemicals, and glass, but also things like potato chips, which need steam generation for food processing.”
From the outside, the Joule Hive heat battery resembles a truncated shipping container connected to pipes and wires. Its insulated steel walls enclose stacks of firebricks, which are charged up by running clean electricity directly through them. The thermal energy is then discharged by running air through the brick stacks that can be piped as hot gas directly into factories.
The unit in San Antonio will allow manufacturers to “kick the tires” to see how the system works, including for on-site testing of minerals drying and other materials processing, Stack said. Electrified Thermal is poised to start delivering its first units to customers’ facilities at the end of this year or in early 2027, he added.
The startup is also partnering with ArcelorMittal to test the thermal-storage technology at the steelmaker’s R&D facility in Spain, and the two are considering piloting the system at a steel plant, where it could potentially replace the fossil-gas heat that is used to shape and strengthen the metal. ArcelorMittal and other global industrial giants, including cement-maker Holcim and iron-ore producer Vale, have invested in the firm.
“Industry has taken notice, and they’ve been very engaged in adopting electrified heating into their processes to try and reduce [energy] costs and cut emissions,” Stack said.
Electrified Thermal is one of more than two dozen startups that are attempting to clean up heavy industries by harnessing thermal storage, using not just specialized bricks but also materials such as crushed rock, molten salt, and sand. By banking low-cost renewable power from the grid, the firms aim to deliver heat that’s even cheaper than fossil gas — a formidable challenge for projects in U.S. regions where gas is abundant and inexpensive.
Thermal storage “has rapidly become one of the fastest-growing areas of interest within emerging storage technologies,” said Yiyi Zhou, a clean energy specialist at BloombergNEF, who added that the approach “offers its strongest potential in long-duration, heat-linked applications,” like the ones that Electrified Thermal has focused on.
Startups in this fledgling sector raised about $200 million in venture capital in 2025 from about a dozen disclosed deals, according to the consultancy Cleantech Group. In 2024, the sector raised close to $300 million — a total that includes a $150 million investment in Antora Energy, a California-based company that uses graphite blocks to generate intense beams of heat.
Electrified Thermal, for its part, says it has raised over $23 million in private capital since launching in 2021.
“It’s an exciting space, just given the overall need for electrified solutions in the sectors that thermal-energy storage companies are working in,” said Zainab Gilani, a research associate focused on energy and power at Cleantech Group. “The problem is definitely immense.”
Industrial heat accounts for about one-fifth of the world’s energy consumption and contributes a significant share of planet-warming pollution globally. In the United States, direct heat use in factories is responsible for roughly 13% of the country’s energy-related carbon emissions.
About three-quarters of those U.S. thermal emissions are the result of low- and medium-temperature processes that produce everyday goods like milk, beer, toilet paper, and bleach. In many cases, electric versions of boilers, ovens, and dryers can already replace the fossil-fueled heating systems in those factories.
But higher temperatures are harder to achieve using electrified equipment, since the extreme conditions can quickly destroy their metallic wires and heating rods, Stack said. For startups like Electrified Thermal, the idea is to design systems that can provide “flame temperature” heat for decades before they need replacing, he added.
Only a handful of industrial-scale thermal storage systems have actually been installed to date worldwide, and many additional projects are needed to build up manufacturers’ confidence in this approach, Gilani said.
Rondo Energy, for example, began operating its first 100-megawatt-hour heat battery last October in a rather counterintuitive place: the oil fields of Kern County, California. The battery’s heat generates steam that is injected into oil wells to increase production, a job previously done by a gas-fired boiler. According to Rondo, the project is a necessary step that allows the startup to secure a paying customer as it scales the technology to decarbonize other industries.
Finding cost-effective projects in the U.S. is especially key now that the Trump administration has canceled hundreds of millions of dollars in Department of Energy awards for industrial decarbonization efforts. The defunded projects included ones that planned to use Rondo heat batteries: a plastics-recycling facility in Texas and beverage-production sites in Kentucky and Illinois.
Electrified Thermal, meanwhile, was set to supply its technology to the ISP Chemicals plant in Calvert City, Kentucky. In 2024, the manufacturer was selected for up to $35.2 million in federal grants to replace gas boilers with the thermal battery. But ISP Chemicals later withdrew from award negotiations, according to the DOE’s website, and Stack confirmed that the project is “halted at this time.”
Still, he said, Electrified Thermal remains focused on deploying its first large-scale projects this year and next, and aims to install 2 gigawatts of thermal power capacity by 2030.
The success of thermal storage projects will largely hinge on their ability to deliver heat that’s cheaper than fossil gas — and for that, they’ll need wider access to wholesale energy markets. In certain places, the price of wind and solar power can drop to zero or even be negative when supplies exceed electricity demand for hours at a time. But most industrial customers buy their power from utilities at retail rates, which excludes them from tapping that cheap clean electricity.
In Texas and Europe, however, companies can more readily access those ultralow rates, and tech providers are pushing utilities and regulators in more U.S. states to similarly open their wholesale markets to industrial users.
“Thermal batteries as an asset class are very new, and so the rules were not written with their existence in mind,” Stack said. “We would benefit from opening that market in more geographical areas of the United States.” This includes California, where renewables are so abundant that a large portion of that supply is curtailed when there’s not enough demand.
Stack called the deployment of that first unit in San Antonio a “pivotal moment” for the company. “We’ve turned on a system now that meets industry where they are, and can electrify them while saving them money on their heating bill,” he said. “And I don’t see anything that stops us from mass deployments.”
Clean energy foes, from the Trump administration to state legislators to some community members, have long complained that large solar installations are threatening farmland and rural America’s pastoral way of life.
The claims are especially salient in North Carolina, which is both a top-five state for solar deployment and a behemoth in agriculture. Fighting “Big Solar” has become a passionate cause among a small but vocal group of conservatives in this purple state, where lawmakers recently advanced anti-solar legislation dubbed the Farmland Protection Act.
But a new analysis finds that, in actuality, solar fields occupy a tiny fraction of farmland in North Carolina — less than one-third of a percent of the nearly 11 million acres classified as agricultural.
The report by the nonprofit North Carolina Sustainable Energy Association, now in its third edition, draws on data from the U.S. Geological Survey, satellite imagery, and state registrations of solar projects with 1 megawatt or more of capacity. The previous version, from 2022, found similar results: Solar that year took up 0.28% of agricultural land.
“A narrative we run into pretty regularly is that solar is taking up a lot of farmland,” said Daniel Pate, director of engagement for the association and a report contributor. But, he said, “the number continues to be minuscule.”
The study comes as Trump officials invoke similar criticisms to stymie large-scale solar, including by kneecapping a program that helps farmers install their own solar arrays.
It also comes as local restrictions on renewable energy, including solar, gain steam around the country.
In North Carolina, a looming threat to solar is the Farmland Protection Act pending in the Republican-controlled state legislature. Sponsored by a longtime solar critic and onetime farmer, Republican Rep. Jimmy Dixon of rural Duplin County, House Bill 729 included a complete ban on large-scale solar on agricultural land when it was filed last April. The provision was later removed, but the bill now phases out county property tax breaks for large solar, a deal-breaker for many developers. With backing from the state Farm Bureau and the state’s agricultural commissioner, the measure has cleared two House committees and awaits a hearing in two more before it can advance to the floor.
Organized opposition, often funded by fossil fuel interests, has unquestionably helped stoke such resistance to renewable energy. But in rural communities, the lingering perception that large-scale solar installations are overtaking the landscape can also come from a place of good faith.
Without doubt, the vast majority of utility-scale solar fields in the state — about 34,000 out of 40,000 acres — are on agricultural land, according to the report. Arrays that have replaced crops and trees are often visible from the road, since that puts them closer to power lines and substations, creating a starker perception of loss. And in some places — especially in wide, flat eastern North Carolina — the concentration of large-scale solar on farmland is substantially higher than the statewide figure. In Halifax County, for instance, solar takes up a full 1% of agricultural land and is on pace to triple its share in the next few years, according to the Center for Energy Education, a local nonprofit.
But despite concerns about its footprint, solar can also help rural communities — to say nothing of its benefits for the climate. Even with the incentives Dixon seeks to abolish, counties are earning vastly more property tax revenue from farmland with solar than from farmland without, researchers say.
Plus, farmers who lease their land for panels have reported earning about $750 to $1,400 per acre per year, according to the report. That steady income can provide a critical supplement to the boom-and-bust revenue inherent in raising crops and animals. That’s one reason Halifax retreated from a proposal last year that would have effectively prohibited new projects: Elected officials heard from constituents who said they would have lost their family farmland but for solar.
Some in the state’s farming community are also enthusiastic about the promise of agrivoltaics, which would allow them to collect revenue from solar while using the land underneath photovoltaic panels for crops, pollinator-friendly plants, or grazing.
Even so, many in the state’s powerful $111 billion agricultural industry remain deeply skeptical of solar. Their distrust is likely exacerbated by decades of bitter battle with environmental advocates — some of the same groups promoting clean energy — over pollution from hog and poultry factory farms.
Jerry Carey, market intelligence specialist for the North Carolina Sustainable Energy Association and another contributor to the report, came face-to-face with some of those skeptics when presenting the findings at a recent meeting with “influential farmers.”
“They’re willing to have a conversation. But they don’t want to hear the numbers. They know what they know. They know what they see,” Carey said. As for the dream of agrivoltaics, he added, “One guy literally said, ‘I don’t want to hear about bees and butterflies.’”
Tesla is rededicating itself to rooftop solar, a decade after it bought the then-leading company in that sector, SolarCity.
The pioneering electric car maker has continued to sell rooftop solar through its energy division since the SolarCity acquisition. But the Solar Roof product — essentially roof tiles that generate energy and which was touted in 2016 as a reason for investors to approve the acquisition — never achieved the pacesetting status that Tesla’s Powerwall did for home storage or its Megapack did for large grid batteries.
On Thursday, a day after reporting year-end earnings for 2025, Tesla unveiled its newest energy product during an event at the company’s retrofuturist Tesla Diner in Los Angeles. And the buzzy new item is, in fact, a rooftop solar panel, launched at a tumultuous moment for both Tesla and the residential solar market.
“This is the first time that we’ve actually fully designed and manufactured our own solar panel, aside from everything that we’ve been doing on the Solar Roof,” said Colby Hastings, who runs the residential energy business at Tesla Energy. “This is available now. This is very real-world.”
Tesla has already begun manufacturing the new panel at its factory in Buffalo, New York, where it built a line capable of more than 300 megawatts of annual production, with room to grow, Hastings said. Tesla also assembles the Solar Roof at that location.
The new design offers “superior aesthetics,” Hastings said, thanks to its low-profile, all-black appearance, with no visible bus ribbon needed to conduct electricity from the cells. Tesla also leaned on its dataset of 500,000 solar installations performed by its in-house teams, Hastings said, to streamline the parts needed to secure the modules to a roof. For instance, the new panel cuts out the rail architecture typically used to fasten panels.
“We’re always looking for ways to eliminate unnecessary pieces and improve time,” Hastings said.
On Wednesday, Tesla reported a drop in revenue (its first full-year revenue drop), vehicle deliveries, and gross profit for the full year 2025. Perhaps the company’s most surprising announcement, though, was that it plans to scrap production of its Model S and Model X cars and instead use those factories to manufacture bipedal automatons. (The solar panels, however, will still be “proudly made on Earth by humans,” per company materials.)
While Tesla’s core business suffered last year, its energy division shone brightly — as automotive revenues fell by 10% for the year, “energy generation and storage revenue” grew by 27%, though the division still makes far less money than its core business. The company deployed an immense 46.7 gigawatt-hours of storage in 2025, more than 10 times the rate just four years prior. But while Tesla freely discloses battery capacity delivered by its generation and storage business, it does not share solar capacity deployed, making it hard to gauge the significance of solar relative to energy storage.
As with Tesla’s vehicle sales, the rooftop solar market is experiencing a downturn. First California, the biggest residential market by far, overhauled the rules for solar compensation in a way that crushed sales. Then the Republican-backed budget law ended the federal tax credit for households that buy their own rooftop solar systems. However, that law kept a tax credit for systems leased by third parties.
Tesla launched a lease offer last year to monetize those remaining tax credits; customers can choose to buy out their systems after five years. As a U.S.-based domestic manufacturer, the company also should be able to claim the advanced manufacturing production credit (45X) for its production in Buffalo.
So in spite of the market turbulence, Tesla can still avail itself of supportive federal policies even though the budget law passed — over the protestations of CEO Elon Musk. But Tesla is far from alone in making solar panels in America these days: It will be competing against the likes of Qcells, the most prolific manufacturer of residential panels in the U.S., which operates more than 8 gigawatts of module capacity, compared with Tesla’s 300 megawatts.
Scale matters in this industry. Lacking that, Tesla does have an advantage: its connected ecosystem of home energy products.
“To my knowledge, we’re the only manufacturer out there that’s directly producing electric vehicles, charging, storage, mounting hardware, solar panels, all of the controls that you can use to integrate these devices and make them work together for your home, and one app to have that full experience in,” Hastings said.
That could be enough to carve out a profitable niche in what’s left of the U.S. rooftop solar market in the second Trump administration.
U.S. solar manufacturers start 2026 in an odd position. They have made real strides toward reshoring production, but still have a long way to go — and federal and trade policies are layering new uncertainties onto the task.
The U.S. is now actively producing all the major components in the solar supply chain: polysilicon, ingots, wafers, cells, and modules. That hasn’t happened in over a decade, since SolarWorld closed its wafer-production plant in Oregon in 2013.
“Except for the glass, everything we have in the module could be domestic, should the client choose that,” said Martin Pochtaruk, CEO of Heliene Solar, which manufactures in Minnesota. “The main issue is the limitation on capacity.”
The U.S. can make almost 65 gigawatts of panels annually, according to the Solar Energy Industries Association. But it can’t yet build enough of the precursor components to meet the demand for panels. (SEIA expects the U.S. will install 44 gigawatts of direct-current solar capacity this year.)
Major factory construction now underway takes aim at that shortfall, even as factory owners grapple with upheavals in federal domestic and trade policies.
Congress created new rules last year that block tax credits from going to “foreign entities of concern,” or FEOC. Those regulations technically kicked in on Jan. 1, but the Treasury Department still needs to release preliminary guidance and launch formal rulemaking.
Separately, an anti-dumping investigation could raise tariffs on solar imports from India, Indonesia, and Laos, as part of a long-running Commerce Department effort to block imports by China-linked companies that build in other countries to avoid steep tariffs.
And last year, Commerce Secretary Howard Lutnick launched an investigation into the national security implications of the polysilicon supply chain, which could impose global tariffs on products that contain polysilicon — including solar panels and their components.
Here are the three biggest storylines to follow for the state of domestic solar manufacturing in 2026.
As of last year, U.S. factories have officially been able to make enough solar modules to meet domestic demand.
Cell capacity, however, lags far behind, at just 3.2 gigawatts. This year, companies are pushing to catch up.
“If we want to have the manufacturing here, we have to have the cell manufacturing here, because that’s the most difficult step, in many ways; it’s where a lot of the innovation happens,” said Tim Brightbill, a lawyer at Wiley Rein LLP who has brought numerous trade cases on behalf of domestic manufacturers. “We can’t just outsource that to China and hope the rest of the industry will be OK.”
Newcomer T1 Energy started building its cell factory in December in Rockdale, Texas, and should open 2.1 gigawatts of cell production by year’s end.
“This is the year of execution for us,” said Russell Gold, T1’s executive vice president for strategic communications. The 100-acre facility will cost $400 million to build and will generate 1,800 jobs. A planned second phase would add another 3.2 gigawatts.
Qcells, the subsidiary of Korean conglomerate Hanwha, is still plugging away on its ingot, wafer, and cell factory in Cartersville, Georgia. The site started producing modules in 2024; it was supposed to produce ingots, wafers, and cells — the more complicated precursor steps — in 2025, but that build-out fell behind schedule. Qcells is aiming to get Cartersville fully operational by the end of 2026, said Marta Stoepker, head of corporate communications at Qcells North America.
Norway’s NorSun had planned a $620 million, 5-gigawatt ingot and wafer factory near Tulsa, Oklahoma, set to open in mid-2026 and supply Heliene and others. But the company’s website returns a 404 error code, and NorSun told Heliene that the Tulsa factory is not moving ahead, Pochtaruk said.
Heliene had wanted to build a cell factory to supply its 1.3-gigawatt module production in Minnesota, but it froze development amid the market turbulence when President Donald Trump took office in 2025. In the coming weeks, Pochtaruk said, Heliene will begin large-scale production of panels using Suniva cells made with domestic wafers, supplied by Corning, which are sliced from domestic polysilicon created by Hemlock Semiconductor in Michigan.
Then there’s an important outlier: First Solar, which has long been the only solar manufacturer with a homegrown supply chain.
First Solar is also unique in that it eschews silicon in favor of thin-film deposition of cadmium and telluride. It’s able to produce a fully functioning solar panel without the separate steps of carving wafers or etching silicon cells. That advantage allowed the company to grow and thrive behind protective U.S. tariffs in the years when the silicon-solar industry collapsed.
First Solar has built 14 gigawatts of domestic manufacturing capacity across Alabama, Louisiana, and Ohio and is building a new site in South Carolina.
The Republican budget law passed last year forces companies that want to claim the solar manufacturing tax credit, or tax credits for installing solar panels, to prove that they aren’t overly beholden to control or support from prohibited Chinese entities.
Weaning any high-tech supply chain from Chinese influence is challenging, but the task is further complicated because the federal government hasn’t finalized its rules yet. In theory, any panel coming off the line since New Year’s Day needs to comply, but doing so requires a bit of extrapolation, or perhaps luck.
Some companies should have no problems. Heliene is headquartered in Canada. Qcells hails from Korea. First Solar is homegrown. Still, they need to pay for the legalistic accounting to prove they qualify.
Some manufacturers that had ties to China, however, have taken steps to reverse that status. China’s JA Solar sold its Arizona factory to Corning. Trina Solar sold its Dallas factory in 2024 to the company that became T1; in December, T1 released a detailed breakdown of the steps the U.S.-headquartered company took to clear itself of FEOC-related risk.
“We want to show investors, hey, we’re prepared for this, we did our work,” Gold said.
Others have slightly more complicated arrangements, like Canadian Solar, which, despite its name, operates largely out of China; and Illuminate USA in Ohio, a joint venture between U.S. developer Invenergy and Chinese solar giant Longi. These firms have not yet completed the kind of sell-off that Trina did with T1, so it’s harder to see how their 2026 production could qualify for tax credits.
In another category are clearly Chinese-owned factories in the U.S., including JinkoSolar in Florida and Hounen Solar in South Carolina, which seem sure to fail the FEOC test.
The quest for FEOC compliance will be a dominant theme for the industry this year — especially once the rules are actually released.
U.S. solar manufacturing has long depended on trade protections, and two major proceedings could reshape the global playing field this year.
Historically, the U.S. has levied tariffs on China’s solar exports in order to offset government subsidies that helped drastically lower the cost of panels made there. Major Chinese manufacturers responded by building module assembly factories in other countries that did not face such tariffs.
Last year, the U.S. added tariffs on solar modules from Cambodia, Malaysia, Thailand, and Vietnam after concluding a Biden-era trade case.
A subsequent petition by U.S. manufacturers could extend tariffs to India, Indonesia, and Laos. Such requests used to draw an outcry from solar developers, who would face higher prices for their materials. But last year, at the U.S. International Trade Commission’s preliminary hearing for the latest case, nobody testified in opposition, Brightbill said, though some parties later filed opposing statements.
The Commerce Department’s investigations could wrap up over the next few months and lead to preliminary duties, with a final determination coming in the early fall.
A different trade action could take a more global approach than this country-by-country effort.
“It’s not only tax credits you have to look into,” Pochtaruk said of planning new factory investments. “Any and all business plans have to have in consideration what the heck the 232 [outcome] is.”
He’s referring to the ongoing investigation into the national security implications of the polysilicon supply chain, under Section 232 of the Trade Expansion Act of 1962. Trump previously used this mechanism to push for tariffs on things like steel and aluminum; it’s different from the authority he invoked for the so-called Liberation Day tariffs last year.
“The courts have largely upheld Section 232 actions by the president, because they tend to defer to the president on national security issues,” Brightbill said.
The Section 232 investigation could produce a far-reaching global tariff on products that contain silicon — not just raw polysilicon but also finished solar cells and panels.
Such a global tariff could drive up costs for the domestic module makers that still have to import cells, since the U.S. is not yet self-sufficient in that step. Then again, it would also raise the cost of foreign modules competing with domestic ones.
“It could be a way to address this Whac-A-Mole problem that we’ve been dealing with for some time,” Brightbill said.
By statute, the Commerce Department must send recommendations to the White House by March 28, which then gives the president 90 days (until late June) to formulate a response.
“All of this contributes to a level of uncertainty around your solar supply chain, and makes building a reliable, transparent, domestic solar supply all the more important,” said Gold, of T1. “The fact that we have a supply deal with Hemlock and Corning gives us a lot of comfort.”
New Hampshire Republicans are attempting to do away with a 50-year-old property tax exemption for households and businesses with solar, contending that the policy forces residents without the clean energy systems to unwittingly subsidize those who have them. Supporters of the exemption, however, say this argument is misleading, insulting, and at odds with New Hampshire’s tradition of letting communities shape their own local governments.
The focus of the debate is a bill proposed in the New Hampshire House this month by Republican Rep. Len Turcotte and several co-sponsors in his party. The measure would repeal a law, established in 1975, that authorizes cities and towns to exempt owners of solar-equipped buildings from paying taxes on whatever value their solar systems add to their property. As of 2024, 153 of the state’s municipalities – roughly two-thirds – had adopted the exemption, one of the only incentives offered in support of residential solar power in the state.
The exemption means that homeowners without solar must pay more property tax to make up for the money not being collected from the “extreme minority” who have solar panels, Turcotte said while presenting his legislation at a hearing of the House Science, Technology, and Energy Committee last week. This “redistribution” of the tax burden is unfair, he said.
The solar property tax exemption is a fairly common policy: Nationally, 36 states offer some version of it. While legislators in many states have targeted pro-solar policies like net metering, property tax exemptions have so far avoided similar attacks. New Hampshire, therefore, could end up as a proving ground for whether this approach can find traction.
New Hampshire does not have a sales tax or an income tax and leans heavily on local property taxes for revenue; its rates are among the highest in the country. That makes changes to property tax policy a particularly sensitive subject. The solar exemption bill has Republicans, who are typically tax averse, walking a fine line between championing what they say is fairness for all and pushing a policy that will inevitably raise taxes for some.
The state authorizes 15 other property tax exemptions — including for elderly residents, veterans, and those with disabilities — but Turcotte’s bill targets only the one for solar.
The exemption is a “local option” policy, meaning cities and towns must opt in through a vote in each municipality. Turcotte, however, doubts the average resident realized that they were signing up to pay more on their own taxes.
“They see a feel-good measure,” he said. “Do they truly understand? I don’t believe they do.”
After Turcotte presented his bill, the remaining speakers — about a dozen clean energy advocates, lawmakers, business leaders, and local solar owners — uniformly opposed his proposal.
Removing the exemption would be an unfair rule change after homeowners invested in solar systems with the understanding they’d be getting a tax break, many argued. Businesses using solar could face a “significant tax increase,” said Natch Greyes, vice president of public policy at New Hampshire’s Business and Industry Association. The change could cost homeowners with solar hundreds of dollars per year while barely reducing the property tax rate for everyone else, others said.
In the town of Hudson, for example, $2.2 million in property value isn’t taxed because of the exemption, out of a tax base of $5.1 billion, its chief assessor James Michaud testified. Removing the exemption would have virtually no effect on the tax rate, he said.
“It’s almost incalculable how small it is,” he said.
Whatever tiny tax shift the exemption creates is worth it, others argued, saying that it provides an incentive for the public good: More solar means lower greenhouse gas emissions and less burden on the grid. Turcotte countered that these broader benefits of solar — many of which have been well documented — are “subjective.”
The question of local control also loomed large in the testimony. In New Hampshire, whose motto is “Live Free or Die,” the right of individual towns to decide on their own rules and regulations has long been a point of pride. Repealing the exemption would mean overriding decisions made by voters. Turcotte’s claim that residents didn’t understand what they were getting into is not only condescending but also just plain wrong, several witnesses said.
“You are essentially, with this bill, substituting your judgment about what is proper at the level of local taxation for that of town meetings and city councils throughout the state,” said Rep. Ned Raynolds, a Democrat, while questioning Turcotte.
The bill now awaits a vote in committee before it can face a floor vote from the full House. It would then advance to the Senate. Republicans control both chambers of the state Legislature and the governor’s office.
But the bill’s opponents hope that lawmakers will heed their arguments and give weight to the mass of voters who have approved the exemption across the state.
“This is the reason two-thirds of the towns have adopted it: They can see it’s a good thing,” testified David Trumble, a solar owner from the town of Weare. “Solar is a good thing.”
Last year brought a torrent of bad news for the U.S. electric vehicle industry. The Trump administration pushed Republicans in Congress to cancel Biden-era EV tax credits and revoke states’ rights to set clean-car mandates. The White House moved to weaken vehicle fuel-economy standards. And it froze billions of dollars in federal EV-charging grants — although legal challenges have since unlocked $5 billion of that money.
Despite the upheaval, U.S. public charging networks had a growth spurt last year, according to a report released today by data analytics firm Paren. And the new chargers are working more reliably and being used more heavily than ever — a sign the country is matching charging supply to demand.
The nation’s public fast-charging network expanded by 30% over the course of 2025, adding 18,041 ports, according to Paren. That’s up from the 13,970 fast-charging ports deployed in 2024, and way up from the 5,313 installed in 2021.
“We’ve got a record number of chargers being deployed by a bunch of new players in the industry, as well as the stalwarts,” said Bill Ferro, Paren’s co-founder and chief technology officer.
Last year’s growth included more charging stations, but also more ports per station, Ferro noted. That’s a sign that charging providers are striving to ensure that EV drivers don’t have to wait too long for a charge when they pull up.
Reliability scores, which Paren measures as the share of charging sessions that are successfully completed, ticked up in 2025 too, averaging 93%. That’s good news for EV drivers who’ve been disappointed by malfunctioning chargers in past years. Ferro credited these incremental improvements both to new infrastructure, “which by default is going to work better,” and improved maintenance and remote diagnostics of malfunctioning chargers.
And utilization rates — a measure of how often a charging port is in use — held steady in most states and even increased slightly in some over the course of 2025. Paren tracked 141 million public charging sessions from January to December, a roughly 30% increase from the previous year.
Paren’s data indicates that charging infrastructure is expanding at a rate that matches up well with demand from a growing number of EV drivers, Ferro said. Maintaining that balance is vital for charging providers, who don’t want to overinvest in charging stations that fail to get enough business to pay themselves off, but also don’t want to leave drivers waiting too long for charging ports to open up.
To date, charging remains in much higher demand in some states than in others. California led the pack on utilization of its fast chargers in 2025, as it has for years, followed by Florida, Hawaii, Maryland, New Jersey, and Nevada. But the fastest growth in utilization occurred in Sunbelt states, including Arizona, Georgia, and Texas.
Importantly, the growth in charging infrastructure was driven almost entirely by private investment rather than by government funding, Ferro said. Tesla, which operates the country’s biggest charging network, continued to lead the pack, with more than 6,700 charging ports deployed in 2025, more than a third of the total. But longtime charging operators, other automakers, and regional players also each added hundreds of charging stations over the course of the year.
This increasing private investment helped counteract the decline in federal funds. In February, the Trump administration tried to cancel the $5 billion National Electric Vehicle Infrastructure program. After setbacks in court, the U.S. Transportation Department reopened the NEVI program in August, allowing states to resume contracting and installing chargers. Last week, a federal judge ruled that the department’s initial suspension of the funding was unlawful.
That program was designed to bolster public charging along highways and other major transit corridors across the country, including places where EV adoption has lagged, undermining the business case for building chargers. But with just over 700 ports installed as of the end of 2025, NEVI projects make up only a small fraction of the country’s total public charging — although they’re important for rural areas where chargers are still hard to find.
Although NEVI dollars are flowing again, the Trump administration hasn’t released the entirety of the federal EV-charging funding it canceled last year. States and environmental advocates have filed lawsuits seeking to force the federal government to unfreeze the $2.5 billion Charging and Fueling Infrastructure grant program for state and local agencies, much of it targeted at expanding charging in rural and lower-income areas.
Meanwhile, the One Big Beautiful Bill Act passed by Republicans in Congress last summer not only ended EV tax credits as of September 2025, but will end tax credits for EV chargers as of July 2026. The law also rescinded hundreds of millions of dollars from the Environmental Protection Agency’s Clean Heavy-Duty Vehicles Program, which was meant to help state and local governments, schools, territories, and tribes purchase zero-emissions trucks and buses and charging equipment.
Even NEVI isn’t out of the woods yet. The draft fiscal year 2026 transportation bill introduced in Congress earlier this month would strip $503 million in unobligated funds from the program, according to the Sierra Club, as well as $300 million earmarked for repair and maintenance of chargers — a potential hit to the network’s reliability.
Looming large over charging providers is the risk that EV adoption may slide precipitously downward. Demand for the vehicles boomed right before federal tax credits expired in September, but sales are now slowing. And major automakers Ford and General Motors have written down billions of dollars of losses on their EV investments.
Still, Paren is forecasting that charger deployments will continue to rise in 2026, albeit at a rate of about 8%, much slower than the breakneck pace set last year. Ferro sees the risks of overbuilding charging infrastructure falling mainly on smaller companies or those overly reliant on federal funding, whose networks could be snapped up by bigger firms.
“I think the industry is going to consolidate and expand at the same time,” he said. “We know the larger players are building out for the future. They’re not looking to 2027 for their goals. They’re looking to 2035.”
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