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Discover the best places to build new clean energy to maximize the benefits to people and climate.
In order to accelerate global decarbonization and run the world’s power grids free of fossil fuel power plants and their pollution, where new solar and wind farms get built matters. A lot.
To reduce air pollution and tackle the climate crisis faster, the best places to build new clean energy are where the electricity grid still depends on heavily-emitting fossil fuel power plants.
Brought to you by WattTime, with support from The Nature Conservancy and Project Drawdown.
By measuring the gravitational pull of water for more than two decades, NASA satellites have peered beneath the surface and measured changes in the groundwater supplies of the Colorado River Basin. In a recent analysis of the satellite data, Arizona State University researchers reported rapid and accelerating losses of groundwater in the basin’s underground aquifers between 2002 and 2024. Some 40 million people rely on water from the aquifers, which include parts of Arizona, California, Colorado, Nevada, New Mexico, Utah, and Wyoming.
The basin lost about 27.8 million acre-feet of groundwater during the study period. “That’s an amount roughly equal to the storage capacity of Lake Mead,” said Karem Abdelmohsen, an associate research scientist at Arizona State University who authored the study.
About 68 percent of the losses occurred in the lower part of the basin, which lies mostly in Arizona. The research is based on data collected by the GRACE (Gravity Recovery and Climate Experiment) and GRACE-FO (GRACE Follow-On) missions. The data were integrated with output from land surface models, such as NASA’s North American Land Data Assimilation System, and in-situ precipitation data to calculate groundwater losses.
The conclusions were similar to those arrived at by Arizona State University Global Futures Professor Jay Famiglietti in an analysis of the Colorado River Basin published in 2014, when his team was at the University of California, Irvine. "If left unmanaged for another decade, groundwater levels will continue to drop, putting Arizona’s water security and food production at far greater risk than is being acknowledged,” said Famiglietti, previously a senior water scientist at NASA’s Jet Propulsion Laboratory and the principal investigator of both studies.
The maps above underscore the accelerating rate of groundwater loss detected by the GRACE missions. In the first decade of the analysis, between 2002 and 2014, parts of the basin in western Arizona in La Paz and Mohave counties and in southeastern Arizona in Cochise County lost groundwater at a rate of about 5 millimeters (0.2 inches) per year. Between 2015 and 2024, the rate of groundwater loss more than doubled to 12 millimeters (0.5 inches) per year.
Two key factors likely explain the acceleration, the researchers said. First, there was a global transition from one of the strongest El Niños on record in 2014-2016 to a period when La Niña reasserted control, including the arrival of a “triple-dip” La Niña between 2020 and 2023. La Niña typically shifts winter precipitation patterns in a way that reduces rainfall over the Southwest and slows the replenishment of aquifers.
Second, there was an increase in the amount of groundwater being used for agriculture. “2014 was about the time that industrial agriculture took off in Arizona,” Famiglietti said, noting that large alfalfa farms arrived in La Paz and other parts of southern Arizona around that time. Dairies and orchards in southeastern Arizona likely impacted groundwater supplies as well, he added. Other “thirsty” crops grown widely in the state include cotton, corn, and pecans. Data from the U.S. Department of Agriculture’s Cropland Data Layer (CDL) shows that these crops are common in several parts of southern Arizona, including Maricopa, Pinal, and Cochise counties.
Irrigated agriculture consumes about 72 percent of Arizona’s available water supply; cities and industry account for 22 percent and 6 percent, respectively, according to Arizona Department of Water Resources data. Many farms use what Famiglietti described as “vast” amounts of groundwater in part because they use a water-intensive type of irrigation known as flood irrigation (or sometimes furrow irrigation), a technique where water is released into trenches that run through crop fields. The long-standing practice is typically the cheapest option and is widely used for alfalfa and cotton, but it can lead to more water loss and evaporation than other irrigation techniques, such as overhead sprinklers or dripping water from plastic tubing.
The satellite image above, captured by the OLI (Operational Land Imager) on Landsat 8, shows desert agriculture in La Paz and Maricopa counties on July 12, 2025. CDL data from the U.S. Department of Agriculture indicates that most of the rectangular fields around Vicksburg and Wenden are used to grow alfalfa, while the fields around Aguila are typically used for fruits and vegetables, such as melons, broccoli, and leafy greens. Some of the alfalfa fields in Butler Valley (upper part of the image) have gone fallow in recent years following the termination of leases due to concerns from the Arizona State Land Department about groundwater pumping.
The new analysis found some evidence that managing groundwater can help keep Arizona aquifers healthier. For instance, the active management areas and irrigation non-expansion areas established as part of the Arizona Groundwater Management Act of 1980 lessened water losses in some areas. The designation of a new active management area in the Willcox Basin in 2025 will likely further slow groundwater losses. “Still, the bottom line is that the losses to groundwater were huge,” Abdelmohsen said. “Lots of attention has gone to low water levels in reservoirs over the years, but the depletion of groundwater far outpaces the surface water losses. This is a big warning flag.”
NASA supports several missions, tools, and datasets relevant to water resource management. Among them is OpenET, a web-based platform that uses satellite data to measure how much water plants and soils release into the atmosphere. The tool can help farmers tailor irrigation schedules to actual water use by plants, optimizing “crop per drop” and reducing waste.
NASA Earth Observatory images by Wanmei Liang, using data from Abdelmohsen, K., et al. (2025), boundary data from Colorado River Basin GIS Open Data Portal, and Landsat data from the U.S. Geological Survey. Oceanic Niño Index chart based on data from the Climate Prediction Center at NOAA. Story by Adam Voiland.
The Trump administration is expected to use a controversial Energy Department report to justify keeping costly fossil-fueled power plants online past their retirement dates. But nine state attorneys general and several clean-energy industry groups are demanding the agency fix the document’s heavily criticized methodology.
The report, which found that the country will face a hundredfold increase in grid blackout risks absent extraordinary federal intervention, was blasted by experts upon its release in July. The DOE’s analysis ignores hundreds of gigawatts of new energy resources likely to come online in the coming years, the vast majority of it solar, batteries, and wind power, and it overstates power plant closures expected over the next five years.
“DOE’s assumptions unreasonably presume that the market, grid operators, and state regulators will take no action in the next five years to address load growth or reliability issues, and that no alternative other than preserving aging coal and gas power plants will ensure grid reliability,” the state attorneys general wrote in their joint request for rehearing filed earlier this month.
The DOE hasn’t yet cited the analysis to support any stay-open orders. But the attorneys general of Arizona, Colorado, Connecticut, Illinois, Maryland, Michigan, Minnesota, New York, and Washington wrote that an April executive order from President Donald Trump and “subsequent statements by DOE make clear that the report will be used to justify Section 202(c) orders going forward.”
Already, before the report was issued, the DOE had used Section 202(c) of the Federal Power Act to order the J.H. Campbell coal plant in Michigan and the Eddystone oil- and gas-burning plant in Pennsylvania to keep running on the eve of their planned closures, at a steep cost to consumers. Forcing more such plants to stay open would drive up electricity costs further and scramble long-running plans from utilities and energy developers to build resources to replace the shuttered facilities.
Doing so would also be illegal, the attorneys general state. “The Report is arbitrary, capricious, contrary to law, and unsupported by substantial evidence in violation of the Administrative Procedure Act and Federal Power Act because it suffers from numerous analytical, mathematical, and empirical flaws.”
The DOE wrote the July report to comply with April’s executive order that seeks to give the agency unilateral authority to force power plants to keep running, even when utilities, state regulators, grid operators, and other experts say it’s safe — and economically prudent — to close them down. The DOE did not respond to Canary Media’s requests for comment.
The report’s flaws were reiterated in a separate rehearing request filed this month by the American Clean Power Association, American Council on Renewable Energy, and Advanced Energy United. The trade groups argue that the DOE’s analysis “fails to take account of (or simply mischaracterizes) major developments that will affect resource adequacy in the next half-decade and beyond,” including “the pace of new resource development, the retirement of existing resources, and the well-established regulatory and market mechanisms that connect these threads.”
In a webinar earlier this month, executives of these trade groups said they also fear that the DOE will use these flawed assumptions to justify ordering fossil-fueled power plants across the country to keep running.
“DOE’s analysis takes a series of outlier assumptions and applies them all in one study as the only future scenario, and the result is that we’re getting predictions of blackouts,” said Caitlin Marquis, managing director at Advanced Energy United. “When it’s applied as directed in the executive order to resource-retention decisions, there will be real-world consequences to those actions.”
Indeed, forcing fossil-fueled plants to stay open could “inflict significant harm on our states,” the attorneys general wrote in their rehearing request. In Colorado and Washington state, coal plants set to close in 2025 could be forced to keep running, despite their closure plans being “thoroughly vetted by state and regional authorities and approved only following an extensive examination of cost considerations and reliability impacts.”
States that are part of regional power markets must still share in the expenses of power plants ordered to stay open, as is the case for the J.H. Campbell plant. Keeping that facility running between late May and the end of June cost $29 million, and the total could surpass $100 million by the expiration of the DOE’s 90-day stay-open order this week. That price tag is being spread across the states that are part of the Midcontinent Independent System Operator’s north and central regions, which include Michigan.
The financial toll could rise dramatically if the DOE uses its authority under Section 202(c) to prevent any fossil-fuel plants nationwide from closing on schedule in the coming years. An analysis from consultancy Grid Strategies found those costs could add up to $3 billion to nearly $6 billion per year by 2028.
This month’s filings aren’t the first challenges to the DOE’s use of Section 202(c) authority.
State regulators and environmental groups filed rehearing requests to the DOE’s stay-open orders in Michigan and Pennsylvania, on the grounds that they violate the agency’s legitimate use of Section 202(c) to deal with near-term emergencies. The DOE did not respond to those requests, which prompted Michigan’s Attorney General Dana Nessel and environmental organizations, including Earthjustice and Sierra Club, to file petitions for review asking the federal D.C. Circuit Court of Appeals to open a case allowing the groups to fight the DOE’s decisions in court. Those petitions for review are pending.
It’s not clear if the agency will respond to these new challenges either, which could prompt lawsuits from the states or the industry. The offices of the nine attorneys general that are seeking a rehearing on the report did not immediately return Canary Media’s requests for comment.
NEW YORK — Just off the chaotic coastline of Lower Manhattan sits Governors Island, a tranquil oasis of tree-lined paths that the city is transforming into a hub for climate change research. Getting there, however, has long meant riding on a diesel-burning ferry that spews soot and planet-warming gases as it zips across the New York Harbor.
A new ferry now provides visitors a much cleaner way to reach the 172-acre island.
Harbor Charger, a hybrid-electric vessel, entered into service last week. The boat is the first of its kind in New York state — and it’s one of only a handful of hybrid-electric ferries to operate nationwide. On Aug. 12, elected officials and other leaders joined the ferry’s inaugural cruise around the harbor, roasting in the late-summer heat on the outside car deck.
“We’re proud to be charting the course for sustainable maritime transportation,” said Clare Newman, president and CEO of the Trust for Governors Island, a nonprofit created by New York City to redevelop the island. Later, Newman smashed a champagne bottle on the stern to christen the new vessel.
The $33 million Harbor Charger operates like an incredibly robust Toyota Prius. The boat’s diesel-fueled generators charge up the 870-kilowatt-hour battery system, allowing the vessel to run partly or fully on electricity during the eight-minute trip to or from the island. The ferry will eventually plug in directly to a shoreside rapid-charging station, using the generators only as emergency backup, but the charging infrastructure hasn’t yet been built.
Harbor Charger, which can fit up to 1,200 people and 30 vehicles, will replace its 69-year-old predecessor named Lt. Samuel S. Coursen. The older ferry guzzles an average of 420 gallons of diesel per day, so switching to the hybrid vessel is expected to save the city over $200,000 per year in fuel costs, according to the Trust for Governors Island.
The new boat will also significantly reduce air pollution and slash carbon dioxide emissions by nearly 600 tons per year when running in hybrid mode. Once it can plug in, the vessel will curb CO2 by an additional 800 tons.
Nationwide, many of the nearly 620 ferries plying waterways rely on decades-old, inefficient diesel engines, making them some of the largest emitters among commercial harbor craft. The vessels also typically operate around densely populated communities, exposing people to health-harming pollutants such as particulate matter and nitrogen oxide emissions.
“Diesel ferries are an important part of our transportation system, but continuing to spew the fumes that diesel leaves and … burn that fuel in the middle of our cities does not make any sense,” New York state Sen. Brian Kavanagh (D) said from the gently humming Harbor Charger. Skyscrapers towered in the distance as helicopters and seaplanes soared noisily overhead.
The newly built Harbor Charger is the second hybrid-electric ferry to launch in the U.S. this summer. In July, Washington State Ferries began running the renovated Wenatchee — a 27-year-old diesel ferry that underwent a $96 million conversion to become a Prius of the seas. The giant ferry can carry nearly 2,500 passengers and over 200 vehicles on a route between Seattle and Bainbridge Island.
Siemens Energy outfitted both ferries with its hybrid technology. The German manufacturer recently equipped a new hybrid-electric ferry in Galveston, Texas, and is in the process of retrofitting another vessel there. It’s also working to deliver two similar vessels to Louisiana’s department of transportation later this year, said Ed Schwarz, the company’s head of marine solutions sales in North America.
“We really think that this is the direction the industry is going,” Schwarz said in an interview as the Harbor Charger cruised past the Statue of Liberty.
For now, the industry will have to chart that course without key federal funding. The GOP megalaw that President Donald Trump signed last month rescinds millions of dollars in unobligated grant money from the 2022 Inflation Reduction Act to help local governments and others slash diesel pollution from ports by modernizing and electrifying equipment.
New York City itself received a $7.5 million federal grant in 2023 to fund the installation of Harbor Charger’s shoreside charging infrastructure, which is currently in the design phase. U.S. Rep. Dan Goldman (D-NY), who helped to secure the grant, lamented the loss of federal subsidies for projects like this one. “It is a very fraught time for our cleantech and our renewable energy,” he said during the launch ceremony.
Still, Goldman added, Harbor Charger “is such a critical example of what the future can be and will be.”
Europe’s largest wind energy company was brought to its knees last week by a market it helped create.
Ørsted, the Danish energy giant that constructed the first wind turbines in U.S. federal waters just five years ago, needs $9.4 billion to complete its two remaining U.S. offshore wind projects and to continue to be financially sound enough to build wind farms elsewhere — likely in places far away from the United States.
During its Aug. 11 earnings call, Ørsted blamed its funding needs on “adverse developments” in the U.S. market, referring to the political risk, red tape, and tax credit changes created in recent months by Trump administration policies. Ørsted’s investor presentation described these MAGA headwinds as “unexpected developments outside our control.”
The announcement follows a series of setbacks for foreign offshore wind developers that were once seen as essential to fulfilling the decarbonization goals set by the U.S. government and many Northeastern states.
In January, the U.K.’s Shell exited the now-defunct Atlantic Shores wind project slated for the waters near New Jersey, absorbing a $996 million loss. In late July, Norway’s Equinor announced a $955 million impairment from unexpected changes and delays to its Empire Wind project, which President Donald Trump tried — and failed — to cancel.
Though intensified by the current administration, the industry’s financial troubles began even before Trump took office. One year ago, Ørsted announced a $575 million impairment due in part to delays on its 704-megawatt Revolution Wind project near Rhode Island. Two years ago, it booked a more than $5 billion impairment from its scrapped Ocean Wind 1 and 2 projects off New Jersey’s coastline.
“‘Come to America and lose a billion dollars’ should be the headline of your article,” said Elizabeth Wilson, a wind energy expert and professor of environmental studies at Dartmouth College, in an interview with Canary Media.
Denmark, which owns half of Ørsted, is backing the new fundraising effort in which the company will issue new shares worth about 45% its total value. It’s a fallback plan resulting from Ørsted’s failure to sell part of its ownership stake in Sunrise Wind, a 924-megawatt wind farm under construction near Long Island, New York. The project is more than one-third of the way built and is slated for completion by the end of 2027, but no one wanted to buy into it at a workable price.
Selling off a stake of Sunrise Wind was always part of the plan; the proceeds were meant to cover a large chunk of its construction. Now that would-be buyers are avoiding Trump’s chaos, Ørsted is left footing the entire bill. The firm’s other active U.S. project, Revolution Wind, is 80% complete and is expected to be fully operational by the second half of 2026, the company announced during the call.
But despite assurances that both Revolution Wind and Sunrise Wind will be finished, even at a steep cost to the firm, Ørsted — according to Wilson — is unlikely to invest in American offshore wind again. Ørsted did not respond to a request for comment by publication time.
“What developers really need is market certainty,” said Wilson, who wasn’t surprised that Ørsted could not find a buyer for Sunrise Wind. Trump’s presidency has brought too much risk, she explained.
Trump issued an executive order on Inauguration Day that froze all offshore wind permitting and leasing pending a federal review. Seemingly safe at the time were eight projects, including Ørsted’s Sunrise Wind and Revolution Wind, that already had all their federal permits in hand. Of those fully permitted projects, the 2.8-gigawatt Atlantic Shores project off the New Jersey coast has since fallen apart. Two more are likely to be mothballed — MarWin near Maryland and New England Wind off the Massachusetts coastline — since they probably won’t qualify for the wind-energy tax credits that Trump’s July megabill sent to an early grave.
Trump did not kickstart the sector’s problems — he simply poured gasoline on the fire.
The financial struggles offshore wind developers faced in 2023 and 2024 were caused not by political headwinds, but instead by inflation, high interest rates, pandemic-related supply chain issues, and the U.S.’s lengthy approval process for new projects compared to Europe or Asia. Beyond Ørsted and Equinor, other foreign developers like BP and Avangrid also canceled or attempted to renegotiate contracts during this time.
By fall 2023, it was already clear that the industry would struggle to meet the Biden administration’s ambitious goal of building 30 gigawatts of offshore wind capacity by 2030 — a target that helped spark the rush of European investment into U.S. wind lease auctions and projects. Analysts at BloombergNEF predicted at the time that just 16.4 GW would be built by the decade’s end.
Soon after Trump took office, Barbara Kates-Garnick, a professor of energy policy at Tufts University, told Canary Media that America would fall short of 5 GW of offshore wind power generation — less than 20% of former President Joe Biden’s original goal. Now, with major European wind developers losing billions and looking for the door, reaching even that figure will be an achievement.
Mounting evidence shows that gas stoves — used in nearly 40% of U.S. homes — pose serious health risks.
Now, Coloradans have a new tool to learn about the dangers of cooking with little blue flames. Gas stoves sold in the state will need a yellow health-warning label under a first-in-the-nation law that went into effect earlier this month.
“It’s fair to warn people, especially if they have health impacts from [poor] air quality, to know what they’re buying in advance,” said state Sen. Cathy Kipp, a Democrat who cosponsored the legislation.
Like other gas-burning appliances and gasoline-burning cars, gas ranges spew noxious compounds such as carbon monoxide and nitrogen oxides. Even off, they emit benzene, a potent carcinogen found in secondhand cigarette smoke; breathing in the fumes from gas ranges increases the risk of cancer, especially in kids. Children in homes with gas stoves are also estimated to be 42% more likely to develop asthma.
“We know that this information has not been reaching the public at the point of sale,” said Kirsten Schatz, public advocate at the nonprofit CoPIRG Foundation.
Since the 1970s, fossil-fuel companies have cited industry-backed research and hired scientists to discount evidence that gas stoves cause harm, according to an investigation by NPR. In 2024, the U.S. gas-stove market was estimated at $3.8 billion. In a 2022 survey of retail stores in 10 states, public advocacy group U.S. PIRG, affiliated with CoPIRG, found that most salespeople said they were unaware of the health risks of gas stoves.
Manufacturers have thrown up a hurdle to the new rules; they’ve asked the federal district court in Colorado to freeze the law’s enforcement. Violators would normally face an up to $20,000 fine, but on Wednesday, the state’s attorney general agreed not to enforce the rules until the court reaches a decision, according to Abe Scarr, energy and utilities program director at PIRG.
Though Colorado is the first state to mandate warning labels, Massachusetts and New York could be next. Last year, proposals in Illinois and California both failed, though the Golden State got close; ultimately, Gov. Gavin Newsom (D) vetoed the bill.
Colorado’s new requirements follow other policies — from building ordinances to performance standards to air-quality regulations — adopted at state and municipal levels to rein in the sale of gas equipment. More than 70 local governments are ensuring gas appliances aren’t installed in most new buildings by requiring new construction to be all-electric. In July, New York became the first state to codify such rules.
Under Colorado’s law, gas-stove warning labels need to bear the phrase, “Understand the air quality implications of having an indoor gas stove.” The stickers will have a URL link or QR code that directs curious consumers to a state webpage. Colorado requires that the site, created and maintained by its Department of Public Health and Environment, provides “credible, evidence-based information on the health impacts of gas-fueled stoves.”
The warnings only need to be displayed on floor models or the website on which they’re being sold, Kipp said. “We made it really simple for manufacturers to comply,” she added, but still, “they just don’t want to do it.”
In a federal lawsuit filed Aug. 5, the Association of Home Appliance Manufacturers alleges that Colorado is compelling its members to endorse a warning label that directs consumers to “non-consensus, scientifically controversial, and factually misleading” information. In doing so, the industry group continues, the state is violating its members’ First Amendment rights “to be free from … unconstitutional compelled speech.”
“The lawsuit is frivolous,” Kipp said. “It’s well within the authority of our Colorado legislature to pass laws that implement consumer protections.”
While appliance makers are portraying the science as unsettled, “that’s not true,” Kipp said.
Several nonpartisan nonprofit organizations recognize the large body of peer-reviewed research on gas-stove pollution and have voiced support for warning labels, Schatz said, including the American Public Health Association, American Lung Association, American Medical Association, and American Thoracic Society.
The parties to the lawsuit are asking for a hearing to be scheduled in early November, Scarr said. They’ve also agreed to a deposition — sworn testimony outside the courtroom — of any witness whom appliance manufacturers rely on to make their case.
“This litigation is set to become a battle of the experts regarding the health impacts of gas stoves,” Scarr said. “Given the science, we’re confident the state can win.”
It’s no Route 66.
But the roughly 80-mile stretch of U.S. Route 50 that snakes across Virginia from the nation’s capital to the West Virginia border is rich in American history and culture. The mostly two-lane, winding mountain road features vineyards, battlefields, high-end resorts, and more. And just like the iconic route from Chicago to California, U.S. 50 is increasingly making way for the future of American road trips: electric vehicles.
The tiny town of Middleburg, Virginia, is a case in point: Officials there installed a fast charger nearly 18 months ago to serve EV drivers in the wealthy, bucolic region just 45 miles west of Washington, D.C.
Named for its equidistance between Alexandria and Winchester, Middleburg has long been at the center of foxhunting and steeplechases. These days, the town of less than 1,000 people is also surrounded by wineries and boasts a film festival, a 168-room five-star resort, and a Christmas parade replete with horses and hound dogs.
“Since colonial times it has been a stopping place, and it’s continued to be a place where people come from all over the world, as well as from the greater D.C. area,” said Lynne Kaye, chair of Middleburg’s sustainability committee.
As electric vehicles have become more prevalent, so too has “EV tourism”: towns off the beaten path seeking to lure travelers with charging infrastructure. While visitors juice up — often for free at relatively slow Level 2 chargers – they might browse local art galleries and shops, grab some dinner, or visit another attraction they may have otherwise missed.
But Middleburg is part of Loudoun County, the nation’s richest, with some of the most robust EV adoption numbers in Virginia. The town has ample attractions, so the idea to install a charger was less about drawing in new visitors than it was about keeping those already passing through happy.
“When we walked around town, we were noticing a bunch of EVs,” said Kaye. “We wanted to make sure that we didn’t accidentally become unappealing to people who were driving them.”
Reducing the town’s climate footprint was also a consideration. Kaye and others reason that cars driven by visitors and residents are the leading contributor to its planet-warming emissions.
“We only have 673 residents. We can only create so much carbon,” she said. “But when you have 20,000 people come to an event, that’s a lot of carbon all at once.”
When town leaders were in the planning stages of adding their charger, they also noticed a lack of devices in the region that could fill up a car battery in an hour or less. “Not everybody wants to spend however many hours getting their EV charged,” Kaye said.
For all these reasons, the decision to install a fast charger in the heart of town was an easy one. But bringing that choice to fruition wasn’t as simple.
An expansive bay with 10 or more chargers, an increasingly common feature at gas stations, wasn’t logistically feasible in the tiny Town Hall parking lot. And most charging companies Middleburg approached wanted to install no fewer than six fast chargers.
“Getting this huge bank of chargers didn’t fit a historic town,” Kaye said. “There wasn’t really space for it, and we weren’t sure that we were going to get enough traffic to use the chargers effectively.”
XCharge North America came to the rescue. The charger manufacturer was “willing to work with us and come up with a way to have the one charger,” Kaye said. “And it’s been a success.”
Initially called Current Electric, the startup had recently been acquired by a European equipment maker. Its business proposition: making fast chargers cheaper by using a 208-volt system rather than the global standard of 480V.
While Middleburg had already wired its new Town Hall to accommodate the industry standard, XCharge still leapt at the opportunity to showcase its hardware, said company cofounder Alex Urist.
“This was very much a way for us to get early applications in the U.S.,” said Urist, who lives in New York City. “The proximity to D.C. is great as well. Selfishly, I go to D.C. to visit the in-laws frequently enough, so I can always check in on the charger. I like to take them over there and show off that I actually have a job,” he quipped.
Typical direct-current fast-charging units can run between $30,000 and $120,000. In Middleburg’s case, XCharge provided its hardware for free while the town covered the installation. The two entities share the revenue from charging sessions, and the company can learn from how the fast charger performs as it explores other markets.
“It’s not really a charger on a high-throughput area,” Urist said. “But what is interesting about it is, it’s kind of dead in the middle of Virginia wine country. It’s along this rural corridor where the perceptive availability of chargers is very important.”
Between March 2024, when the charger was installed, and February 2025, 181 sessions were logged. Since then, there’s been an uptake, with 268 sessions logged as of May 2025, according to XCharge.
“It’s a really interesting use case for us to see. How does it help with the local economy? Are they going to also see any ancillary impacts of it beyond just the revenue coming in?” Urist said.
Indeed, that’s one of the expectations behind an initiative called Virginia Green Travel, which helps the state’s towns, especially those with carbon-reduction goals, attract environmentally minded tourists, said Alleyn Harned, executive director of Virginia Clean Cities.
“Electric vehicle chargers have been part of green tourism in Virginia,” said Harned, whose group is among the backers of the Green Travel initiative.
Virginia Clean Cities, a U.S. Department of Energy-funded entity that’s based at James Madison University in Harrisonburg, is what brought Middleburg and XCharge together. The town’s success with its fast charger was a bright spot for the organization after President Donald Trump stalled the rollout of $5 billion for charging infrastructure launched under his predecessor.
“This is a positive story in getting something done,” Harned said, “because this stuff really improves our economy.”
As the Trump administration moves toward releasing National Electric Vehicle Infrastructure funds after losses in court, more towns across Virginia may have the chance to follow Middleburg’s lead.
Kaye says they should know that fast charging is possible for them. “I think it’s important for other small towns to realize that there is an opportunity, if they want to take it,” she said.
For decades, electrical engineers have dreamed of a device that can seamlessly connect solar panels, battery systems, and on-site generators to high-powered equipment like EV chargers or data center servers, without loads of expensive hardware to make it all work together.
Now, these devices, called solid-state transformers, are actually starting to hit the market — and they couldn’t be coming at a more opportune time.
That’s because the technology could be key to dealing with the torrent of power demand from data centers, factories, and electric-vehicle charging hubs that threatens to overwhelm the grid and cause utilities to burn more planet-warming fossil fuels.
Right now, these large electricity customers are clamoring for more power than the U.S. grid can easily supply. In theory, this problem could be solved by allowing them to install their own solar arrays, batteries, and generators on site — ideally as a microgrid — but that seemingly simple solution is actually complicated and costly to execute.
Every solar array, battery, fuel cell, generator, or other source of on-site power requires multiple pieces of equipment — electrical protection gear, isolation transformers, step-up and step-down transformers, power converters — to safely turn direct current into alternating current or vice versa, and to raise or lower voltages to match the needs of different loads within a building.
Solid-state transformers can do all that from a single device, controlling electricity as nimbly as routers control the flow of data. That’s particularly valuable when it comes to managing equipment with high power needs, like EV chargers, or with extremely sensitive requirements for power quality, like the server racks populating data centers.
So says Haroon Inam, CEO and cofounder of DG Matrix, one of a handful of companies starting to get solid-state transformers into real-world applications. DG Matrix raised $20 million in March and is building a factory in North Carolina, set to open late this year, that will be capable of producing up to 1,000 units annually, he said.
“We’re hitting the massive underserved commercial and industrial microgrid market,” he said. “People haven’t done it because it costs so damn much to build individual snowflake microgrids.”
DG Matrix is not the only firm working on this. Heron Power, a startup founded by Tesla alum Drew Baglino, has raised $43 million in funding with the goal of building its first solid-state transformers in 2027. Amperesand raised $12.5 million last year to continue developing solid-state transformers being tested on Singapore’s power grid.
Major electronics companies are interested. Electrical equipment giant Eaton last month agreed to acquire Resilient Power Systems, which raised $5 million in 2021 to build and deploy its power-conversion devices for EV charging hubs and other energy-hungry settings. Eaton will spend $55 million on the company on closing; additional payments based on Resilient Power’s financial and technological performance in the coming years could total another $95 million.
“People have been working at this technology for well over a decade,” said Aidan Graham, senior vice president and general manager of Eaton’s critical power solutions business. But now, following several key engineering advances, the technology may finally be ready for primetime — and utilities and others are starting to test it out.
Eaton has been working on solid-state transformers for years. The company isn’t saying how it intends to scale up manufacturing and deployment of Resilient Power’s technology. But “there are a couple of branches we’re chasing,” Graham said, including EV charging and integrating batteries into data centers and other critical environments, “where people‘s lives are on the line, or a lot of money is on the line, if the power goes out for even a fraction of a second.”
Michael Wood III, DG Matrix’s chief of staff, said the company is testing its devices with companies including electrical-equipment manufacturing giant ABB, North Carolina-based utility Duke Energy, and PowerSecure, a major microgrid and data-center power system developer owned by utility Southern Co.
“The best way to get the next gigawatt of energy is to build distributed systems,” Wood said. “Today, you need all of this gear to make those projects work. DG Matrix eliminates all that balance of systems and boils it down to a single system.”
Using a DG Matrix solid-state transformer can cost half as much as using the standard mix of multiple technologies to connect the components of a typical on-site microgrid, Inam said. It also makes it a lot simpler to quickly mix and match devices or to change up the configuration of systems at data centers, EV charging hubs, and other potential microgrid sites.
So if solid-state transformers are such a useful technology, why are they just now getting into the field?
There are good reasons why it’s taken so long, said Vlatko Vlatkovic, a veteran of General Electric’s industrial electrification business and a partner at DG Matrix investor Clean Energy Ventures, who joined the startup’s board of directors this year.
Much of the power grid relies on electromechanical devices that operate in relatively simple ways that haven’t changed much in a century. Despite recent advances that have enabled things like solar inverters or electric-vehicle drivetrains, the same kind of semiconductors that make modern computing possible have yet to be applied widely to the power grid.
“It’s always been a big challenge to move that industry towards using more power electronics,” Vlatkovic said, particularly at the higher voltages of electricity on the grid. Until relatively recently, the underlying technology “wasn’t big enough, wasn’t reliable enough. There were technical issues.”
Similar challenges have dogged solid-state transformers in higher-voltage industrial applications, said Neal Dikeman, a partner at Resilient Power investor Energy Transition Ventures. Consistent advances in silicon carbide semiconductors have helped, as have strides in the computing ability required to make them effective at power conversion, he said. “But that doesn’t make it easy.”
Inam, who served as chief technology officer at grid power-controls provider Smart Wires before joining DG Matrix in 2023, noted several key challenges that the startup had to solve to get to this point.
Dissipating the heat created by converting alternating current and direct current at high voltages is tricky, for one. So is dealing with “electromagnetic noise,” or interference caused by that same high-frequency electrical switching. “If you don’t understand how to critically mitigate that noise, it gets into everything. It causes overheating, blow-ups, and misperformance,” Inam said.
Solving those challenges has its rewards, however. “We’re at the point where the technology is mature enough and good enough so that we can introduce reliable devices,” Vlatkovic said.
The timing couldn’t be better.
“Everything’s being electrified, from cars to industry to housing,” Vlatkovic said. “If you look at the projections for what the grid needs to deliver over the next 10 to 20 years, at a minimum we have to double the capacity of the grid. Some projections say we need to triple what we have.”
Meeting power demand from data centers is a particularly big opportunity, Inam said.
Tech giants’ AI ambitions are taxing the grid capacity of utilities in data center hot spots like Virginia, Georgia, and Texas. That’s led data center developers to explore ways to reduce the stress they put on grids — including the potential for generators and batteries built nearby or on site.
“The three big problems are speed to power — customers can’t get power fast enough — cost of power, and the ability to aggregate multiple resources to reach flexibility,” Inam said. “We talk to enterprise customers with hundreds or thousands of sites. Their biggest challenge is having to design every single one from scratch. They’re looking for a turnkey solution to the challenge of not having to deploy one, but having to deploy 1,000.”
Solid-state transformers can help meet those needs, Vlatkovic said. “You go from complex installations and multiple companies to one company doing everything.”
Packing more capabilities into a smaller “power-dense” package also saves valuable space in tight environments like data centers and EV charging sites, Eaton’s Graham said. And solid-state transformers can be made en masse in factories, reducing the cost and time spent on electrical labor on job sites. “You’ve pulled that back into a controlled manufacturing environment,” Graham said.
Plus, having a single device that can perform multiple tasks simplifies engineering needs, Dikeman said.
“If you’re using off-the-shelf components and designing a complex system, the mismatching of” different devices that don’t perfectly match the needs of the system “drives up costs and drives down efficiency,” he said. “You can get around that by building custom stuff — but that’s more expensive and more risky. When you get to solar and storage and data centers and people who need to go fast and need things that are reliable and cheap, all of that breaks down.”
All of these potential benefits have led PowerSecure, the microgrid developer, to launch pilots of at least two solid-state transformer technologies, including its tests with DG Matrix, said Joaquin Aguerre, the company’s director of strategic portfolio development. “We’re trying to be in front on this technology.”
PowerSecure has designed and installed more than 2.4 gigawatts of microgrid capacity for customers ranging from big-box retailers and hospitals to utilities and data centers. It’s particularly interested in solid-state transformers to integrate power-efficient “hybrid microgrids” that combine “solar, energy storage, natural-gas generators, fuel cells, EV charging, you name it,” Aguerre said.
“There is starting to be a real market need,” he said. At the same time, “the majority of these companies are still in the early stages. … The next logical step is doing proper pilot programs, to see real customer use cases at a smaller scale” and to test the durability and reliability of the technologies in question.
After all, whatever their drawbacks compared to cutting-edge power electronics, traditional transformers “don’t fail that often,” Aguerre pointed out. “Everyone’s going to expect the same reliability for whatever solid-state transformer they’re looking at.”
A clarification was made on Aug. 19, 2025: This story originally stated that Eaton will pay $55 million to acquire Resilient Power. The piece has been updated to clarify that the deal also includes additional payments contingent on Resilient Power’s performance over the next couple of years.
The Trump administration has set up yet another roadblock for wind and solar power in the U.S. — one that will make it harder for clean-energy developers to qualify for federal tax credits before they expire next summer.
Treasury Department guidance released Friday puts new restrictions on the “safe-harboring” rules that have for decades guided whether solar and wind developers are considered to have “commenced construction,” a key milestone required to secure tax-credit eligibility.
The rules, which will go into effect on September 2, are likely to further slow the rollout of wind and solar power — two of the fastest-growing sources of energy in the country, both of which have been under siege by President Donald Trump since January.
Clean-energy industry advocates attacked the guidance as an improper use of executive authority that will make it harder for the U.S. to meet growing electricity demand and will further drive up electricity bills. But industry analysts noted that the new rules, though restrictive, could have turned out even worse.
Under the big new tax and spending law passed by Republicans last month, solar and wind projects must commence construction by early July 2026 to access tax credits.
For projects larger than 1.5 megawatts in size, Treasury’s new guidance eliminates one way for developers to prove they’ve started work: spending at least 5% of the total cost of the project by the deadline. That new restriction won’t apply to residential and commercial solar installations, so companies in that space such as Sunrun, Freedom Forever, SolarEdge, and Enphase, saw their share prices rise on Friday.
But it will apply to most other clean-energy developments, from community solar farms to massive utility-scale solar and wind projects. Starting in just a few weeks, projects larger than 1.5 megawatts will have only one option for proving they’re under construction: They must demonstrate that they are undertaking “physical work of a significant nature” on a continuous basis.
The test is not new, and project developers have relied on it in the past. But it is less straightforward than the 5% safe-harbor rules, creating uncertainty that could make it harder or more expensive for developers to lock down financing for a project.
“Unless you’re pretty far along, you’re not going to go build some roads and install racking overnight,”said Andy Moon, CEO and cofounder of Reunion Infrastructure, a company that manages clean-energy tax-credit transfers. “It’s not so easy to change your plans and accelerate something that fast.”
Clean-energy industry groups declined to speculate about how the changes would impact the hundreds of gigawatts of solar and wind projects now under development across the country. But these industries are already reeling under the much-shortened timeline for securing tax credits under last month’s One Big Beautiful Bill Act; previously, under the Inflation Reduction Act, developers had until at least 2032 to commence construction and thereby secure tax credits. Analysts have said the drastically shortened tax-credit window will cut clean-energy growth by more than half over the coming decade.
That’s a problem for a country facing rising demand for power for data centers, factories, and broader economic growth. Solar, batteries, and wind made up 96% of new capacity added to U.S. grids last year and will remain the primary option for new power in the next few years, given that there are five- to seven-year wait times for new gas turbines and even longer construction timelines for nuclear and geothermal power plants.
“This is yet another act of energy subtraction from the Trump administration that will further delay the buildout of affordable, reliable power,” Abigail Ross Hopper, president and CEO of the Solar Energy Industries Association, said in a Friday statement.
Since Trump signed the megalaw in July, his administration has taken a host of anti-wind and anti-solar actions, including subjecting projects to byzantine Interior Department reviews, setting “capacity density” restrictions for projects on federal lands, and potentially halting already permitted wind farms both onshore and offshore.
Shortly after the law passed in July, Trump ordered the Treasury Department to review the safe-harbor rules. The directive came after pressure from the ultraconservative Freedom Caucus members in the House of Representatives, who were upset that the law preserved tax credits for wind and solar projects at all. In that same executive order, Trump also told Treasury to develop rules governing “foreign entity of concern” restrictions; those rules, which are still in development, could be even more disruptive to the industry.
“The Treasury Department’s decision to accelerate the phaseout of clean energy tax credits undermines the integrity of our energy grid and our legislative process,” Jason Grumet, CEO of the American Clean Power Association trade group, said in a Friday statement. “Congress explicitly chose to provide energy companies with one year to phase out tax credits to keep energy prices low while meeting growing power demand.”
Friday’s guidance came despite entreaties from Senate Republicans Chuck Grassley of Iowa and John Curtis of Utah, who negotiated the tax-credit amendment to the final bill. Though both senators voted for the One Big Beautiful Bill Act, which cleared the Senate by just one vote, earlier this month they placed holds on three of Trump’s Treasury Department nominees in an attempt to force the administration to negotiate a less harmful change to the safe-harbor rules.
Grassley’s office did not immediately respond to a request for comment on Friday afternoon.
“Frankly, I think the intervention worked,” said Pavel Molchanov, a Raymond James analyst covering cleantech companies. “Treasury could have gone really far in the direction of making life difficult.”
Molchanov cited rules left unchanged in Friday’s guidance, such as the four-year window for projects that commence construction by July 2026 to complete their work to secure their tax-credit eligibility. “Imagine if they had said, ‘Oh, did we say four years? It’s actually two.’”
Similarly, the “physical work” requirements listed in Friday’s guidance are not outside the bounds of what a large-scale solar or wind project developer can reasonably take on over the next year, he said. Exemptions for extreme weather, permitting delays, and other obstacles to continuing work should shield developers from risks of being declared out of compliance with those requirements, he said.
“The good news is that it’s still almost 11 months until July 2026, so developers have plenty of room to make adjustments before starting construction,” Molchanov said. “From my perspective, it’s actually better than expected. But maybe my expectations were just so low to begin with.”
Jeff Cramer, CEO of the Coalition for Community Solar Access, a trade group that represents companies building smaller-scale solar and battery projects, decried the new guidance as a violation of the deal Republicans made in crafting the megalaw. But he also said that simply knowing the rules of the game is a help.
“I think the only good news is that there may now be less uncertainty,” he said. “The onus is now on the states to ensure that any projects that can meet that July 2026 deadline can do that.”
While China leads the world in both the production and adoption of clean energy tech like solar and EVs, the country has been slower to tackle decarbonizing heavy industry. That is starting to change.
In July, the Chinese state-owned steelmaker HBIS Group agreed to sell more than 10,000 metric tons of green steel to a buyer in Italy. The agreement set a deadline for delivery by the end of August. That same week, Australian Prime Minister Anthony Albanese visited China and pledged to work together to build out the green steel industry.
Meanwhile, in the U.S., steel producers are backing away from earlier commitments to produce green steel. Just before President Donald Trump’s inauguration in January, the Swedish steelmaker SSAB pulled out of negotiations for $500 million in federal funding to back a project to make iron with green hydrogen. In June, Cleveland-Cliffs abandoned its own green steel effort in Middletown, Ohio, after the Trump administration pressed the steelmaker to use a $500 million Biden-era grant to ramp up coal-fired iron production. Nippon Steel pledged to modernize U.S. Steel after securing Trump’s support for a $15 billion acquisition of its American rival in June, but the Japanese giant’s reputation as a “coal company that also makes steel” suggests the merger could extend the life of blast furnaces in Indiana and Pennsylvania.
“A lot of the rhetoric around competitiveness with China makes it seem like we think we must not fall behind. Stories like this make clear we already are behind,” said Marcela Mulholland, a former official at the Department of Energy’s Office of Clean Energy Demonstrations who now leads advocacy at the nonpartisan climate group Clean Tomorrow. “It is happening. The green steel example is just one of many.”
China produces a staggering amount of steel each year — more than 1 billion metric tons. About 90% is made with a two-stop process that relies on coal. First, iron is smelted from ore in a coal-fired blast furnace. Then the iron is transformed into steel in a basic oxygen furnace. About 10% of the country’s steel is made with an electric arc furnace, a process that – if powered by green electricity – is much cleaner, but depends on a steady supply of scrap metal as a feedstock. (The U.S. has a decided advantage with this particular technology since most of the steel that the nation produces uses scrap metal in EAFs.)
China has yet to widely implement the technology known as direct reduction of iron, or DRI, which typically relies on natural gas to produce iron but which can also use hydrogen. The country’s supplies of the former fuel are limited, spurring it to experiment with ways to conduct DRI using the latter.
China has many small-scale pilot projects manufacturing steel with hydrogen, but most involve minimal volumes of the material. For example, the country’s No. 2 steelmaker, Angang Steel Co., is producing just 10,000 metric tons of iron from green-hydrogen-fueled DRI per year. HBIS is shipping that volume of steel to Italy this month alone. Only HBIS and another major producer, China Baowu Steel Group, are producing green steel with hydrogen in significant quantities, according to research published last month by the Helsinki-based nonprofit Centre for Research on Energy and Clean Air.
How clean the hydrogen is that China uses to make steel is a complicated question.
Hydrogen – the smallest molecule – is already widely used in industrial processes and offers a cleaner alternative to fossil fuels since it produces no carbon dioxide when burned. Yet the vast majority of the global supply of hydrogen is made through methods that use fossil fuels and generate planet-heating emissions. When made with electrolyzers powered by renewable energy, hydrogen produces almost no emissions at all, but production of this form – green hydrogen – is nascent and comes at a high premium. (DRI using green hydrogen paired with EAFs is the highest – but nearly nonexistent – standard for producing green steel.)
Headquartered in Hebei province, HBIS started experimenting with lower-carbon steel in part by using hydrogen captured from its coking plants, where coal is roasted at more than 1,110 degrees Fahrenheit to cook off contaminants and produce an industrial-grade fuel. Roughly 60% of the gas emitted during the process is hydrogen.
It’s unclear how much of the steel HBIS is shipping to Italy is made with iron that employs hydrogen produced from industrial waste processes rather than the green stuff made from electricity generated by nearby renewables. HBIS did not respond to a request for comment.
But David Fishman, a principal at the Shanghai-based energy consultancy The Lantau Group, said “there are quite a few” sources of hydrogen made with renewable power near HBIS’s facility in northern China. He noted that HBIS has a strategic partnership with the China National Petroleum Corp., which launched its first large-scale demonstration project to make green hydrogen in 2023.
The export deal may be a sign of China raising its ambitions for cleaner steel. The national government had set a target for 15% of steel coming from EAFs by the end of this year. But that steelmaking capacity has remained at 10% for more than a decade.
Part of the problem is that provincial steel targets are at odds with the policies set in Beijing. Though the national government opened China to imported scrap steel that could be used in EAFs, imports halved in 2024 compared to the previous year, according to the Centre for Research on Energy and Clean Air analysis. Ten provinces, meanwhile, ramped up production of coal-made steel in the first half of this year, bringing down prices and disincentivizing more costly green investments, said Xinyi Shen, the China team lead for the Finnish nonprofit, who authored the report.
But if China can deepen its stockpiles of scrap steel, the country could more quickly build out a lower-carbon steel industry using EAFs while it waits to improve technology on green hydrogen that can bring down costs of fully decarbonized steel, Shen said.
“This is a more promising way to produce low-carbon steel,” she said. “For hydrogen steelmaking, it depends on the progress of green power.”
The bottleneck, she said, is “always the feedstock for DRI.”
But two recent policy changes on renewable power could incentivize Chinese companies to use more of the nation’s vast solar and wind resources to generate green hydrogen.
The first, called the 430 policy, took effect on May 1 and requires that new distributed solar arrays — like those on buildings’ rooftops — first power the facility they are sited on before selling any surplus electricity onto the grid. The second, dubbed the 531 policy, eliminates the guaranteed “feed-in tariffs” that renewables projects long benefited from in China, and requires new solar and wind farms to sell electricity on the spot market.
Whether policies that direct renewable power away from the grid benefit hydrogen producers by making that power more available to them depends on the provincial-level strategies for the fuel, which vary, Shen said. But the emergence of overseas buyers willing to pay more for steel made with green hydrogen could drive the market, she said.
Starting next year, the European Union, of which Italy is a founding member, is set to fully implement its Carbon Border Adjustment Mechanism. The carbon tariff essentially levies an extra cost on imports made with more planet-heating pollution. That means China’s coal-fired steel is about to become less competitive. While China could ramp up scrap-based EAF steel, Shen said the quality of that product tends to be very low, making it unappealing for export. The Italy deal, according to the Boston Consulting Group, shows the levies are creating a market for truly green material.
“This development holds significant implications,” Nicole Voigt, the Boston Consulting Group’s global lead of metals, told Canary Media. “China’s commitment clearly highlights its intent to seize commercial opportunities in the green steel market, especially in Europe.”
It’ll take time for the cost to come down. But China “overall has a long-term direction for carbon neutrality,” Shen said. “This gives companies and investors confidence and certainty to invest into newer technologies.”
Under the previous administration, the U.S. pumped billions of dollars into green hydrogen and clean industrial projects, and made tax credits for renewables available into the 2030s. Even then, America hardly employed all the policy mechanisms at play in China. The federal clean-industry program where Mulholland worked supported a few dozen projects, almost all of which saw their funding yanked away by the Trump administration this spring. Last year alone, China had nearly twice the number of low-carbon industrial demonstration projects. This year, Beijing funded a second set of more than 100 new projects.
“The investment into these new technologies will need a long, stable policy environment,” Shen said. “Long-term, the political goal is there here in China.”
A correction was made on Aug. 18, 2025: A previous version of this story incorrectly stated that basic oxygen furnaces directly burn coal.
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