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California’s premier “virtual power plant” program is already reducing the state’s reliance on polluting, costly fossil-fueled power plants. And that’s just the start of what the scattered network of solar and batteries could do to stymie rising utility costs — if the state Legislature can stave off funding cuts to the program, that is.
So finds a new analysis from consultancy The Brattle Group on the potential of the statewide Demand Side Grid Support (DSGS) program to help California’s stressed-out grid keep up with growing electricity demand. The program pays households and businesses that already own solar panels and batteries to send their stored-up clean power back to the grid during times of peak demand, like hot summer evenings.
Continuing the program’s payments to those customers to make their stored energy available could save all California utility customers anywhere from $28 million to $206 million over the next four years, the report found.
The findings come as state lawmakers attempt to rescue the DSGS program from a new round of funding cuts. Last year, California lawmakers slashed DSGS spending to deal with an unexpected budget shortfall. The situation is still troubled this year, and Democratic Gov. Gavin Newsom has proposed defunding the program further, leaving it little money to pay participants beyond this year.
But the program could regain its financial footing if newly introduced legislation becomes law.
This week, California Assemblymember Jacqui Irwin, a Democrat, released draft legislation that would allocate money to DSGS from the state’s much-contested Greenhouse Gas Reduction Fund, which is supported by payments from polluting companies. That draft legislation calls for depositing 5% of revenue collected by electric utilities for that fund into a new account to finance DSGS from 2026 to 2034. Lawmakers don’t have much time to move the proposal forward, with the state’s legislative session ending Sept. 12.
Saving the program would be a win for reducing the state’s sky-high utility costs, according to Ryan Hledik, a principal at Brattle and coauthor of the report. “It’s cheaper to pay customers to provide grid resources from technology they’ve already adopted than it is to go invest capital in new stuff,” he said, including the fossil-fueled generators now used to meet peak grid needs.
California has already committed billions of dollars on emergency backup generators and on keeping aging fossil-gas-fired power plants open past their planned closure dates, he noted. The high end of the savings DSGS could provide is based on the assumption that it “would be a substitute for spending money on more expensive emergency resources,” he said.
At the same time, DSGS could also bring down the “resource adequacy” payments shelled out by California utilities, community choice aggregators, and other power providers to secure enough grid resources to meet peak demand in future years. Those costs have been rising in California, though not as drastically as they have in other parts of the country.
Since its launch in 2023, the battery program Brattle analyzed, which is one of the four options for customers to participate in DSGS, has grown to a collective 700 megawatts of capacity. The report forecasts the program could nearly double its current capacity to reach 1.3 gigawatts by 2028, covering roughly half the total residential distributed-battery capacity expected to be online in the state by then.
That won’t happen without state funding for the program, however — and though some state lawmakers are attempting to save DSGS’s funding, it remains unclear if the money will be there for future years.
If Irwin’s proposed provision becomes law, it would supply roughly $70 million to $90 million per year to DSGS over the next five years, said Brad Heavner, executive director of the California Solar and Storage Association. DSGS needs at least $75 million this year to operate in 2026, according to a letter sent to California lawmakers on Tuesday by 35 companies, trade groups, and advocacy organizations active in solar, batteries, on-site generators, and demand response, including Heavner’s group.
The amount of funding dedicated under the proposed legislation “won’t be enough for all the program activity we expect — but it will be enough to have a core program,” he said.
DSGS’s cost-effectiveness, demonstrated by the Brattle analysis, should give lawmakers confidence that the money isn’t being wasted, Heavner said. “It’s great that the Brattle study finds there’s a two-for-one benefit — every dollar spent here saves two dollars” for utility customers across the state, he said.
Brattle’s research was funded by Sunrun and Tesla, two companies with longtime programs that sign up customers to make their excess battery capacity available for grid services. Both firms benefit from initiatives that boost the value of the rooftop solar and battery systems they sell to households in California and beyond.
But the study also matches broader research on how virtual power plants can reduce blackout risks and electricity price spikes on U.S. grids. VPPs are collections of homes and businesses with smart thermostats, grid-responsive EV chargers, water heaters, and other appliances that can reduce how much power they’re using, as well as rooftop solar-charged batteries or generators that can push power back to the grid as needed.
Under the Biden administration, the U.S. Department of Energy found that the hundreds of billions of dollars that consumers spend on EVs, rooftop solar systems, batteries, smart thermostats, and other appliances could provide 80 to 160 gigawatts of VPP capacity by 2030, enough to meet 10% to 20% of U.S. peak grid needs and save about $10 billion in annual utility costs. (The Trump administration has removed this DOE report from the internet, but archived versions are available.)
VPPs also pass the eye test: They’ve helped avoid blackouts in Puerto Rico, New England, and California this summer. States including Colorado and Virginia have passed laws or created regulations requiring utilities to expand VPPs.
DSGS, for its part, has “scaled in a way that folks can no longer poke holes in its reliability,” said Lauren Nevitt, Sunrun’s senior director of public policy. Sunrun has dispatched hundreds of megawatts from its customers’ batteries in California so far this summer, all during hours of the evening when wholesale electricity prices spike above $200 per megawatt-hour.
In a two-hour experiment last month, Sunrun and Tesla dispatched 535 megawatts of battery power to the grid in what utility Pacific Gas & Electric called “the largest test of its kind ever done in California — and maybe the world.”
Lining up a steady source of funding for years to come would give these participating companies confidence that their investments in DSGS won’t be left stranded by future budget cuts, Heavner said — and encourage even more investment going forward.
Pressure to curb energy costs is particularly acute in California, where residential customers of the state’s three major utilities now pay roughly twice the national average for their power and where rates rose 47% from 2019 to 2023.
It is also among the best-positioned states to take advantage of VPPs to rein in those costs. California leads the country in rooftop solar, backup battery, and EV adoption, and a 2024 Brattle analysis found that VPPs could provide more than 15% of the state’s peak grid demand by 2035, delivering $550 million in annual utility customer savings.
DSGS is only one of a number of VPP options available in California. But advocates say it’s by far the most successful in a state that’s seen mixed progress on VPPs to date. In the past five years, stop-and-start policies from the California Public Utilities Commission have reduced overall capacity from demand-response programs that pay utility customers to turn down their electricity use to relieve grid stress.
DSGS, which is run by the California Energy Commission, has grown rapidly due to a combination of factors, said Edson Perez, who leads California legislative and political engagement for clean-energy trade group Advanced Energy United. It’s available to residents across the state, rather than being limited to individual utility territories and programs. It also has relatively simple enrollment and participation rules compared to many other programs, he said.
It can be tricky to quantify the costs and benefits of these kinds of programs compared to traditional utility investments in power plants or large-scale solar and battery systems. But Brattle’s new report is the “first analysis of what its value is out in the field,” he said, and the results show “it’s very cost-effective.”
Solar-charged batteries are also much less polluting than the state’s other emergency grid-relief resources, he said. DSGS is one of a set of emergency programs launched after California experienced rolling blackouts during summer heat waves in 2020 and more heat-wave-driven grid emergencies in 2022.
But most of the billions of dollars in emergency funding have gone to fossil-fueled generators. California had spent about $443 million on state-managed generators that burn fossil gas or diesel fuel as of December 2024, and has committed about $1.2 billion to keep fossil-gas-fired “peaker” plants in Southern California open until 2026, well past their scheduled 2020 closure date.
“We’re in a statewide affordability crisis,” Perez said. “Leveraging existing resources out there drives down costs for everyone.”
The Trump administration has extended its order to keep a Michigan coal-fired power plant running until November, well past its planned closure in the spring. It’s the latest move in a push to force dirty, expensive power plants to keep operating, which experts warn could saddle Americans with billions of dollars in unnecessary electricity costs.
Just days before the J.H. Campbell plant was set to shutter in May, the administration ordered it to stay open for 90 days — an unprecedented federal intervention in state-regulated utility operations. That order has already cost Midwest utility customers millions, and Michigan’s top utility regulator estimates that keeping the aging plant open longer could burden consumers with more than $100 million in unnecessary costs.
The Department of Energy’s Wednesday extension adds weight to concerns from states, environmental advocates, and clean-energy industry groups that the administration intends to wield emergency powers meant to address true threats to grid reliability to prevent any fossil-fueled power plant from closing nationwide. Doing so would cost consumers between $3 billion and nearly $6 billion per year by the end of President Donald Trump’s term, per an August report from consultancy Grid Strategies.
“The order purports to override the considered judgment and careful work of many federal, state, and regional bodies who actually have authority to keep the lights on,” Michael Lenoff, senior attorney for nonprofit Earthjustice, said in a Thursday statement.
Lenoff is leading litigation against the DOE’s initial order from May. Michigan’s Attorney General Dana Nessel has also challenged that order in court, after the agency failed to respond to requests from environmental groups and eight state utility commissions seeking a rehearing of the decision.
To keep fossil-fueled plants running, the Trump administration is taking advantage of Section 202(c) of the Federal Power Act, which gives the DOE the authority to take temporary action to address nearterm grid-reliability emergencies. But many groups say there is no such crisis: Wednesday’s order from Energy Secretary Chris Wright, a former gas industry executive and well-known denier of the climate-change crisis, “points to no evidence of an imminent emergency requiring Campbell to keep racking up the bills paid by customers in Michigan and nearby states,” Lenoff said.
“Despite already forcing the plant to run for 90 days, [Wright] points to not a single instance where the plant was needed to keep the lights on,” Lenoff said.
Consumers Energy, the utility that owns J.H. Campbell, reported in late July that it cost $29 million to operate the plant in the first five weeks of the DOE’s stay-open order.
“The coal-fired J.H. Campbell plant has reached the end of its life. Michigan cannot afford to let political interference prolong its operation,” Justin Carpenter, policy director for the Michigan Energy Innovation Business Council, said in a Thursday statement. “So-called temporary extensions only keep an unnecessary, inefficient plant alive, extending its pollution and high costs.”
Later in May, the DOE also used its Section 202(c) authority to order the Eddystone oil- and gas-burning plant in Pennsylvania to stay open through the summer. It was set to close this year too, and, as with the J.H. Campbell plant, utility regulators and regional grid operators had determined that shutting it down would not threaten grid reliability. The DOE’s 90-day order for the Eddystone plant is set to expire in late August.
Lawmakers, advocates, and industry experts are increasingly concerned that the Trump administration intends to apply its Section 202(c) authority more broadly. In particular, critics fear a DOE report issued in July will be used to justify future orders — even though its methodology is severely flawed.
The document was written to comply with an April executive order from Trump that tasks the agency with taking unilateral authority over power-plant closures, circumventing decades-old structures that utilities, state and federal regulators, and regional grid operators follow to determine when power plants can close or when they must stay open.
Earlier this month, clean-energy trade groups and nine Democrat-led states filed rehearing requests with the DOE asking it to redo the July grid-reliability report. They argue the study uses cherry-picked data and flawed assumptions to declare that the U.S. faces a hundredfold increase in grid blackout risks absent federal intervention in power plant operations.
Running aging power plants is expensive for utility customers, both in terms of direct costs on energy bills and the indirect costs of crowding out new, cheaper renewables. Utilities and independent energy developers will build less solar, batteries, and wind power if those plants stay online.
The DOE’s moves come as electricity prices are rising at more than twice the rate of inflation across the country. Wright and Trump have falsely claimed that renewable energy is to blame for that trend.
“By illegally extending this sham emergency order, Donald Trump and Chris Wright are costing hardworking Americans more money every single day for a coal plant that is unnecessary, deadly, and extremely expensive,” Laurie Williams, director of the Sierra Club’s Beyond Coal Campaign, said in a Thursday statement. “While Donald Trump and Chris Wright decry this made-up ‘energy emergency,’ they are simultaneously limiting our access to cheap, reliable, renewable energy.”
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.
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