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Electricity costs are going up in the U.S. — and the Trump administration’s attempts to choke off clean energy development are only going to make matters worse.
The average price of electricity for residential consumers is set to hit 17 cents per kilowatt-hour this year and could climb to 18 cents per kilowatt-hour in 2026, per a new report from the U.S. Energy Information Administration.
Electricity prices are rising at more than twice the rate of inflation. Just five years ago, in 2020, average U.S. power prices were only 13.15 cents per kilowatt-hour — 23% lower than they are today.
The difference may seem small, but even one additional cent would tack on roughly $108 to the average U.S. home’s expenses each year. It’s taking a toll on people’s wallets: A survey conducted this spring found that three in four Americans said they’re worried about rising utility bills.
Republican leaders — most recently U.S. Energy Secretary Chris Wright — have tried to blame the trend on the large amounts of clean energy hitting the grid, but that’s not the problem. Solar, wind, and batteries are the cheapest form of power, and a 2024 report from research group Energy Innovation found no correlation between renewable energy adoption and utility rate increases.
Numerous reports and studies reveal that the core drivers of rising prices include an aging distribution grid that requires expensive repairs, and damage to the system from the wildfires and storms exacerbated by climate change. Then there’s the volatile price of natural gas, which produces about 40% of U.S. electricity. Skyrocketing demand for power is also increasingly a factor, as people electrify their homes, businesses, and cars, and in particular as data-center developers snap up as much energy as they can to support their AI ambitions.
In January, President Donald Trump took office promising a great many things — including to make energy more affordable. But since then, household electric bills have risen another 10%, and the policies he’s enacted are set to exacerbate the problems at hand.
Due to the GOP megalaw signed by Trump last month, the U.S. could install as much as 62% less clean energy over the next decade, per Rhodium Group estimates. That’s a huge deal: It’s expected that 93% of the new electricity capacity built this year will be solar, wind, or batteries.
If renewable energy construction slows at the same time data centers and consumers require more power, it will create a clear dynamic of too much demand and not enough supply. The result will be even higher energy bills for Americans, Rhodium and others forecast — the exact opposite of Trump’s grand vow to rein in costs.
If your power bills are getting higher and higher, you’re not alone. That’s probably little comfort, but here’s some proof anyway: Utilities requested or were granted a total of $29 billion in rate increases in the first half of 2025, according to a study from advocacy group PowerLines. That’s more than double the total in the same period last year.
The biggest reason for these rising prices stems from the piece of the grid you can see from your window, as Heatmap reports. Utility poles and wires, also known as the distribution grid, shuttle power from high-voltage transmission infrastructure into homes and businesses. Over the last few years, building and maintaining these lines has become the biggest source of costs that utilities recoup via power bills, according to a December report from the Lawrence Berkeley National Lab.
Natural disasters are also driving up expenses as they force utilities to repair and harden their grid for future weather events. California utilities, for instance, have to rebuild after wildfires and in some cases are spending even more money to underground lines. In the Southeast, utilities routinely look to raise rates to cover post-hurricane restoration costs.
Then there’s the fact that natural gas remains the U.S.’s dominant energy source and that prices for that fuel remain higher than they were over much of the last two years.
Now for the second big question: Will things get better anytime soon? Probably not, for a few reasons.
For starters, power demand is on the rise, stemming in large part from the construction of energy-hungry data centers. Tech giants plan to keep building facilities to run their AI operations, and how they’re powered — and how that demand is managed — could end up making everyone else’s electricity more expensive.
That demand could be largely satiated by new solar and wind farms, which are typically quicker and cheaper to stand up than fossil-fueled and especially nuclear power plants. But the One Big Beautiful Bill Act that Republicans passed in July will soon wipe out federal tax credits that incentivized clean energy construction.
Instead, the Trump administration is pushing to keep aging fossil-fuel power plants online past their retirement dates — a mission that could end up costing utility customers as much as $6 billion each year by the end of President Donald Trump’s term. A federal order that kept a Michigan coal plant open past its planned closure cost its operator $29 million in its first five weeks, and just this week the Energy Department reupped the facility’s extension until November.
Treasury rules tighten access to clean energy tax credits
The U.S. Treasury Department has released guidance that will make it harder to access wind and solar tax credits before their ultimate expiration, Canary Media’s Jeff St. John reports. The One Big Beautiful Bill Act gives wind and solar developers two options to tap the credits: They must either put their project in service by the end of 2027 or begin construction by July 2026. The Treasury’s new guidance narrows the federal government’s longstanding definition of what marks the start of construction.
Still, things could’ve been a lot worse, experts told Jeff — deadlines to finish work could’ve been accelerated, for example. And with these rules, developers have the clarity they’ve been waiting for to make decisions and get building.
USDA pulls support from solar, wind on farmland
Federal assistance for solar and wind power on farmland is fading. On Tuesday, the U.S. Agriculture Department announced that it will “no longer fund taxpayer dollars for solar panels on productive farmland or allow solar panels manufactured by foreign adversaries to be used in USDA projects.” It will also render wind and solar projects ineligible for the agency’s Business and Industry loan program, and bar Rural Energy for America Program loans from being used for ground-mounted solar projects larger than 50 kW.
The Trump administration has already taken multiple shots at REAP, Canary Media’s Kari Lydersen reported in July, freezing nearly $1 billion in funding for farmers and closing a window for new applications before it even opened.
“Come to America and lose $1B”: Foreign offshore wind developers have faced steep financial losses over the past few years, and they’ve only intensified under the Trump administration’s anti-wind policies. (Canary Media)
Polluting the post: Republican U.S. senators move to strip federal funding for the U.S. Postal Service’s transition to an EV fleet to save taxpayer money, though industry observers say the move would have the opposite effect. (Associated Press)
Steel’s dangerous warning: Last week’s fatal explosion at Pennsylvania’s Clairton Coke Works underscores the urgent need to decarbonize the coal-reliant steelmaking industry. (Canary Media)
Solar still rises: The Energy Information Administration estimates the U.S. will add 33 gigawatts of solar power to the grid this year, amounting to half of all new generation brought online in 2025. (EIA)
A red flag for gas stoves: A new Colorado law will require gas stoves to come with labels that warn buyers about the carcinogens and pollution the appliances emit, though a lawsuit has delayed its implementation for now. (Canary Media)
Cruising to electrification: New York City debuts its first hybrid-electric ferry, which is making trips from Manhattan to an emerging climate-change research hub on Governors Island. (Canary Media)
Counting on cleanup: California advocates worry Phillips 66 may shirk its responsibilities to clean up a “lake of hydrocarbons” that has accumulated under a Los Angeles-area refinery slated for closure later this year. (Capital & Main)
China’s dominance of the battery supply chain is uncontested. Many U.S. storage companies have tried to catch up by replicating the technologies already in mass production there. But a smaller cohort is taking a different tack: building factories for next-generation batteries that could give American manufacturers more of a competitive edge.
Peak Energy is one of the newest members of that cohort. The startup, which appeared on the scene in 2023, took a big step this summer when it shipped its first sodium-based grid-battery system for installation in the field. The 875-kilowatt/3.5-megawatt-hour battery is now being completed in Watkins, Colorado, at a testing facility known as the Solar Technology Acceleration Center.
In fairness, the battery cells were imported from China, but Peak designed and built a new enclosure for them in Burlingame, California. Since the sodium batteries are especially rugged, Peak could forgo the temperature-control equipment needed for the current favorite chemistry for grid storage, lithium ferrous phosphate (LFP). If this first installation works well and the cost savings are as consequential as promised, Peak plans to build U.S. manufacturing for the whole package, cells and all.
The installation is a rare bright spot as the storage industry at large grapples with the impacts of Trump administration energy policy. President Donald Trump’s unpredictably shifting tariffs on China have raised the costs of imported batteries and made it hard to plan. The White House’s signature budget law ripped up some — but not all — tax credits meant to support domestic manufacturing of batteries, and added dense new bureaucratic requirements around components from China. New investment in domestic clean-energy manufacturing has plummeted since Trump took office.
But the power sector still wants to build grid batteries at record pace, especially as supersized data centers clamor for electricity supply as soon as possible.
Upstart battery-makers often jockey over how much energy density they can pack into their cells, or how they can reduce the fire risks that follow from squeezing so much energy into a tight footprint. Peak Energy brags more about what its technology doesn’t need: heavy-duty climate control.
“If you think about it, an LFP [energy storage system] is essentially a giant refrigerator that has to operate flawlessly for 20 years in the desert,” said Cameron Dales, Peak’s chief commercial officer and cofounder. That’s because that particular chemistry ideally needs to stay within a few degrees of 25 degrees Celsius (77 degrees Fahrenheit) to preserve its useful life; serious deviations from that safe zone could lead to declining performance or even dangerous failures. A handful of dramatic battery fires has already inspired community pushback against storage plants, making safety a crucial part of the industry’s social license. Indeed, this week U.S. Environmental Protection Agency Administrator Lee Zeldin pledged to support communities resisting nearby battery installations.
The sodium-ion cells that Peak favors — technically called sodium iron pyrophosphate or NFPP — can withstand a much broader range of temperatures, from minus 20 degrees C (minus 4 degrees F) to 45 degrees C (113 degrees F). Peak’s engineers thus dispensed with the usual battery-cooling systems, relying instead on what Dales calls “clever engineering” around how the cells fit into the broader package. “There’s no moving parts, no fans, no liquids, no pumps, no nothing,” he said. The container does include a solid-state heater to ensure the cells never get too cold to charge.
This saves money by reducing the cost of materials and cutting auxiliary power usage up to 90% over the life of the project. But axing the conventional safety equipment brings one more major benefit, because that hardware has paradoxically caused several of the recent high-profile grid-battery fires (by, for example, erroneously spraying water on live batteries, which can make a fire where there wasn’t one).
Plenty of cleantech startups have pitched themselves as safer alternatives to dominant strains of lithium-ion batteries, only to be crushed mercilessly by the lithium-ion manufacturing juggernaut. Overwhelming scale and a wealth of industrial expertise keep pushing mainstream batteries to lower prices and superior performance. However, the up-front costs of the batteries themselves are now just a small piece of the overall bill.
“What has not really been addressed is the construction and installation of a project, and then, even more importantly, the long-term operating costs associated with running that power plant,” Dales said.
According to Dales’ calculations, the energy savings from the passive cooling of Peak Energy’s battery enclosure over a period of 20 years more than cover the initial cost of the battery cells. That’s one way to lure customers to a type of battery they haven’t seen before.
“How can a startup, who’s just getting up to speed and their costs are high and volume is not there yet, compete and win on a project like that?” he said. “It’s because these project economics are so good that even today, we can win on cost relative to … a Chinese LFP system.”
Flipping the switch on the Colorado project is just the start. Then Peak Energy needs to find paying customers interested in much bigger versions of the technology. But the startup has an innovative plan for that next step.
The founders of many battery startups focus on a technology that they find interesting (maybe they chose it for their doctoral research years ago), and then at some point have to convince customers to buy it. This typically leads to what Dales identified as “a classic failure mode, to get piloted to death.” The eager startup spends its precious time developing insignificant yet money-losing pilot installations with lukewarm customers, who try it for a few years and decline to make a follow-up purchase. Then the startup runs out of cash and collapses.
Peak Energy’s founders decided on a different strategy: develop a product in conversation with prospective customers, so they actually want to buy it when it’s ready.
The Colorado project, paid for by Peak, will be scrutinized by a consortium of nine utilities and independent power producers, who have signed on to receive exclusive performance data. If the project meets agreed-upon metrics, these companies will buy Peak’s product for their own use.
“If we do what we say we’re going to do, and the economics are what we think they are, then you should sign up for doing a real project, because it actually makes sense for you,” Dales explained. “That’s how these companies have entered the program, and now we’re in the ‘proof is in the pudding’ phase.”
Some of those consortium members have requested batteries for demonstration projects in 2026, in the storage range of 10 MWh to 50 MWh, Dales said. One large power developer is working on a 2027 project that would deploy nearly one gigawatt-hour of Peak’s sodium batteries to support a hyperscaler data center.
The path from initial installation to giga-scale projects always takes longer than battery startups initially pledge. In fact, only lithium-ion batteries have crossed that threshold, while more unusual variants languish in the minor leagues.
But Peak doesn’t have to invent the core technology — it’s piggybacking off an emerging field of China’s battery industry — and it’s coming to market at a time of propulsive growth in grid storage demand. Its task might not be quite so daunting as it has been for other battery innovators.
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.
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