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Fervo Energy is set to complete the first commercial-scale enhanced geothermal power plant in the United States later this year. It won’t be its last.
The Houston-based startup filed for its long-awaited initial public offering last Friday, and the document offers a more concrete look into the company’s long-term ambitions.
Fervo Energy’s Cape Station geothermal development, in Beaver County, Utah (Fervo Energy)
Fervo has a total of 3.65 gigawatts of power plant capacity that are under construction, ready to build, or in advanced stages of development, according to newly disclosed details in the filing. If built as planned, those projects would nearly double the current installed capacity of geothermal projects in the United States.
That development figure includes the Cape Station project, in Beaver County, Utah, which broke ground in 2023 and is on track to produce its first power in late 2026. A total of 500 megawatts are under construction at the site, though Fervo says it has permits in place to build an additional 1.5 GW on the premises and could scale up even further.
It also includes a “shovel-ready” 150-MW development at a site in Nevada, which Fervo aims to bring online by 2030 as part of a deal to supply electricity to Google and the utility NV Energy.
The firm says it has the potential to grow its power-plant portfolio far beyond these more mature projects. Across the nearly 600,000 acres it has leased — spanning public and private land in the American West, from New Mexico up to Washington — Fervo estimates that it has the potential to develop over 42 GW in total geothermal-energy capacity.
If Fervo is able to realize even a fraction of that larger potential, it would transform the long-stagnant geothermal space — and mark a significant breakthrough for America’s efforts to decarbonize the power grid. Geothermal energy is carbon-free and, importantly, always available, making it complementary to intermittent solar and wind installations.
But the energy source has historically been viable only at select sites with specific geological features, and as a result, it has played a limited role on the grid. Though the U.S. is the world leader in geothermal power production, it gets less than 1% of its annual electricity from the source.
Fervo is at the forefront of a group of startups looking to rapidly expand the footprint of geothermal energy by using innovative technologies. For its part, Fervo makes use of horizontal-drilling techniques honed in the shale oil and gas sector, where its CEO, Tim Latimer, worked before co-founding the company in 2017 alongside Jack Norbeck.
Investors have anticipated the firm’s initial public offering for more than one year. The company is reportedly seeking a valuation of between $2 billion and $3 billion.
Fervo will go public in a market that is red-hot for companies that promise to supply data centers with the enormous amounts of electricity they need. To that end, the firm and other next-generation geothermal players, such as Sage Geosystems and XGS Energy, have struck deals with tech giants in recent years. Fervo has particularly close ties with Google, which is an investor and an anchor customer of the forthcoming Nevada project as well as the startup’s first demonstration plant in the state.
Fervo has already raised nearly $2 billion in funding, including a recent $421 million infusion of commercial project financing for Cape Station. The next-generation geothermal space as a whole has attracted significant attention from investors and enjoys strong support from both Democrats and Republicans; it’s one of the few clean-energy sectors for which tax incentives were spared in last year’s One Big Beautiful Bill Act.
In its IPO filing, the startup says its Cape Station project will deliver its carbon-free power at $7,000 per kilowatt of installed capacity — a price it says is competitive with both traditional and next-generation nuclear power. Its goal is to cut that cost by more than half, to $3,000 per kW of installed capacity, which it contends would allow it to outcompete gas.
Repeatability is the secret sauce here: Fervo’s approach involves drilling and then aggregating together several smaller wells, which it says allows it to rapidly refine its techniques and reduce upfront expenses. Between 2022 and 2025, it says, it reduced drilling times by about 75% and slashed per-foot drilling costs by about 70%.
Going public is a major moment for not only Fervo but also next-generation geothermal in general. What has for years been a buzzy but nascent sector is now stepping firmly into the public eye. With that will come more scrutiny — including of the financials.
Fervo ran a net loss of just under $57.8 million last year, up from $41.1 million the year prior, and it warns in its filing that the losses will continue for the next “several years” as it increases spending and scales up.
But if Fervo proves it can deliver on its near-term power-plant construction targets, investors are unlikely to sweat a few years of losses.
For decades, utilities have used smart thermostats to reduce strain on the grid when electricity consumption is super-high. Paying customers to let utilities turn down air conditioning on hot summer afternoons or electric heating on cold winter mornings is called demand response, and it’s delivering gigawatts of valuable grid relief today.
Phoenix’s Ahwatukee Foothills neighborhood is served by the utility Salt River Project, an early mover in tapping smart thermostats to reduce pressure on the grid. (Hunter Trick [Trick Hunter], CC BY-SA 4.0 via Wikimedia Commons)
But millions more of these smart thermostats are shifting households’ temperatures on a daily basis — and not on behalf of utilities. Instead, the owners of these devices have agreed to let smart thermostat companies modify their temperature settings to avoid costly peak power rates, or to use more clean energy and less dirty energy.
While this energy shifting has largely been invisible to them, some utilities are now gathering data on how these under-the-radar systems could be leveraged to avoid costly infrastructure upgrades or to burn less fossil fuels. Put simply, the more smart thermostats that utilities can recruit to lower peak demand, the less they have to run dirty power plants and the fewer wires and poles they need to transport electrons.
Big Arizona utility Salt River Project is one early mover on this front. Last year, it worked with smart thermostat firm Renew Home to see how thousands of the company’s thermostat-equipped customers in and around the Phoenix area could reduce strain on the grid. Those thermostats belonged to households that opted into Renew Home’s Energy Shift program, which lets the company automatically adjust their temperature settings throughout the day. Nationwide, about 5 million customers representing 4 gigawatts of capacity have signed on to that initiative.
The tracking effort revealed that customers enrolled in Energy Shift are easing peak grid pressures nearly as effectively as those enrolled in the utility’s smart thermostat demand-response program.
Over the course of six test events last August and September, about 28,500 Energy Shift–enabled homes each delivered about 1.1 kilowatts of peak load reduction on average, for a total of about 27 megawatts, Josh Logan, Salt River Project’s senior product manager, said during a March webinar.
That’s not quite as much energy reduction as the average 1.3 kilowatts per thermostat that Salt River Project gets from the roughly 75,000 customers enrolled in its standard demand-response program, he said. But an additional 27 megawatts of peak relief happening more or less automatically is nothing to sneeze at, he added.
It’s worth pausing to note the trickiness of comparing customer load-reduction programs like Energy Shift to typical utility demand-response initiatives. Utilities and regulators have always thought of demand response as something that happens during emergencies to directly alter how customers would have otherwise used energy. Utilities want to see a direct reduction in energy demand from some typical baseline.
Energy Shift’s frequent tweaks to millions of household thermostats upend those benchmark expectations, said Will Baker, Renew Home’s senior director of market integration. To measure the impact of its test events in Arizona and elsewhere, the company uses randomized control trials that pull data from a broad range of customers to determine a baseline, he said.
The company’s results are prompting Salt River Project to examine the idea of offering Energy Shift customers incentives for expanding how often or deeply they’re willing to shift their energy use. While the utility isn’t disclosing what financial arrangements it might be working out to more reliably tap into those smart thermostats in the future, Logan expected the results would be “extremely cost-effective” for the utility.
Renew Home worked with the company EnergyHub to reveal this particular data to Salt River Project, free of charge. The utility already uses EnergyHub’s online platform to manage its existing demand-response programs, and the smart thermostat data from Renew Home was rolled into the tool to allow an easy viewing experience.
Arizona isn’t the only place where EnergyHub and Renew Home are collaborating to surface the value of what they call “background virtual power plants” — networks of distributed energy resources that operate with no utility management.
During Winter Storm Fern in January, for example, the two companies found that Energy Shift customers reduced load for an unnamed Southeast U.S. utility by 50 megawatts, said Megan Nyquist, EnergyHub’s senior product market manager. That’s about twice as much winter peak reduction as that utility has enrolled in its official smart thermostat demand-response program, she said.
“Utility programs will continue to be a huge part of how [virtual power plants] grow and scale. But they’re not the only source of flexible capacity out there,” Nyquist added.
Last summer, Renew Home reported that it was able to provide 380 megawatts of load reduction over two hours on a hot July afternoon in the territory of PJM Interconnection. PJM faces a cost crisis in meeting its peak demands for the grid it manages for more than 67 million people in 13 states and Washington, D.C.
Tyson Brown, Renew Home’s head of utility partnerships, noted during the March webinar that this achievement came from “only a fraction of the available fleet. If we actually dispatched the entire Energy Shift–enabled fleet in PJM, the impact would have been closer to 800 megawatts.”
One important advantage of Energy Shift’s day-to-day adjustments is that they are generally less disruptive to household comfort than traditional demand-response programs, Brown said. Utilities that ask customers to shiver through the coldest mornings or swelter through the hottest afternoons struggle to keep households enrolled.
“The goal here is for it to really be imperceptible, such that the end user feels as if the thermostat is doing the things that it’s already been doing for them,” he said, noting that customers are always free to cancel their participation if they want to.
Paying consumers to use less energy during times of peak demand can help save all utility customers money in the long run, Baker noted. That’s because utilities pass on the costs of building and operating power plants and grid infrastructure to meet peak loads on to all customers as a portion of their utility rates. Anything that utilities can do to reduce those costs can eventually lead to lower rates across the board.
Renew Home is a member of the Utilize Coalition, a group of companies promoting virtual power plants as a means of reducing rising utility bills. Baker declined to name other utilities that might be considering methods to pay Energy Shift customers for committing to reduce peak energy use. But he did say, “We’re going into our preseason planning with our utilities — and there’s not a single utility we’re not talking with about this.”
Enfield, North Carolina — a small rural town with big clean-energy dreams — just passed a key milestone on its quest to lower costs and strengthen resilience.
A seed grant of nearly $300,000 will jump-start a neighborhood form of geothermal energy that can heat, cool, and provide hot water to households.
If the nonprofit that secured the money, Enfield Energy Futures, can raise the rest of the $5 million it needs for the pilot project, the town’s electric utility could become the first in the Southeast to deploy this kind of technology, joining a small but growing number that are following the lead of Eversource Energy in Framingham, Massachusetts.
“The community is super bought into the idea that we are looking beyond dirty energy,” said Mondale Robinson, the 46-year-old mayor of this town about 30 miles south of the Virginia border, one of the poorest and Blackest in America.
Since late 2023, Robinson and the team who formed the Enfield nonprofit have been holding town hall meetings to vet and refine their ambitious goals for low-cost energy independence. Their plans include a town-run solar farm, a weatherization hub to help residents access grants for insulating their homes and upgrading appliances, and a revamp of the town’s dilapidated grid, which suffers frequent outages.
The geothermal project, called a thermal energy network, is part of this larger vision. The pilot project would serve an upcoming affordable housing development that Robinson is spearheading, made up of 34 townhomes in southeast Enfield. Eventually, the group hopes to expand the geothermal network to the entire town of some 2,000 — providing a sizable chunk of the community’s energy needs.
“If you’re a Black Enfield resident, either new or one with deep roots like myself, you know what permanent neglect looks like,” said Robinson, who grew up in a segregated part of town where indoor plumbing wasn’t a given, even in the 1980s. The thermal energy network, he said, could serve “as a model for what’s possible in rural Black spaces, throughout the Black Belt in North Carolina and the South at large.”
A political organizer and consultant who has worked around the world, Robinson returned to his hometown and was elected mayor during the Biden administration. Together with a coterie of climate advocates, academics, and other local leaders, Robinson hoped to tap funds from the 2022 Inflation Reduction Act, Biden’s signature climate law, and other government initiatives to help realize his vision for Enfield.
Then, President Donald Trump was elected. In a matter of months, Trump and the Republican Congress took a wrecking ball to federal support for clean energy — clawing back funds from Biden-era climate programs and drastically curtailing tax incentives for efficiency and renewable energy.
The Trump administration’s assault on clean energy has undoubtedly been a setback, said William Munn, a former regional director at Vote Solar who is now a consultant and acts as Enfield Energy Futures’ executive director. “The federal situation really screwed up our strategic plan,” he said.
But the group is determined to press on. “We’re being creative,” Munn said. “We’re finding ways to do all the things.”
The geothermal pilot project is a prime example.
Geothermal is among the few sources of carbon-free energy that survived last summer’s federal purge on tax credits. That means the Enfield project can access a 30% to 40% federal incentive so long as it begins construction by 2033 — and none of its components are produced by countries deemed a “foreign entity of concern.”
“With the tax credits still alive there, it just makes natural sense,” said Helen Whiteley, a climate entrepreneur and longtime member of the Enfield team.
With those federal incentives in mind, Whiteley and her cohorts last year recruited Eric Bosworth, who oversaw design of the Eversource thermal energy network in Massachusetts, to do the same in Enfield.
The term “geothermal” has many meanings, said Bosworth, who has since left Eversource and formed his own consultancy. “It can mean drilling miles down to generate electricity via steam. It can mean going a few thousand feet down and pulling hot water out. Or it can mean what we’re talking about, which is shallow geothermal.”
Either way, he emphasized, “the technology is not new. We know that it works.”
Indeed, shallow geothermal has been deployed by communities such as hospitals and universities for decades. But utility-sponsored projects linking individual homes have only recently begun to gain steam, with some 26 utility pilots underway across the country.
The collective nature of the networks helps make them cost effective, Bosworth said. That will be especially true of the Enfield pilot serving the new affordable housing development, which is expected to break ground this summer. Its homes won’t have to be retrofitted with ducts and other features to accommodate central heating and air conditioning.
Another factor keeping costs low: open trenches. Thanks to funds from a federal pandemic-relief law, the town will be replacing its aging water mains over the next year or so.
“Construction is so expensive. If you’ve got the equipment out there digging up sidewalks, and you’ve got to cement them over, why not just lay the geothermal piping at the same time?” said Whiteley, who hatched the plan to undertake the thermal energy network’s construction in conjunction with the water main replacement.
“If you’ve already got a trench open, and you’re just laying the pipe in,” Bosworth said, “you’re saving probably on the order of 50% of the costs.”
That the project will leverage existing infrastructure programs was a key source of appeal for BuildUS, a philanthropic foundation aimed at speeding the transition to a cleaner and more equitable economy. BuildUS distributed the nearly $300,000 grant to Enfield Energy Futures earlier this month.
“Enfield is showing how rural communities can lead the clean energy transition,” Jill Fuglister, the managing director, of BuildUS, said in a statement announcing the grant. “By aligning infrastructure upgrades, geothermal technology, and workforce development for the local community, this project demonstrates an equitable model that other towns can follow.”
Enfield Energy Futures is eager to use the thermal energy network for job training in the county, which has one of the state’s highest unemployment rates.
“Think about all the ancillary jobs and opportunities that came along with the industrial revolution with the steam engine,” Munn said. “We’re thinking about this in the same way.”
Perhaps above all, the pilot project would bring desperately needed relief for a town straining under the weight of unaffordable and unreliable energy. Electricity bills here average $650 a month in the winter.
“That is beyond oppressive,” Robinson said. “Our people are super excited about lessening their burden.”
A thermal energy network is essentially a network of ground-source heat pumps. They’re analogous to air-source heat pumps, which move heat from inside a building to outside to lower the temperature, and vice versa.
In a thermal energy network, heat moves between the indoors and the ground, rather than the air. An antifreeze water solution flows through a buried pipe, cooling or heating the surrounding earth, maintaining a steady temperature. That makes ground-source heat pumps roughly twice as efficient as air-source varieties.
“The physics are the same,” Bosworth said. “It’s just using the ground temperature instead of the air temperature, and that’s why you get a higher efficiency.”
While the technology works everywhere, it’s particularly cost-effective in areas that can experience extreme temperatures, such as North Carolina in the dog days of summer. And it’s four to five times more efficient than the electric baseboard heaters and window air conditioners prevalent in Enfield.
It’s also possible to add hot-water heating to the mix — increasing the balance that can be achieved in the closed-loop system.
“You have a lot of excess heat in North Carolina,” Bosworth said. “It gets really hot in the summer. You’re going to store all of that heat underground, and you may not pull all of it out in the winter, but if you add domestic hot water, suddenly the system looks a lot better.”
Between replacing hot-water heating and meeting heating and cooling needs, the network could have a huge impact on the average Enfield resident, cutting maximum household energy needs by as much as 70%.
Similarly, if the entire town gets connected to the thermal energy network, it could cut overall electricity demand by about half, though planners don’t have exact figures yet.
“What geothermal can do is just relieve a significant amount of pressure on the grid,” said Brian McAdoo, an associate professor at Duke University’s Nicholas School of the Environment, whose students will gather data this fall about how well the ground transfers heat in Enfield, to inform the project’s design.
McAdoo said less grid pressure would mean fewer outages in the town, which experienced a high-profile, four-day loss of power last summer. And with the town’s hoped-for solar farm, the thermal energy network would foster energy independence, backed up by the regional grid.
“Then you can use the backup and that excess capacity for more business,” McAdoo said. “That’s the dream, right?”
But plenty of obstacles still stand in the way of that dream, starting with the need to raise millions of dollars to complete the pilot, and to do so quickly enough to take advantage of the open trenches.
Nick Jimenez, senior attorney at the Southern Environmental Law Center and another key member of the Enfield coalition, remains optimistic.
“The grant shows the power of embracing and leading with a positive vision, particularly in communities that have seen historic underinvestment,” he said. “It takes courage to try something new, but when you do, people want to get behind it.”
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy and the environment. Sign up for their newsletter here.
Reporting for this story was supported by a grant from the Fund for Investigative Journalism.
TOM GREEN COUNTY, Texas—Some Texas oil wells gush hundreds of barrels of oil a day. But many are like the wells on Jackie Chesnutt’s ranch in West Texas that only trickle out a couple barrels a month.
Chesnutt, a retired engineer, claims the five wells operating on her ranch are out of compliance with state rules and should be shut down. The company, CORE Petro, says that it’s struggling to break even, let alone pay to plug the wells. But it says that all its wells are in compliance.
There are thousands of oil and gas wells around Texas like these: low-producing wells leased by companies operating on a shoestring. About two-thirds of the active oil wells in Texas, or 99,000 wells, produce less than 10 barrels of oil a day, according to the state regulator. To remain active, oil wells in Texas must produce at least five barrels for three consecutive months or at least one barrel for 12 consecutive months.
Jackie Chesnutt props up a sign next to a leaking oil well operated by CORE Petro on her property near Knickerbocker, Texas, on Nov. 18, 2025.
Companies will often maintain a minimal amount of oil production instead of plugging a well, which can cost tens of thousands of dollars. Landowners like Chesnutt argue that this pattern can lead to pollution and burdensome equipment on their land.
Oil industry analysts and environmental advocates say they have heard claims that companies report the bare minimum of oil production to avoid plugging wells.
“The wells on the lease are all producing,” said Railroad Commission spokesperson Bryce Dubee.
Advocates of reforming the oil and gas industry say that stricter rules are needed to ensure companies plug wells in a timely manner and assume the costs so that it does not fall to the state.
In a 2022 report on Texas’ orphan well problem, the nonprofit organization Commission Shift wrote companies should not be able to “indefinitely ‘produce’ a teaspoon of crude or a cubic foot of gas simply to avoid paying for decommissioning.”
Texas has more than 159,000 inactive wells. If the operator of an inactive well goes out of business, the unplugged well eventually becomes an orphan. Texas is facing a record-high backlog of more than 11,000 orphan wells.
Chesnutt is the rare landowner who is fighting back against this broken system. The 69-year-old and her now-deceased husband bought the 375-acre property outside San Angelo in 1998. After retiring from a career working at a pharmaceutical company in San Angelo, she now tends goats and sheep on the ranch.
Her complaints to the Railroad Commission, which regulates oil and gas, have gone nowhere, she said. She has resorted to shutting off power to CORE Petro’s wells because she says they are out of compliance with state production rules. CORE Petro responds that it’s Chesnutt who is breaking the law by shutting off power and, without electricity, they have no way to produce oil at the wells.
“We’re between a rock and hard place,” said Cassie Ohlhausen, who runs CORE Petro with her husband, Kent. “We’re not financially able to plug a bunch of oil wells. That’s not why we’re in this business. We’re in this business to produce oil wells.”
Chesnutt’s growing frustration has spilled over into confrontations with CORE Petro and commission staff. The Railroad Commission alleges that Chesnutt physically assaulted staff members and endangered them with aggressive driving. The agency has instructed her to put all communications in writing to avoid future incidents. The owners of CORE Petro say she has threatened them with a gun. Chesnutt disputes these claims.
The Railroad Commission declined to answer numerous questions about the oil lease on Chesnutt’s ranch. Instead, commission staff provided a letter sent to Chesnutt that described altercations with staff members. The Railroad Commission has not issued any fines to CORE Petro.
Chesnutt’s ranch is one small window into the vast problem of Texas’ aging oil assets. Existing financial mechanisms are not enough to retire the thousands of low-producing oil wells littered across the Texas countryside. The problem eventually falls to the state or becomes a thorn in the side of landowners like Chesnutt.
Persimmon Creek Ranch lays where the desert scrubland of the Trans Pecos region meets the rocky woodlands of the Texas Hill Country. The ranch, about 200 miles northwest of Austin, gets its name from the native persimmons she collects to make preserves.
“One of the biggest things we have focused on out here since we’ve bought the place is water, water, water,” she said. Chesnutt, now widowed, relies on a windmill-operated well to provide water for her residence and animals.
Chesnutt’s home office displays professional mementos, including her diploma from the University of Texas, Austin, where she was an early female graduate of the engineering program. She now applies an engineer’s attention to detail to investigating the drilling operations on her property.
Chesnutt holds 50 percent of the mineral rights on the property, meaning she receives a share of profits from the wells. This has amounted to only a few hundred dollars in royalties every couple months in recent years. This money is hardly worth the trouble the wells have caused, she said. She riffled through documents on a sunny fall afternoon, her dog Einstein asleep at her side.
While the lease was operated by a previous company, Amor Petroleum, Well #10 had been shut down for lack of production. That left only four producing wells.
Then CORE Petro took over the lease in 2021. Chesnutt says that is when the problems started.
Once a well is inactive, the operator has 12 months to plug it or obtain an extension. The clock started ticking for CORE Petrol to get Well #10 producing again. CORE Petro reported a small amount of production at the well to bring it back to active status.
Chesnutt said that the company caused numerous spills in their attempts to get oil flowing.
“They made a big mess of it,” she said, showing photos of spills of oil and produced water, a hazardous byproduct of drilling. Chesnutt fears the spills could contaminate her groundwater and has paid to get her water tested multiple times.
“We have worked our asses off to make this place wonderful and beautiful,” she said. “I refuse to accept that the next person is going to have this happen to them.”
The Railroad Commission issued CORE Petro multiple violations for unpermitted disposal of oil and gas waste, or spills, at the lease. But each time, the violation was later resolved without the company paying fines.
“RRC records indicate four pollution violations for this lease,” Railroad Commission spokesperson Dubee said. “In each instance the operator was notified and upon reinspection all violations have been fixed on the lease indicating compliance.”
CORE’s Ohlhausen said that some amount of spillage is to be expected and that the company always cleaned up the spills.
But Chesnutt’s frustrations only grew.
“What has really blown my mind about this is that we have to follow one set of rules in industry,” Chesnutt told Inside Climate News. ”But the oil companies, they allow them to just come out here and do whatever the hell they want.”
By her account, only one of the wells on her property has produced oil in years. But CORE Petro reports ongoing production at all the active wells. The Railroad Commission requires well testing to prove wells are producing oil. CORE Petro’s most recent well testing, in 2025, shows each well producing less than one barrel a day.
Chesnutt claimed the company is falsifying production numbers to keep the wells operating. The company denies this claim.
“The operators can fill in any information they want and nobody checks them,” she said. “It’s unacceptable. I’m really sad that the Permian Basin and all these areas are like this.”
Operators submit monthly reports to the Railroad Commission of how much oil is produced and how much is stored at each lease. While the state rules require every well to be actively producing oil, production reports are only required for the entire lease, not individual wells. Inside Climate News found inconsistencies between public records of oil production and inspections at the lease.
On July 2, 2025, a truck picked up oil from the ranch and recorded the level of oil in the tank afterward, according to a commission inspection report. A Railroad Commission inspector visited the site on Sept. 16. He noted that the amount of oil in the tank hadn’t changed since July 2.
But in the intervening months, CORE reported producing 10 barrels in July and another 15 barrels in August. The company was reporting production on paper but the volume of the tank did not rise, according to the RRC inspection.
The Railroad Commission declined to answer questions about this and it does not appear the agency has investigated the discrepancy. Cassie Ohlhausen said that the company uses an auxiliary tank to collect the oil. Once it is full, the oil is transported to the tank battery, a large metal tank that stores oil. She said this could explain why the tank battery did not rise even though oil was being produced.
“The reporting of production is accurate and is done by a third party who tracks our oil sales and inputs those numbers into the RRC system,” Ohlhausen said.
Inside Climate News observed an auxiliary tank at only one well. Any oil produced at the other wells would have to flow directly into the tank battery.
Commission documents reveal other inconsistencies. On February 7, 2025, the Railroad Commission issued a violation to CORE Petro that said Well #9 was an “inactive unplugged well.” However, the next time the inspector visited the site, the well was determined to be compliant. The Railroad Commission declined to respond to questions about this.
Property owners have little recourse other than reporting the problems to the Railroad Commission. Chesnutt feels the Railroad Commission is ignoring her complaints about CORE Petro.
“Not one single acknowledgement that [the wells] should be plugged,” she said of her interactions with the state agency. “I’ve had resistance on even cleaning up the spills.”
Meanwhile, Chesnutt’s behavior has alarmed Railroad Commission staff. An attorney for the agency sent a letter to Chesnutt on Oct. 31, 2024. The letter states that she “verbally threatened and physically assaulted Commission staff” and “engaged in reckless and aggressive driving,” threatening the safety of commission staff. The letter also says that she told commission staff of her “intent to commit several violent crimes” against CORE Petro’s employees.
Chesnutt disputes the commission’s characterizations. “I don’t know, because I’ve never assaulted anyone,” she said.
The Tom Green County Sheriff’s Office has responded to calls from Chesnutt, Kent Ohlhausen and the Railroad Commission about incidents at the ranch, according to call sheets. The Railroad Commission requested the sheriff’s office be on “standby” when visiting Chesnutt’s property.
Commission inspectors have also noted in inspection reports that Chesnutt is turning off power to wells on her property. Chesnutt maintains that the wells pose a fire hazard and she is within her rights to turn them off. State rules require electricity be disconnected at inactive wells. Electrical lines for oil wells were blamed for starting devastating wildfires in the Texas Panhandle in 2024.
In response to the regulator’s claims of her “reckless driving,” Chesnutt said that last October she saw a Railroad Commission truck on the road leading to her ranch. She was driving in the opposite direction, so she did a U-turn and flashed her headlights to get the driver’s attention. She asked him to pull over and asked if he was headed to her property, because she was waiting for an inspector.
CORE’s Ohlhausen said that Chesnutt has threatened their staff multiple times.
“All the wells produce at some point or another until she goes and turns them off,” she said.
“We can’t afford a lawsuit, but we have every right to call the sheriff and the justice of the peace and have her stand down on turning our oil wells off,” she said.
CORE Petro specializes in operating aging, low-producing wells, Ohlhauser explains, noting that her husband Kent is called “the Oil Well Undertaker” because he works with “end of life wells.”
“We’re the ones that end up with what they call the stripper wells that have already been stripped of all their oil,” she said. “They’re just producing a bit of oil every day to keep somebody alive.”
Kent Ohlhausen owns several other oil companies. Many of the leases he operates meet the bare minimum requirement of one barrel of oil production a month for 12 consecutive months. For example, the Olhausen Oil Company’s Ohlhausen, W.T. lease reported one barrel of oil production for each month between April 2023 to April 2024. The same company’s Barker C.P. lease reported one barrel of oil production every month December 2023 to January 2025.
“We literally work seven days a week, producing stripper oils,” his wife said. “We just eke out a little bit of money and that’s just fine with us.”
The company paid a $50,000 bond to the state of Texas to cover plugging costs if they went out of business. But Ohlhausen said that, even if they wanted to, they wouldn’t be able to plug all their wells.
“Sometimes the money is not there,” she said. “We don’t take investors. We are just Kent and Cassie.”
Texas is dedicating more money than ever to plugging orphan wells. But the number of orphan wells continues to climb. Many of the marginal wells that continue producing when their owners do not have the means to plug them eventually become orphan wells.
“Operators will often produce a de minimis amount of hydrocarbons to stay out of inactive status,” said Adam Peltz, a senior attorney at the Environmental Defense Fund. ”This is widely abused.”
Peltz said that properly identifying inactive wells is important because it creates an “early warning system” for regulators.
“Every marginal well eventually becomes an inactive well. And many inactive wells become orphan wells,” he said. “There’s no reason why the public should bear the risk.”
New Mexico is in the process of reforming its bonding system for oil and gas wells. The proposed rule changes would classify wells that produce less than 90 barrels of oil a year as of “no beneficial use” and require them to be plugged.
Peltz said these changes would reduce the likelihood that the state would end up paying to plug the wells.
The Railroad Commission is also developing new rules for inactive wells following the passage of Senate Bill 1150 in 2025. The law requires plugging wells that are more than 25 years old and have been inactive for at least 15 years, unless they qualify for certain exemptions.
The Inflation Reduction Act created a $350 million fund for plugging marginal conventional wells to reduce methane emissions. The Texas Commission on Environmental Quality (TCEQ) received the largest grant from the program, of $134 million. The methane reduction program falls under the TCEQ, as the state agency that regulates air emissions from industry. The program is “currently in development” and staff are preparing to issue a request for grant applications to prioritize and select wells for plugging, according to a TCEQ spokesperson.
The program will rely on operators volunteering to plug their wells.
The program could help companies like CORE Petro plug wells that otherwise might end up orphaned.
“If there was a grant for us to plug wells, we’d be plugging wells all day,” Cassie Ohlhausen said. “Because we know that we own holes that are not gonna ever be viable.”
An aerial view of Jackie Lynn Chesnutt’s property in Tom Green County, Texas, on Nov. 18, 2025. She has owned the ranch for nearly three decades and worked to increase tree cover and provide wildlife habitat.
When it comes to clean energy, China makes — and the world takes.
The country produces the vast majority of the globe’s solar panels, batteries, and wind turbine equipment, and most of its EVs. Plenty of that tech is used in China itself, but the country also exports a lot of it elsewhere.
In recent years, China has seen the most growth in its exports of EVs and batteries in particular. For both technologies, European nations have been the main destination.
In the EU, Chinese-made EVs accounted for 9% of sales in December 2025 — up from 6% the prior year. That acceleration happened even though the EU slapped duties on Chinese-made EVs in October 2024, in an attempt to protect its domestic automakers.
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Though China still makes more than 90% of the world’s solar panels, its exports have declined from their peak in early 2023 as two key markets — Europe and Brazil — have imported and installed solar at a slower pace. Asian countries imported more Chinese solar equipment than did any other region across most of last year.
China’s clean-energy manufacturing machine has taken on new relevance since late February, as U.S. and Israeli attacks on Iran have spurred a historic disruption of global oil and gas markets.
Asian countries are bearing the brunt of the current energy crisis. Some especially hard-hit nations are taking extreme conservation measures — encouraging people to use less air conditioning, work from home, and even ration fuel. But energy costs are also soaring in other places, like Europe, which relies heavily on imported fossil fuels. Americans, meanwhile, are paying higher prices at the gasoline pump, where a gallon has surpassed $4 on average.
It’s the latest reminder of the perils that come with depending on fossil fuel imports — and it’s prompting some countries to double down on renewable energy to insulate themselves from future price shocks. True, importing clean-energy tech is still importing, but it’s fundamentally different from relying on fossil fuels from abroad. With clean energy, you buy it once, roll it out, and for decades it does its job within your borders. That’s not so with fossil-fueled infrastructure.
Ultimately, even if other regions invest in building out their own domestic clean-energy supply chains, China is the clear beneficiary of the coming shift to cleantech. Its head start is just that big.
Canary Media’s “Electrified Life” column shares real-world tales, tips, and insights to demystify what individuals can do to shift their homes and lives to clean electric power.
Balcony solar is poised to take the U.S. by storm.
The DIY systems, which you can hang on a balcony and plug into a normal 120-volt outlet, help lower energy bills and carbon emissions. Already huge in Germany, solar that’s as easy to install as an appliance would be a game changer for the four out of 10 U.S. households that can’t get rooftop systems for financial or logistical reasons.
In 2025, deep-red Utah became the first state to pass a bill making it easier to adopt plug-in solar systems. So far this year, four more states have all advanced similar measures — and nearly two dozen others are weighing bills of their own.
Considering a balcony power plant yourself? Check our tracker to see the status of plug-in solar legislation in your state, and keep reading for some FAQs on the tech.
Balcony solar systems are modest in size, ranging from just one to a few solar panels. Most states, including California and New York, are considering capping systems at 1,200 watts — a sixth of the average home-solar installation.
The panels connect to an inverter that converts their direct current into alternating current, the kind our homes use. A plug from the inverter fits into a typical 120-volt outlet (15 or 20 amps), pumping the power of the sun directly into a home’s existing wiring.
The systems can cover a small but meaningful fraction of a home’s electricity use: An 800-watt unit can power the equivalent of a fridge or a few small appliances when the sun’s shining.
One or two people can set up a system in less than an hour without the help of a professional. In states with balcony solar laws, you don’t need permission from your utility, unlike when installing a larger rooftop array. Nor do you need to pay the utility a fee.
Balcony solar costs range from several hundred dollars to more than $1,000, depending on the system size, and can save a household hundreds of dollars per year.
In Los Angeles and the San Francisco Bay Area, for example, the plug-in solar nonprofit Bright Saver offers a two-panel, 800-watt system for $1,499 and a four-panel, 1,600-watt system for $2,348. (Because of utility rules, Bright Saver currently provides these products only to residents who already have rooftop solar and want to expand.)
At $1.47 to $1.87 per watt before taxes, that’s a pretty good deal in the U.S. Nationally, the average rooftop system costs $2.58 per watt before local and state incentives.
The payback period depends on how much electricity your home uses and your utility rate. But according to Bright Saver, these systems can save California households nearly $500 per year and have a payback period of four to five years.
Once they’re paid off, every sunny hour can provide you with free power for the life of the solar panels, many of which are warranted to last 30-plus years.
Absolutely. Physically, the panels can go anywhere they’re safely secured and able to soak up a lot of sun, such as a deck, patio, porch, fence, or yard.
Unless, of course, your home is subject to limiting regulations. Your city or homeowners’ association may have rules about where you can put solar panels. If you’re a renter, you’ll want to double-check your lease to make sure you’re not prohibited from hanging them outside.
Balcony solar produces electricity and sends it directly into the home’s circuitry at a wall outlet. Rooftop solar, by contrast, pours power into a home’s electrical panel.
That distinction has prompted some safety concerns, even as a few companies start to sell these products.
If the solar panels provide too much power, and circuit breakers don’t trip, the wires in the wall could overheat, creating a fire risk, said Ken Boyce, vice president of engineering at safety science company UL Solutions. If a person were to touch the plug prongs either while the panels are illuminated and partially plugged into an outlet or in the fraction of a second after the plug is disconnected but still energized, the individual could get shocked or electrocuted.
But these hazards can be tamed with technical fixes. For example, a special plug could be designed with a built-in circuit breaker and no exposed conductive parts.
In their plug-in solar bills, states are legislating that manufacturers adhere to rigorous standards to protect consumers. Utah’s law, for example, requires that systems are certified safe for consumers by UL Solutions or another nationally recognized testing laboratory, and that they meet the standards of the National Electric Code.
The National Electric Code doesn’t specifically address plug-in solar, leaving the tech in a legal gray area on that requirement. And as of publication, no manufacturer has had a complete balcony-solar product certified as safe.
But that could soon change. After Utah’s law passed, UL created a new safety standard for plug-in solar, UL 3700, and launched a certification program in January. The company is now working with manufacturers to get their systems certified. Boyce anticipates the first certification in “weeks to months rather than years.”
So, if you’re itching to get plug-in solar but concerned about safety, sit tight: A vetted product should hit the market soon.
And, bigger picture, take solace in the evidence from across the Atlantic.
Germany has seen balcony solar grow from roughly 40,000 systems in 2017 to as many as 4 million in 2025. Sebastian Müller, chair of the German Balcony Solar Association, said last year that the country had yet to see any safety issues beyond a few cases of individuals attempting to hook up unsuitable hardware, like a car battery, to the devices.
Not without a battery. For the safety of utility lineworkers, a blackout will trigger the inverter to stop putting out AC power. But if you plug the solar panels into a battery instead of an inverter that feeds your home, then you can pull the stored electrons when you need them.
That peace of mind isn’t cheap, though. For example, while EcoFlow’s inverter retails for $299, a 1.92-kilowatt-hour EcoFlow inverter-battery combo costs $1,199.
Indeed they are. Bright Saver estimates more than 1,000 plug-in solar systems have been installed in California alone.
Bentham Paulos, senior research associate for the Clean Energy States Alliance, recently installed a system at his home in Berkeley, California, for just $0.66 per watt. (He has a rooftop array, and his utility’s rules allow him to add up to 1,000 watts without another interconnection agreement.) To prepare, Paulos, who also authored a plug-in solar policy report released in January, spent many hours studying amps, volts, and wiring configurations on YouTube to assure himself that he could safely put plug-in solar on his garage.
The market for balcony solar could rapidly transform in the U.S. over the next year, as states green-light the tech and manufacturers roll out compliant products.
“I think a lot of companies are waiting for the regulatory landscape to be clear,” Paulos said. Once a handful of states explicitly allow balcony solar, he anticipates that manufacturers will show “a lot of innovation to make this a really super easy and safe consumer product.”
Canary Media’s “Eating the Earth” column explores the connections between the food we eat and the climate we live in.
In late March, President Donald Trump dramatically expanded the federal mandates for farm-grown biofuels in cars, trucks, and tractors. In front of a cheering crowd that he called “the single largest gathering of farmers the White House has ever seen,” Trump announced his Environmental Protection Agency will require record amounts of soy-based biodiesel and corn-based ethanol to be blended into petroleum-based diesel and gasoline.
Like most of Trump’s environmental policies, and almost all biofuels policies, it’s terrible — for consumers, the climate, the hungry, and the country.
By diverting food crops into fuel and inflating demand for grain and vegetable oil, Trump’s jacked-up mandates will increase food prices, food shortages, and food insecurity. They’ll also accelerate deforestation and greenhouse gas emissions, inducing the world’s farmers to clear tens of millions of acres of new fields to exploit the higher prices for their crops. At the same time, they’ll inflate demand for fertilizer that’s already in short supply because of the Iran war, further increasing global food prices as well as corn-country pollution.
This is all bad. It’s morally unconscionable to reroute crops from bellies to cars when the grain it takes to fill the average gas tank could feed one of the world’s 150 million undernourished children for a month. It’s environmentally and economically nutty to use good farmland to grow ethanol when an acre of solar panels produces 20 to 100 times more energy than an acre of corn. The world is on track to deforest a land mass nearly twice the size of India for agriculture by 2050, and biofuels are a remarkably inefficient use of increasingly scarce soil.
But as I wrote in this space four years ago when President Joe Biden was promoting biofuels during a global food crisis, the badness is bipartisan; few Democrats oppose aggressive government support for farm-grown fuels. The badness is global, too; Brazil, Canada, India, Indonesia, and other nations are ratcheting up incentives for crop-based fuels for cars and trucks. There’s also a growing worldwide effort to run planes on farm-grown “sustainable aviation fuel,” including generous subsidies in the One Big Beautiful Bill Act that Trump signed last year.
Really, the only unique aspect of the biofuel badness at Trump’s White House “Celebration of Agriculture” was his candor about its purpose: to shovel cash to farmers, his most loyal voting bloc and America’s most powerful lobbying force.
He didn’t really pretend he was trying to give consumers relief from exorbitant gas prices or reduce America’s dependence on foreign oil, the industry’s current arguments for stuffing more crops into fuel tanks. He certainly didn’t pretend he was trying to help the planet; in fact, he exulted about all the regulatory “environmental nonsense” he’s gutted to save farmers money. He didn’t even pretend he was simply trying to ensure farmers a level playing field; he boasted about all the special treatment he’s given them, including “massive new loan guarantees,” a huge bailout to offset his tariffs —“I just gave you $12 billion!” — and lucrative tax breaks that “only Trump could’ve gotten you.”
“I’m actually giving you much better than a level playing field!” he proclaimed.
This agri-pandering isn’t unusual, even if Trump is unusually brazen about it. In Washington, D.C., it’s almost mandatory to describe farmers as “hardworking patriots” with “heartland values” while showering them with lavish subsidies, grants, cut-rate loans, price supports, and other agricultural welfare. The Beltway’s relentless efforts to prop up crop-based fuels, which would have no hope of competing with conventional fuels without government help, are the ultimate proof that Big Ag has even more political clout than Big Oil.
But Trump is taking the badness to a new level. While his slogan may be America First, his Agriculture Department’s slogan is Farmers First. Timothy Searchinger of Princeton University, the researcher who exposed biofuels as a deforestation disaster in a 2008 Science paper, estimates the EPA’s new blending requirements will ultimately expand global cropland by at least 28 million acres, an area the size of Ohio.
Two decades ago, when there were no viable alternatives to fossil energy and a documentary called “Who Killed the Electric Car?” was chronicling how General Motors literally scrapped its first alternative vehicles, crop-based fuels looked like the renewable future of transportation. But ever since Searchinger and others showed that those fuels are much worse for the climate than gasoline, and a new generation of electric cars proved to be much better, the federal Renewable Fuel Standard has merely reflected Washington’s determination to increase farm incomes by increasing farm commodity prices. In case there was any doubt about his motives at his Celebration of Agriculture, Trump also canceled a Biden administration effort to extend the Renewable Fuel Standard to electric vehicles, which would have helped the cause of cleaner transportation but not the cause of wealthier farmers.
Again, though, the problem is much bigger than Trump. The world devotes 125 million acres of cropland — an area larger than California — to growing biofuels. (The area is actually even larger, but biofuel production does create useful by-products like animal feed that affect the land accounting.) A recent paper concluded that in Indonesia and Malaysia alone, global demand for biodiesel drove an area of tropical forest larger than Connecticut to be converted into oil palm plantations between 2002 and 2018 — and Indonesia’s own biofuels targets contributed to a 66% jump in deforestation there just last year. Searchinger says that meeting the 2030 biofuels targets already set by major countries would require an additional land mass larger than New Mexico; meeting the International Energy Agency’s global goal of more than doubling biofuel production by 2030 could require another California.
The IEA also envisions a massive surge in renewable fuels in aviation and shipping, from less than 1% of global markets to as much as 15%, a recipe for an almost unfathomable assault on nature. The industry hopes to run half the world’s planes and ships on crops by 2050, which could require new farm fields eight times the size of California. Put another way, nearly one-third of the world’s cropland would be needed to generate a mere 2% of the world’s energy.
I’ve been banging my spoon on my high chair about the badness of biofuels since 2008, when I wrote a Time cover story on corn ethanol headlined “The Clean Energy Scam.” Honestly, the policy arguments are starting to bore me. It’s no longer news that producing biofuels can require nearly as much fossil fuel as they replace. It’s just common sense that when one farm grows fuel instead of food, another farm will expand to grow more food — usually into a carbon-rich forest or wetland, not a parking lot. I spend 50 pages of my latest book, “We Are Eating the Earth,” documenting the various ways scientists, economists, and bureaucrats in Washington, California, the European Union, and even the United Nations Intergovernmental Panel on Climate Change have cooked the books of climate analyses to make biofuels mandates look less catastrophic.
Nevertheless, farm-state Democrats like Sen. Amy Klobuchar of Minnesota and Gov. JB Pritzker of Illinois continue to tout biofuels as greener alternatives to fossil fuels. California under Gov. Gavin Newsom has promoted crop-based fuels through its “Low Carbon Fuel Standard,” even though corn ethanol and soy biodiesel are much higher-carbon than gasoline or conventional diesel. And while a few environmental groups have denounced Trump’s latest favors for the industry, most of the environmental community has remained silent, even as they’ve trashed Trump’s other environmental sins.
I get it. Fighting the farm lobby can feel like a waste of time and political capital. But biofuels are an excellent fight to pick, and now that they’re poised for a gigantic growth spurt in the U.S. and abroad, this would be an excellent time to pick it. Most farmers don’t vote for Democrats anyway. Agricultural expansion is an enormous environmental problem, driving biodiversity loss, nutrient pollution, water shortages, and climate change. And at a time when Americans are furious about high food prices — which helped Trump get elected, and have helped make him unpopular — biofuels mandates are specifically designed to increase the cost of things farmers sell and consumers buy.
None of this will persuade Trump or his Republican lackeys, who don’t care about the climate or the rainforests and won’t do anything to offend their farmer base or agribusiness donors. But it is way past time for serious people who know that biofuels are an insidious boondoggle to start fighting to stop the madness. I’m specifically thinking of three groups that should suit up for battle:
Democrats. There used to be a lot of rural Democrats. There also used to be a deal in Washington: Urban Democrats supported biofuels and other farm goodies as long as Republicans supported food stamps. But rural America is now overwhelmingly Republican, and the GOP’s One Big Beautiful Bill Act blew up the deal, gutting food stamps while blasting even more cash into farm socialism; it even included language ensuring biofuels could still qualify for new subsidies no matter how much they expanded agriculture into nature. So why do Democrats continue to support these environment-wrecking handouts for rich farmers who will never vote for them? Maybe it’s understandable that a corn-state Democrat like Klobuchar is now clamoring to permanently increase the ethanol levels in U.S. gasoline from 10% to 15% in order to cushion the blow from soaring gas prices — though she was clamoring for that long before gas prices were soaring — but why isn’t the rest of the party saying no?
Democrats need a new approach to agriculture, focused less on the 1% of Americans who farm and more on the 100% who eat. That would mean redistributing less money from ordinary taxpayers to the biggest farmers who grow the most common row crops, while also opposing the tariffs, price supports, and biofuel mandates that raise prices at the supermarket. Let Trump stand for giving farmers “much better than a level playing field.” Democrats should stand with everybody else.
Environmentalists. Green groups enthusiastically supported the original Renewable Fuel Standard in 2005, back when biofuels looked like an eco-friendly alternative to fossil fuels. To their credit, most of them stopped pushing farm-grown fuels after Searchinger’s science revealed their downsides. European enviros have actually fought back, successfully limiting crop-based fuels on the continent’s roads and excluding them from “sustainable aviation” mandates. But while a few American groups have also sounded alarms — most notably Friends of the Earth, Earthjustice, the Center for Biological Diversity, and the World Resources Institute — most have been silent, or have lobbied for relatively modest tweaks to state and federal mandates. I found no mention of Trump’s latest expanded biofuels mandate on the websites of the Natural Resources Defense Council, World Wildlife Fund, or Environmental Defense Fund, even though it will have a big impact on natural resources, wildlife, and the environment.
This strategy is designed to avoid alienating the powerful farm lobby, even though Big Ag routinely fights environmentalists over climate, wetlands, toxic chemicals, and other issues. And the strategy hasn’t entirely backfired; although biofuels quickly seized about 3% of the global fuel market by 2010, their market share has remained stagnant ever since. But that’s mostly because of the rise of electric vehicles, and the new push for biofuels in planes and ships, which can’t be easily electrified, is a huge new threat to nature and the climate. That’s what enviros are supposed to fight for, even if it means fighting Big Ag.
International institutions. In “We Are Eating the Earth,” I quote several scientists who worked on IPCC reports complaining that their panels were stacked with biofuels advocates who fought desperately to make sure the fuels were endorsed as climate solutions. Someone could write a whole book about that alone, but the long story short is that IPCC reports tend to point out that critics believe crop-based biofuels won’t reduce emissions at all, while supporters believe biofuels can reduce ludicrously massive amounts of emissions — and then suggest the world should aim for something in between to achieve its net-zero goals, which still amounts to a pro-biofuels stance. The IEA and other global institutions have taken a similar approach.
The scientists who still claim biofuels are good for the climate tend to assume they’ll make food so expensive that poor people won’t be able to afford as much meat, which would be bad; or that higher crop prices will miraculously enable farmers to grow way more crops without using more land, which isn’t grounded in empirical reality; or that farmers who do clear more land will somehow avoid carbon-rich forests, which is more wishful thinking. The science is clear, even if it isn’t comforting. It’s true that net-zero will be much harder to achieve if we can’t assume emissions reductions from biofuels. Unfortunately, we can’t, and the sooner credible institutions recognize that, the better.
So that’s my advice. Democrats should stop trying to suck up to farmers who will never love them back. Enviros should stop shying away from a war with Washington’s most powerful lobby. And climate institutions should abandon the most politically popular climate solution even though it will make climate progress look even less achievable.
I can’t pretend that any of this will be easy. If it were, it would’ve happened already. The fact that biofuels are crass political payoffs is one of those things just about everybody in Washington knows but hardly anybody wants to try to change. I’m genuinely not sure change is possible, but I’m sure it won’t happen if nobody tries.
Enormous new batteries keep appearing on the grid, making it devilishly tricky to keep track of which is the biggest in a given region. That’s certainly the case in New England, where acute power needs and robust state climate goals are fueling a buildout of big batteries that keep breaking capacity records.
Canary Media recently covered the inauguration of the 175-megawatt Cross Town battery in Gorham, Maine, which was the largest in New England when it began operating in late November. But that trophy has already passed to a 250-megawatt facility in Medway, Massachusetts, southwest of Boston and about 10 miles from the Patriots’ Gillette Stadium.
The Medway battery came online fully Feb. 25, according to developer VC Renewables, a subsidiary of global energy trader Vitol.
“To be fair, I don’t expect Medway to hold that title for very long, either,” said Tom Bitting, managing director at Advantage Capital, which supported the project with a $158 million tax equity deal. “There are other batteries being developed in New England that are bigger, but I think it is all just a sign that we need all of it, and there’s huge demand for it.”
For instance, Jupiter Power, a heavyweight in Texas’ booming grid storage market, is developing the 700-megawatt/2.8-gigawatt-hour Trimount battery plant at a former oil-storage site in Everett, Massachusetts, just north of Boston. Jupiter aims to finish the project in 2028 or 2029. Trimount is slated to be among the largest stand-alone batteries in the whole country — Vistra’s battery in Moss Landing, California, set that record with 750 megawatts/3 gigawatt-hours, before much of that capacity burned up in a disastrous fire.
The wave of battery megaprojects marks a new chapter for the region, which until recently was focused on building small-scale batteries. Massachusetts encouraged this by requiring energy storage alongside many distributed solar projects that received payments through the state’s main solar incentive; this rule led to a buildout of systems in the range of 1 to 5 megawatts.
Bigger batteries started taking off in the late 2010s out West: in California, Arizona, and Nevada, where developers can sign long-term contracts to deliver grid capacity; and in Texas, where they can bid into a uniquely competitive market.
The first three big batteries in New England — Plus Power’s Cranberry Point and Cross Town, as well as Medway, which was previously developed by Eolian — won seven-year contracts in 2021 to provide capacity for the New England grid, but the grid operator subsequently shortened that kind of contract to one year. After that change, developers have struggled with the lack of long-term capacity revenue; they can still charge up when prices are low and sell when they’re high, but that’s an unpredictable revenue stream that financiers might not want to underwrite.
Massachusetts has succeeded in building a robust fleet of small-scale solar — on recent sunny spring days, it has generated close to 50% of the region’s demand. But leaders knew they needed batteries to keep cleaning up the grid in the hours when solar doesn’t produce. So they created a new policy driver for storage investment called the Clean Peak Standard, which officially took effect in 2020.
The rule orders utilities to serve a percentage of their peak-demand hours with clean electricity, and the target grows with each passing year. Companies that use batteries to save solar energy for the evening — when electricity consumption rises as people get home from work and school — earn credits that they can sell to utilities, providing some revenue certainty outside the wholesale market.
The administration of Gov. Maura Healey, a Democrat, views storage as a key lever to improve energy affordability, Undersecretary of Energy Michael Judge said, because it makes better use of existing grid infrastructure to meet peak demand.
“Store all that solar energy that we’re producing in the middle of the day and bring down the cost of operating the system for everyone,” he said. “You don’t have to run these peakers, and you get all the emissions benefits and integration of clean energy benefits, too.”
It took several years for the rule to actually spur batteries in the multihundred-megawatt range, but now that era has begun. Advantage Capital, for example, factored in revenues from the Clean Peak Standard when it analyzed and underwrote the investment in the Medway project, Bitting noted. A total of 725 megawatts of battery storage had qualified for the Clean Peak Standard as of early March, according to state data.
Stand-alone grid battery projects are also bolstered by a federal tax credit that can cut investment costs by 30%, an incentive that the Trump administration preserved in last summer’s budget law even as it slashed support for wind, solar, and electric vehicles.
Clean Peak cash alone doesn’t pay the bills; battery developers still need to make money in the marketplace. Though New England lacks long-term capacity contracts, storage companies in the region have at least two factors working in their favor: some of the nation’s highest electricity prices and growing demand for power.
“It’s very difficult to get additional generation online in an area with high population density, because regardless of what type of power generation you’re building, it requires a lot of space,” Bitting said. Batteries, though, can fit a lot of power into a relatively small footprint, without the smokestacks or pollution that make it hard to build new fossil-fueled plants in populous areas.
Batteries compete directly with gas power plants to serve the peak hours of demand, when prices are highest. That’s especially valuable in New England, where gas supplies are stretched thin between power generation and home heating on the coldest days of the year.
“When it’s cold, the households are going to continue to demand it,” Bitting said. “But if we can ease some of the peak on the utility side, that will provide a relief valve to supply.”
Jupiter Power’s colossal Trimount project will continue New England’s foray into large batteries, with the ability to discharge enough power for roughly 500,000 homes, per the developer. Trimount was the largest of four battery projects selected in December from Massachusetts’ statewide solicitation to bring on more Clean Peak power. Previously, battery owners could sell off their Clean Peak credits on a quarterly or annual basis. The new solicitation was designed to produce “cost-effective” long-term contracts for storage, giving developers more stable revenue to plan around. Furthermore, Healey doubled down on grid storage in a March 16 executive order that calls for another 5 gigawatts installed by 2035.
“That kind of policy signal, combined with the state’s grid reliability challenges and its decarbonization commitments, creates the conditions for investment at scale,” Hans Detweiler, senior director for development at Jupiter, said in an email.
Massachusetts officials also hope to speed development with new permitting rules, which run large battery applications through a state-level body instead of piecemeal local processes. Community members still get to weigh in, but the program has a clear 15-month timeline and allows just a single appeal to the state Supreme Court, to ensure a more timely resolution of conflicts in the permitting process.
The true test of all these policies will be whether the recent megabatteries kick off a trend, or remain bold outliers in the region’s energy system.
After years of negotiations, data centers and other large customers of Georgia Power have finally won a pathway to pay for their own new clean energy projects to be built and connected to the utility’s grid.
The Georgia Public Service Commission approved the utility’s program last week, allowing these companies to identify and commit to paying for solar, battery, and other renewable-energy projects to supply their own power needs.
If it works as planned, the new customer-identified resource, or CIR, program could help prevent data center growth from raising power bills for Georgia Power’s customers at large — and offer a template for other utilities and regulators wrestling with similar issues nationwide.
Georgia Power is planning one of the largest new fossil-fuel buildouts in the country. Over the next five years, the utility wants to build nearly 10 gigawatts of new capacity resources, roughly 60% of which would come from natural gas power plants. The utility says it needs this new capacity to keep the grid running as power-hungry data centers flood into the state.
Those new power plants may be justifiable if the proposed data centers get constructed and keep operating long enough for the utility to recoup the costs through electricity sales. But if the AI bubble deflates, as more and more industry observers fear will happen, then the cost of paying off those utility investments could fall on everyday customers.
Programs like CIR are meant to protect customers at large from that worst-case scenario as well as from upward pressure on utility rates linked to data centers.
Its effectiveness on that front will depend on whether it results in Georgia Power building a smaller amount of electricity infrastructure than it’s currently planning on through its normal processes, thus reducing cost burdens on customers.
But that effectiveness will be hard to measure, given how the program is designed. Under the program, Georgia Power does not have to include any CIR projects in its long-term grid planning. If regulators don’t rectify that and force the utility to incorporate those projects into its plans, it may wind up adding gigawatts of unnecessary power plants in addition to whatever clean energy moves through the new program. Customers at large would foot part of the bill.
This issue will likely come to a head in Georgia Power’s next integrated resource planning process — the sprawling regulatory proceedings aimed at determining how much power, and what mix of resources, a utility needs to develop or maintain to meet its future needs.
Still, the unanimous vote approving CIR indicates that state regulators want Georgia Power to “work with large loads on the system in a way that manages cost shifts and concerns related to affordability,” said Nidhi Thakar, senior vice president for policy at the Corporate Energy Buyers Association (CEBA), the trade group that negotiated with the utility to create the CIR program.
CEBA includes major hyperscalers — like Amazon, Google, Meta, Microsoft, and Oracle — that signed a “ratepayer protection pledge” at the White House last month, promising to limit the risk that their data center expansion plans will increase everyday utility customers’ electricity rates. But most of the actions that could actually fulfill that pledge will rely on efforts from individual states and utilities, energy experts say — such as the CIR program from Georgia and Georgia Power.
“These large customers are willing to put down capital on the front end and take on the risk” to build the clean energy to supply significant portions of their demand, said Katie Southworth, CEBA’s deputy director for market and policy innovation in the South and Southeast. “This program opens up the procurement pathways.”
Starting this summer, large commercial and industrial customers in Georgia Power’s territory can use CIR to seek out and work directly with independent developers of solar, wind, battery, geothermal, and other carbon-free energy projects, Southworth said.
That’s a first for Georgia Power. As with many utilities in the Southeast and Midwest, it is vertically integrated, meaning it has exclusive rights to contract for power plants. The utility already lets big customers subscribe to clean energy projects that Georgia Power selects and contracts with, but it hasn’t previously allowed customers to bring their own specific clean energy projects to the table.
States without vertically integrated utilities let independent power producers contract directly with big customers. Big power users, and tech giants in particular, have taken advantage of this arrangement where available. U.S. corporate clean-energy procurement surpassed 130 gigawatts of new generation capacity between 2014 and 2025, according to the latest CEBA data. That’s roughly 44% of all new generation capacity built in that time, CEBA told Canary Media.
Under the CIR option, these large customers still won’t directly purchase energy from the projects that they have identified. Instead, they will pay Georgia Power a monthly tariff designed to cover the projects’ construction and operating costs, plus a reasonable rate of profit for the projects’ owners, in an arrangement CEBA likens to a “sleeved power purchase agreement.”
Solar and batteries will probably make up the lion’s share of that new CIR capacity, given that more than 20 gigawatts of those resources are being developed and seeking interconnection in Georgia, according to data from the Southern Renewable Energy Association trade group.
Solar and batteries are also the cheapest source of new generation capacity available nationwide, which could drive lower energy costs for the big customers contracting for it and for Georgia Power customers at large. Together, solar and batteries are expected to account for nearly 90% of new energy capacity built nationwide this year.
Under the CIR structure, if the power from these projects is cheaper than the equivalent cost of power generated and delivered by the utility, 75% of the resulting savings will go to participating customers, while 25% will be shared with other Georgia Power customers, Southworth said.
That could help get large-load customers — namely AI data centers — the massive amounts of energy they need without increasing utility rates for customers at large.
Georgia Power’s previous renewable-procurement structures have helped “diversify our generation mix and increase reliability,” Wilson Mallard, the utility’s director of renewable development, told Canary Media in an email. Adding CIR to those existing structures “offers the opportunity for the procurement of additional renewable resources at competitive prices to meet customer needs,” he said. “We expect these projects will provide energy and capacity benefits to the system value for all Georgia Power customers.”
CEBA fought for some key features that made it into the final CIR program approved by Georgia regulators last week.
For one, Georgia Power removed a contentious provision that would have allowed the utility to terminate CIR contracts at any time and without penalty, Southworth said.
Additionally, small commercial and industrial users of power can now band together to collectively achieve the 3-megawatt minimum required to participate, Southworth noted. That could expand options for retail chains, hotels, local businesses, or local governments to secure their own clean energy resources. And customers will be allowed to transfer in and out of those arrangements, which allows for more flexible participation.
But CEBA wasn’t able to secure one feature it had wanted — a way for CIR customers to earn credits for the capacity value of the projects they bring online. Capacity is how utilities measure the impact that power plants, solar and wind farms, batteries, and other resources have on meeting the peak demands on their grid.
Those peak demands are important because they determine how much generation and grid infrastructure that utilities ultimately build. What’s more, large utility customers typically have to pay demand charges, which are based on how much power they use during those handful of hours when electricity use hits its upper limit.
The CIR program’s monthly tariff is an energy-only tariff. That means participating customers won’t be able to reduce their demand charges on the basis of the projects they’ve enabled to be built under CIR — even if that infrastructure helps Georgia Power reduce its peak demand.
But sooner or later, Georgia Power and its regulators will need to consider how to capture the grid value these CIR projects provide.
That’s likely to play out in the utility’s future integrated resource planning, Southworth said. “When we get to the next IRP, I’m confident there will be some resources — solar and storage — that will be brought on” under CIR, Southworth said. “Those will be resources on the Georgia Power system, and through that modeling, they will absolutely show up” as part of the capacity calculations.
The question then will be whether that newly unveiled CIR capacity will alter Georgia Power’s current power plant expansion plans, which were approved in December through a regulatory process that has unfolded largely outside the utility’s standard IRP proceedings. Georgia Power and regulators justified this approach to deal with a massive increase in the utility’s forecasts of how much power and capacity it will need to supply in future years, which have surged from 400 megawatts in 2022 to 6.6 gigawatts in 2023 to 8.5 gigawatts in 2025.
But environmental groups, consumer advocates, and others say Georgia Power’s latest expansion plan for gas power plants and batteries allows the utility to overbuild for a data center boom that may fail to emerge. Georgia Power will be able to earn guaranteed levels of profit on the $16.3 billion in “company-owned projects” in that plan, giving it an incentive to overestimate its power needs.
Last month, a group of environmental and faith groups brought a legal challenge against the decision. “The commission still has to apply its rules to protect its ratepayers from overbuilding,” said Isabella Ariza, a staff attorney with the Sierra Club, one of the groups filing the legal challenge. “And we think those rules are the only protection that ratepayers have at this point.”
Ariza noted that the final version of the CIR program wasn’t yet posted by the Public Service Commission, which limited her ability to discuss how the resources brought online under the program might impact future capacity planning.
Even so, “in future IRPs, Georgia Power would have a hard time theoretically explaining to the commission why the clean resources shouldn’t offset some of the peak demand,” she said. “But we’ll see.”
A correction was made on April 15, 2026: This story originally misstated that Georgia Power has exclusive rights to build and operate generation in its service territory. In fact, the utility also contracts with third-party solar and battery projects under its CARES program.
Stegra has secured the financing needed to complete its flagship green-steel mill in northern Sweden.
The company, formerly H2 Green Steel, said it landed 1.4 billion euros ($1.65 billion) in capital from a group of new and existing investors led by Sweden’s prominent Wallenberg family. The funding will enable Stegra to finish building and commissioning its novel facility in Boden, just south of the Arctic Circle.
The project is a cornerstone of Europe’s broader ambitions to decarbonize its industrial sector and lead the world on lower-emissions technology. Conventional steel mills rely heavily on coal to produce the ubiquitous metal, making them a major source of planet-warming emissions and harmful air pollution.
Stegra’s first-of-a-kind project will instead rely on green hydrogen, which could slash carbon emissions from steelmaking by up to 95%, compared with traditional coal-based furnaces.
The sprawling facility will use giant electrolyzers, powered by the region’s ample hydro and wind energy supplies, to split water molecules and produce the clean fuel. That hydrogen will then turn raw iron ore into lumps of iron, which will be melted and made into steel in electric arc furnaces, also powered by renewables.
Stegra said it expects to initially produce 2.5 million metric tons of steel annually and eventually double its production of the metal.
The ambitious undertaking has hit some serious snags since construction began in 2022. Stegra previously raised some 6.5 billion euros ($7.64 billion) in loans and equity. But in recent months, faced with rising project costs and delays, the firm had been urgently seeking additional financing to address a growing cash crunch.
In October, the French hydrogen investor Hy24 swooped in to help fund Stegra for an undisclosed amount. That still wasn’t enough to stave off financial troubles for the steelmaker, which has batted away frequent rumors that the company and its marquee steel mill were close to collapsing.
With the new investment from the Wallenberg-led consortium, Stegra says it will now ramp up construction activities following several slower months during its fundraising period. As of last fall, the plant was 60% complete.
The company says the project’s timeline is now “under review,” though Stegra CEO Henrik Henriksson said it will take about 18 to 24 months to start producing steel once the facility is finished, the Sweden Herald reported.
Before its financial woes began last fall, Stegra was planning to complete the steel mill by late 2026.
“As an industrialist, you get a little sad if you come up to Boden now, because there is a half-finished steel mill that is running at perhaps a quarter of the speed it should be running,” Leif Johansson, an adviser to the investor consortium, said at a press event this week. The funding lifeline should change that.
The news comes four months after the European Union’s world-first carbon border tax went into effect. The policy makes it more expensive for European companies to import steel from countries that don’t have carbon-pricing systems, like the EU does, all of which should benefit domestic low-emissions steel producers like Stegra.
“We are convinced of the competitiveness of Stegra and the commercial attractiveness of green steel in addition to the climate benefits, while remaining clear-eyed about the challenges that lie ahead,” Johansson said in a separate statement. “We also consider the project to be of great importance to Sweden’s position as an industrial nation.”
Green steel proponents applauded the news of Stegra’s financing round, which is expected to formally close in June after undergoing credit and regulatory approvals.
“Stegra securing the future of its Boden green steel plant is a welcome development that signals the change towards truly clean steelmaking at scale is happening,” Caroline Ashley, executive director of the nonprofit SteelWatch, said in an emailed statement.
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