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In January, Lerned Zint’s gas water heater croaked.
It would have been an inconvenience for anyone. For Zint, a Spanish-speaking mother who runs Corazones Daycare out of her San Francisco home, it was an emergency.
Zint takes care of about 10 children, 6 months to 4 years old. Their sticky fingers and stinky messes make hot water essential.
Thankfully, Zint didn’t have to wait long for a solution. Within days, the San Francisco Environment Department worked with a partner contractor to install a shiny new water heater in her home at no cost — and it runs on an electric heat pump, not gas.
Zint is the first participant in the city’s new electrification pilot program for child care centers run out of residential homes. Led by the Environment Department and funded by a TECH Clean California Quick Start Grant, the $300,000 program will swap gas water heaters for heat-pump options at up to 30 facilities. The initiative could be a model for other communities around the country looking to decarbonize their buildings and thereby give their children access to cleaner, safer air.
Electric upgrades can’t come soon enough to the disadvantaged communities the new initiative is prioritizing.
Zint lives in the Excelsior neighborhood, which not only has the highest number of children up to 5 years old in the city but also carries “a disproportionate share of environmental burdens from high pollution,” Supervisor Chyanne Chen, who represents the neighborhood, said during a March press event. This initiative improves indoor air quality, reduces emissions, lowers energy costs, and modernizes child care facilities, she noted. That “means healthier providers, healthier children, and a healthier neighborhood.”
By their nature, appliances that burn material — fossil fuels, charcoal, wood — spew toxic compounds that chronically harm health. The pollutants, from oxides of nitrogen to carbon monoxide, can damage nerves, increase asthma symptoms, heighten the risk of stroke and dementia — and even kill.
For children, whose lungs and immune systems are still developing, the health impacts of gas-appliance pollution are particularly grave. Gas stoves, which often aren’t required to vent outside, are the biggest threat: They can increase any person’s chances of getting cancer, but the risk for kids is nearly double that for adults. Water heaters, furnaces, and dryers fueled by gas pose risks, too.
Low Income Investment Fund, a national community-development financial organization that is helping the Environment Department implement the program, has recently become acutely aware of how ubiquitous these dangers are. “Most of these child care programs, they’re running their stoves more than half of the day, because they cook for the children,” Katherine Perez, a LIIF program officer who is aiding Zint with electrification, told Canary Media.
To date, the Environment Department has installed five heat-pump water heaters under the program and aims to complete all 30 by the end of the year.
After that, LIIF will incorporate learnings from the pilot to update its existing Child Care Facilities Fund, which can go toward renovations and repairs. The grant program awards up to $100,000 per home child care business, with the requirement of a 20% copay. This funding has come to the aid of providers when their appliances break down, and historically has been used to replace gas equipment with gas equipment.
But the nonprofit has started to encourage participants to replace their broken appliances with electric options across the board.
“We haven’t formalized our policies in regards to electric appliances for homes,” said Kimberly Thai, a LIIF program manager. “But it is our practice to fund appliances that improve indoor air quality.”
About 500 child care programs across San Francisco are eligible for LIIF’s facilities grants.
As part of the electrification pilot, the Environment Department is also providing training to the local workforce. Up to 10 San Francisco contractors will gain experience installing heat-pump water heaters in child care facilities, which require more creative scheduling than typical homes, according to Benny Zank, the department’s building decarbonization coordinator and the lead for the pilot. Those skills will equip them to serve many more homes in the future.
San Francisco will need electrification-savvy contractors to fulfill its public health and climate ambitions. Bay Area air quality regulators are finalizing the details on landmark rules that will phase out the sale of new residential gas water heaters starting in 2027 and gas furnaces in 2029.
In just 14 years, the city plans to achieve net-zero-emissions. As of 2022, buildings still accounted for nearly half of its climate pollution.
For her part, Zint is thrilled with her heat-pump water heater and plans to fully electrify her home, she said, as Zank translated. LIIF is assisting her with that transition, which entails replacing a gas-fired furnace, stove, and clothes dryer, in the coming weeks, Perez said.
The appliances create a safer environment for the children, Zint noted. “Especially, they reduce the risk of carbon monoxide poisoning, which is really important when taking care of kids.”
Word of Zint’s electrifying update is spreading. “A bunch of other child care providers have reached out to me,” she said, asking about how they can ditch gas appliances, too.
“We make sure to share all this information with each other,” she added. “We’re a real community who all care about the health and safety of the kids that we take care of.”
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
Cache Energy installed its thermal battery at the University of Minnesota, Morris, where it stores energy from the campus’ two wind turbines and releases it to heat a carpentry workshop. (University of Minnesota, Morris)
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
“It’s windy year-round here in western Minnesota,” said Troy Goodnough, the school’s sustainability director.
Together, Bert and Ernie crank out 10 million kilowatt-hours of electricity annually. According to Goodnough, UMN Morris consumes about half the output and sells the rest to the Otter Tail Power Co., the local investor-owned utility. Now, a first-of-its-kind thermal battery pilot is underway that, if scaled up, could help the campus use more of that juice while reducing the environmental impact of the sprawling methane-powered steam-heat loops that keep it cozy through Minnesota’s bitter winters.
Late last month, technicians from Illinois-based Cache Energy arrived on campus to install the battery unit, which transforms electricity into intense heat. Its outlet temperature can reach 1,000 degrees Fahrenheit — more than hot enough to efficiently run a steam heating system.
It took two hours to position the shipping container that houses the unit next to the school’s carpentry shop, and then another few hours to connect the unit to the building’s electrical and duct systems. It powered up on March 24 and hasn’t stopped providing heat since, Goodnough said. Its task is not small, he added: The “warehouse-like” shop has high ceilings and several thousand square feet of floor space.
“The cool thing is it’s doing what it’s supposed to be doing,” he said. “It’s working great.”
The battery unit contains limestone-derived pellets coated in a proprietary binder that keeps them intact throughout their 30-plus-year operating life, according to Cache. When exposed to a stream of moist air, the pellets get so hot they “can be used to make hot air or even vaporize water to make steam,” Goodnough wrote last month. To recharge, the system uses electricity to dry out (and cool down) the pellets.
Ideally, that electricity is cheap, clean, and otherwise at risk of curtailment, said Sydnie Lieb, an assistant commissioner for regulatory analysis with the Minnesota Department of Commerce. Lieb’s agency helps fund Minnesota Energy Alley, a public-private partnership that supports the Cache project and other cleantech demonstrations in the North Star State.
“The most cost-effective place for thermal batteries is going to be where you have a lot of excess energy being produced where you don’t have a lot of transmission or [customer] load,” Lieb said.
Western Minnesota certainly fits the bill. The wind farms that dot the open, rolling landscape here and in neighboring North and South Dakota routinely produce more energy than the grid can handle. The Midcontinent Independent System Operator, the nonprofit that manages Minnesota’s grid, throttled hourly wind generation by an average of 508 megawatts in 2023, according to the U.S. Energy Information Administration. That’s the equivalent of what’s produced by about 160 newish onshore wind turbines. The Southwest Power Pool, which manages the grid for the wind-rich region stretching from North Dakota to the Texas Panhandle, curtailed wind output by an average of 1,097 MW that same year.
Arpit Dwivedi, Cache’s founder and CEO, said low-cost electricity helps make the economic case for customers to invest in thermal batteries rather than stick with equipment that runs on natural gas, which is also plentiful in the United States’ midsection.
“We know gas is cheap,” he said, and that’s a problem for tech developers looking to electrify heat.
Another issue for big energy users, like UMN Morris, is that switching from gas to electric heat means replacing massive, long-lived boilers — likely fully paid for — with new equipment that needs to be leased or financed.
That shift is necessary if the university is going to meet its aggressive climate goals of reducing greenhouse gas emissions by 87% by 2035 and reaching carbon neutrality by 2050, but it could incur a considerable balance-sheet burden. So from the outset, Dwivedi and his team were intent on reducing Cache units’ upfront cost, he noted.
“We knew that if we did not have a low-capex system, we would not have an economic advantage,” he said.
Like other emerging thermal battery designs, Cache’s uses low-cost — if heavy — materials that are widely available in the United States. The primary inputs are steel, lime, and water, all of which Cache sources domestically, Dwivedi said. The proprietary binder that keeps the lime granules stable is by far the most expensive input, so the company focused on keeping that cost in check. Its secret ingredients are available domestically, too, Dwivedi added.
Cache offers its battery as a lease product that it says bundles the battery unit, delivery, installation, maintenance, guaranteed uptime, and takedown “without capital burden.” Just as an automaker leases a passenger vehicle, Cache retains ownership of the battery unit during the lease term, after which the customer has the option to buy it or send it back.
Cache launched in 2022. For its first few years, space heating was a sideshow. Dwivedi and his team were more focused on the technology’s potential to electrify low- and medium-temperature process heat for food, chemicals, and other types of industrial production. To that end, Cache recently conducted a pilot at a Duke Energy testing facility in North Carolina that “[hosts] several interested industrial companies,” the company said last month in a news release.
Cache still works on industrial heat, but it’s also leaning into relationships with large space heating customers, particularly those with existing hot-water or steam infrastructure such as UMN Morris. That includes the U.S. Army, which is interested in the thermal battery’s ability to provide reliable backup for military installations at risk of extended power outages.
Cache was one of nine finalists in a demonstration cohort fielded last year by Grid Catalyst, a Minnesota-based clean energy accelerator that also supports Minnesota Energy Alley.
“Decarbonizing our heating in Minnesota stood out as a value proposition,” said Nina Axelson, Grid Catalyst’s president and founder. Cache’s technology, she noted, “is simple, less costly, and really effective on thermal storage and dispatch.”
Axelson said Grid Catalyst acted as a sort of “energy matchmaker” on the UMN Morris project, connecting university leadership with the Cache team. Front-end engineering and feasibility work required some time, she said, but once the university decided to move forward, it only took a couple of weeks to get the project up and running.
“It’s about as plug-and-plug as you get for thermal storage,” she said.
Dwivedi said that while the Morris system has been charging and discharging five or six times a day, the underlying technology can actually cost-effectively store energy for months on end. That’s a big selling point for customers serious about electrifying space and process heat.
Cache is fresh off a demonstration at an Alaskan industrial site, owned by oil and gas services firm Halliburton, that validated its batteries’ ability to hold heat for a long time in temperatures as cold as minus 40 degrees, Dwivedi said. That’s a critical proof point because the price of electricity — particularly on grids rich in renewables — tends to fluctuate throughout the year, he said. A Cache system could, for example, charge up on cheap power during a sunny, windy period in October, then wait to fully discharge until a dark, still spell in December, when local power prices are likely to be higher.
With a capacity of “several hundred kilowatts,” according to Dwivedi, the unit at UMN Morris is smaller than the industrial-scale ones that Cache hopes to sell at volume in the years ahead. The startup makes units as large as 5 MW and could deliver one to Minnesota in a few months if the university decides to expand the pilot, he added.
“We see this university project as a demonstration of one of the applications of this technology, and we can scale from there,” Dwivedi said.
A scaled-up, multiunit configuration could serve dozens of campus structures with a variety of uses. Some buildings have labs, swimming pools, and dehumidification systems that require heat even in the warm months, Axelson said.
In theory, Cache units could replace gas boilers on the campus steam system and complement a future hot-water loop powered by ground-source heat pumps — an increasingly popular cold-climate heating technology that Grid Catalyst is familiar with through Flow Environmental Systems, another 2025 cohort member that produces commercial-grade systems using low-impact refrigerant. A hybrid system could more efficiently distribute thermal energy between buildings and optimize campus heating in the depths of winter, “when you need all the heat you can get,” Axelson said.
“We are looking at using this as a showcase project so that our utility, industrial, and campus partners can see it in operation,” she said. “It’s hard for folks to be first, but when you do take that first project, you really open the gates.”
As UMN Morris undertakes a comprehensive review of its energy usage, Cache’s thermal batteries are among several technologies that could factor into a “Swiss Army knife solution” for sustainable heating, cooling, and power, Goodnough said.
On paper, it looks daunting to fully decarbonize a campus whose gas-fueled heat network uses three to four times more energy than all its electrical equipment put together, Goodnough said. But the university has steadily added on-site renewable capacity, including a 500-kW solar array that “we think is the largest agrivoltaic field in the Upper Midwest,” he said.
In the not-too-distant future, it could have far more homegrown electricity to play with.
“It’s not inconceivable that Bert” — the older windmill — “could be replaced by a 5-MW turbine,” Goodnough said. If Ernie meets the same fate, UMN Morris would roughly triple its on-site wind capacity. Goodnough believes that would be a tremendous opportunity not only for the university but also for rural communities nearby.
“Out here in rural Minnesota, you see storage everywhere: grain elevators, propane tanks, fertilizer bins,” he said. “The energy transition will demand lots of different kinds of storage. It’s a natural fit for us.”
Chaz Weatherford has a busy schedule. On a typical workday, the solar inspection technician for major U.S. rooftop solar company Freedom Forever drives to eight or nine homes across southern Arizona, checking to make sure their newly installed solar systems are safely configured and ready to turn on. Sometimes it’s hard to stay on schedule — especially when he has to wait around for hours for a city or county inspector to show up to review his work.
An employee of Lumina Solar uses his smartphone to conduct a remote video inspection of a rooftop solar installation in Baltimore County, Maryland. (Lumina Solar)
But at homes within the jurisdiction of Pima County, Arizona, Weatherford doesn’t have to wait very long. That’s because the county is one of a growing number doing remote virtual inspections, which cuts the time its inspectors need to approve home solar projects from hours to minutes.
Weatherford uses his smartphone camera to take photos and videos of everything on his inspection checklist: a home’s main electrical panel and the breakers within it, the disconnect switch, the electrical meter, and all the wires and conduits connecting them. Then, he sends those digital records to the county’s inspection office.
Soon after, “we get an email back saying if we’ve passed or not — and if not, there are instructions on how to fix it,” he said.
That’s good for Freedom Forever, for the homeowners who are installing solar, and for the county inspectors, he said.
Solar, battery, and home electrification advocates say the benefits of a virtual inspection make it a no-brainer policy. Any steps that can reduce the cost of rooftop solar are critical right now. Utility bills are rising nationwide, making home solar especially useful to households. But in the U.S., these systems are far more expensive than they are in most other countries. It doesn’t help that the Trump administration scrapped federal tax credits for rooftop solar last year.
Right now, just a few states have efficient permitting practices for rooftop solar and home battery projects, according to a recent report produced by advocacy nonprofits Environment America and Frontier Group.
While the report names streamlining installations via third-party and remote inspections as one of the top reforms, the approach is used by only a relative handful of the more than 40,000 county, city, and local permitting jurisdictions in the U.S.
Many of those jurisdictions allowing the remote reviews are in California, which was also the first state to pass an instant-solar-permitting mandate. Arizona, Florida, and Texas also have a significant number of jurisdictions that have adopted virtual inspections; New York state’s NY-Sun solar and storage subsidy program requires them as a follow-up to on-site local inspectors.
The number of jurisdictions using the technique is likely to grow. A half dozen states have advanced or are considering bills to reform solar and battery permitting this year, according to Permit Power, a nonprofit that advocates for permitting reform for residential clean energy. Several of those bills would impose mandates if passed, and some would offer state support for jurisdictions that adopt virtual inspection.
One such bill is already poised to become law. In Maryland, a bill to streamline solar and battery permitting was wrapped into a broader energy package that passed the state’s Democratic-controlled legislature this month and now awaits the signature of Gov. Wes Moore, a Democrat.
“You’re seeing a real movement across both plug-in solar and more traditional solar and batteries to knock down the barriers and red tape that get in the way of American families buying and installing those systems,” said Nick Josefowitz, CEO of Permit Power.
The old adage is as true for solar permitting as it is for anything else: Time is money.
That’s why remote virtual inspections can add up to big savings, according to an exhaustive report from the Interstate Renewable Energy Council, a nonprofit clean-energy advocacy group. Using technology for virtual inspections can reduce costs by more than $30,000 per inspector annually, according to IREC, cutting expenses on vehicles and fuel as well as enabling inspectors to do roughly three times as many inspections per day.
Daniel Ice, a deputy director at Pima County’s development services department, certainly sees the savings on the ground. His office started doing virtual inspections for residential air-conditioning installations more than a decade ago, and has gradually expanded it to more tasks.
“We’re a large county — our inspectors were driving up to 150 miles per day,” he said. “This saved on our vehicle and fuel costs — and we could do more inspections.”
Like most building inspection departments, Pima County has more work than it has employees to do it, Ice said. Spending less time on everyday home solar inspections “freed up the planners to work on more complicated projects.”
Permit Power and other advocates want Pima County to become the rule — not the exception.
Statewide bills like Maryland’s are a good start to making that happen, said Erin Kelly, vice president of residential operations at Lumina Solar, an installer based in the state.
Maryland’s legislation will require counties to adopt online solar permitting by mid-2027, and it includes requirements that counties that can’t meet five-day turnarounds for these permit applications by mid-2028 “must offer a remote inspection option that provides inspection within five business days of a request.”
A few Maryland counties already offer virtual inspections, which have “saved a ton of time, a lot of headaches,” Kelly said. That’s particularly useful for follow-up inspections, which installers can respond to by fixing identified problems and sending in video evidence on the same day. Other counties, by contrast, can take from a day to more than a month to schedule on-site inspections and follow-ups, she said.
Not all Maryland counties are happy about adopting virtual inspections or online solar permitting, however. The Maryland Association of Counties warned state lawmakers in a March letter that “a highly prescriptive state mandate could undermine local flexibility, strain budgets, and compromise safety safeguards.”
Carla Blackwell, who led Pima County’s adoption of virtual inspections and instant solar permitting as director of its development services department before retiring last year, understands those concerns.
“We always hated when the state legislature got involved and passed some sort of mandate,” she said. “If you want to get people on board, you have to get them involved and part of the process — both so that they understand and support it and so they don’t sabotage it in some aspect.”
Pima County started using these technologies out of necessity, she added. The 2008 real-estate market crash forced her department to lay off about two-thirds of its staff, forcing it to find ways to do more with fewer employees.
It took some work. The county had to upgrade its permit management software to handle the new digital inputs, for example. That might not be a welcome prospect for smaller permitting agencies, she said. “The minute you mention IT to a government department, they’re like, ‘Uh-oh, I don’t want to deal with those guys.’”
But once the software is in place and employees are trained in using it, virtual inspections can improve the quality of work being done, she said. “I actually spend more time with you on these remote field inspections than if I had to drive out, spend five minutes, and then drive to the next one.”
Creating digital records of the projects can also help inspectors catch errors that brief on-site inspections can miss, she noted. That’s backed up by IREC’s report, which cited multiple building department officials affirming the benefits of being able to review photos and videos to do quality checks.
That’s true for more than solar and battery installations, said Colleen Corrigan, sustainability and resilience policy manager at the nonprofit San Francisco Bay Area Planning and Urban Research Association (SPUR). Her group and Permit Power are co-sponsoring a state bill that would give California homeowners the option of requesting remote inspections for water heaters, heat pumps, and rooftop solar installations. SPUR is also supporting another bill that would streamline permitting for heat pumps and plug-in solar systems.
“Permitting and inspection delays are these quiet but significant barriers to climate progress,” Corrigan said. The bills SPUR supports are aimed at “removing the friction at these key choke points in electrification,” she said.
But they’re also “rooted in best practices in jurisdictions already doing automated permitting or virtual inspections,” she added, as is happening in at least 19 places statewide, ranging from cities like Los Angeles and San Diego to rural areas such as Placer County in the Sierra Nevada.
Gabe Armstrong, acting chief building official at Placer County’s Community Development Resource Agency, estimated that the agency is eliminating about 3,900 driving miles per year by using remote video inspections. It also offers them on the same day that projects are completed, which is convenient for contractors who don’t want to have to come back the next day just to meet an inspector.
Armstrong’s agency also retains the right to show up in person to check the work, which it does from time to time as part of a quality-control audit, he said. To ensure contractors aren’t misrepresenting their work, “we only do live video inspections,” he said. “We need to know we are at the right jobsite, not looking at some random photo.” If contractors aren’t being honest, “we’ll turn them into the state contractor licensing board — and we’ll ban them from the RVI program.”
Some projects, like new home builds, require on-site visits, he said. And inspectors will still come out in person if the contractor or property owner requests it. But for approved projects like solar panel systems and heating, cooling, and air-conditioning installations, “we have these really large monitors, and we’ll pull up the plans on one side, and we can zoom in and read all the notes — and we can also zoom in on the work being inspected.”
Using video taken from solar installers on rooftops also avoids having to send inspectors up there to check their work, which eliminates safety hazards, Armstrong added. As for contractors, “usually once we get someone doing it, they become a repeat customer,” he said. “Being able to pick the exact inspection time — think about how much money you’re saving.”
Offshore wind development has all but screeched to a halt in the United States amid the Trump administration’s unrelenting attacks. But in the rest of the world, it’s another story.
Wealthy and developing economies alike are embracing the energy source as they look to build out supplies of domestic and renewable electricity — a goal that is growing more urgent as the Middle East conflict leaves many nations short on oil and natural gas.
Global offshore wind capacity rose by over 9 gigawatts in 2025, up 16% from the previous year’s installations, bringing the world’s total offshore wind capacity to about 92 GW, the Global Wind Energy Council said in its latest annual report, released Monday. Land-based wind projects saw record gains, adding over 155 GW in 2025.
All told, nearly 1,300 GW of wind turbine installations are now providing power to nearly 140 countries worldwide, according to the international industry group.
About half that cumulative capacity — both offshore and on land — comes from China, which is building renewable energy at a breakneck speed to meet its surging power demand and reduce its reliance on fossil fuels.
The United Kingdom is also a global leader for offshore wind in particular. It added over a gigawatt last year, bringing its total offshore capacity to nearly 17 GW. In January, the government moved to grow that figure further, awarding 8.4 gigawatts’ worth of contracts to project developers. The auction, which was Europe’s biggest for offshore wind to date, set power prices that will be significantly cheaper than those from a new gas-fired power plant.
The U.K. joined nine European Union nations earlier this year in vowing to build 100 GW of the resource to transform the gusty North Sea into “the world’s largest clean energy reservoir” in order to help meet the region’s climate change targets.
Other land-constrained nations, primarily in Asia, are poised to propel the fledgling industry forward in the coming years. Japan, the Philippines, South Korea, and Vietnam have all recently launched auctions and programs to install gigawatts’ worth of turbines to power their growing economies and curb their dependence on oil and gas imports.
“Despite what you hear from the White House, offshore wind is alive and well,” said Rebecca Williams, deputy CEO of the Global Wind Energy Council. “Across a new set of emerging markets, we’re seeing governments really double down on momentum, and we’re also seeing that from the usual suspects.”
Globally, offshore wind installations are expected to continue growing over the coming years, albeit at a slower pace than once anticipated.
Between 2027 and 2030, countries other than China are expected to add an average of 11 GW in offshore wind installations every year — almost triple the levels from 2022 to 2024, according to the research firm BloombergNEF. China alone could add the same amount over that three-year period.
Farther ahead, the total capacity of offshore wind farms globally is set to reach about 486 GW by 2040, BNEF has forecast.
“In general, there is lots of negative news around offshore wind … but it is still a very, very large and global industry,” said Kajsa Jernetz, an offshore wind analyst at BNEF.
That negative news is real, however, with the most dramatic impact happening in the United States.
Since last year, President Donald Trump has halted new offshore wind leasing and tried, unsuccessfully, to stop construction of five in-progress wind farms in the U.S., three of which are now sending power to the East Coast’s grid.
Even before the politically driven attacks, project developers worldwide faced financial hardships and logistical challenges. High inflation and rising equipment costs, exacerbated by the Covid pandemic and Russia’s war in Ukraine, have made what are already multibillion-dollar energy installations even more expensive. Now, however, global energy firms like Denmark’s Ørsted and Norway’s Equinor have taken an additional hit after they were forced to pause work on fully permitted projects and cancel future developments off America’s Atlantic coast.
“That level of volatility is extreme when it comes to any infrastructure sector,” Williams said of the Trump administration’s actions, adding that they have had a “chilling effect on the offshore wind industry as a whole.”
Developers have reduced their investment budgets for the near term, due in part to U.S. headwinds but also to other major policy and supply chain challenges in China and Europe.
In 2025, companies won bids to build over 11 GW of future offshore wind capacity — one-fifth of the amount awarded in 2024, according to the Global Wind Energy Council.
For Europe in particular, “this is part of a bigger, negative spiral for offshore wind, where costs have increased, which means that projects get delayed, and in turn, project viability decreases,” Jernetz said. In response, Denmark, Germany, and the Netherlands announced plans to support developers by providing minimum revenue guarantees for offshore installations.
The energy crisis caused by the U.S.-Israeli strikes on Iran is expected to exacerbate some of the supply chain challenges faced by offshore wind — and every other major infrastructure project.
But on balance, the Middle East crisis is likely to bolster the case for investing in offshore wind, the CEO of Ørsted, Rasmus Errboe, told Reuters earlier this month. Errboe was speaking about Europe, where gas prices are surging again, four years after the region drastically cut imports from Russia, spurring a severe gas-supply crunch.
But the same is true for other regions that rely heavily on imported fossil fuels to generate electricity, Williams said. Southeast Asia, for example, is seeing fuel prices soar because of disrupted flows through the Strait of Hormuz, a choke point for much of the world’s oil and gas supply, which has prompted Asian governments to adopt price caps and ration reserves.
“What we’re seeing now is an urgent sense from countries around their own energy security, resilience, and the desire to have self-determination,” Williams said. “In this really shifting geopolitical landscape … that imperative becomes ever more acute, and that’s the dynamic we’re seeing play out.”
Perovskites hold a place of honor in the pantheon of much-heralded clean energy breakthroughs that have yet to actually arrive, alongside small modular nuclear reactors and solid-state batteries. In theory, these crystal structures could radically improve solar panels’ capabilities by absorbing wavelengths of light that conventional silicon cells can’t catch. But the stunning advances in R&D specimens have yet to infiltrate the cold, hard world of commercial solar manufacturing.
Tandem PV is now producing perovskite-coated glass panels 60 times larger than its R&D test size, in the hopes of commercializing highly efficient solar. (Tandem PV)
Perovskites hold a place of honor in the pantheon of much-heralded clean energy breakthroughs that have yet to actually arrive, alongside small modular nuclear reactors and solid-state batteries. In theory, these crystal structures could radically improve solar panels’ capabilities by absorbing wavelengths of light that conventional silicon cells can’t catch. But the stunning advances in R&D specimens have yet to infiltrate the cold, hard world of commercial solar manufacturing.
Startup Tandem PV is fighting to break that impasse with its new 65,000-square-foot perovskite factory in Fremont, California, the same Bay Area locale Tesla chose for large-scale electric vehicle manufacturing more than a decade ago. In an exclusive first look ahead of the facility’s April 21 grand opening, CEO Scott Wharton showed Canary Media via video chat how the automated factory line pumps out large panels of glass treated with a photovoltaic perovskite coating. Conventional silicon photovoltaic cells convert the sun’s rays to electricity with about 22% efficiency; layering them with Tandem’s perovskite glass in a “solar panel sandwich” lifts that efficiency to 30%, Wharton said.
That’s a huge jump for the solar industry: These paired, or “tandem,” solar plants could produce one-third more energy in the same physical footprint than regular solar panels on the market do today.
Tandem’s perovskite panels, which started rolling off the line in late January, are 60 times larger than what the company’s previous R&D line produced — but still one-quarter the size of large utility-scale solar panels.
“There’s only so much you can learn in the lab — then you have to build big things on bigger tools, otherwise you’re just not going to learn how to do that,” Wharton said. “And that’s the phase where we are at right now.”
To prove that performance, Tandem has agreements to sell panels to what Wharton called “a who’s who” of American solar developers for real-world testing in hot, cold, humid, and dry conditions around the country. Assuming field operations bear out Tandem’s claims of performance, the company expects to produce full-size perovskite panels starting in 2028 at a planned larger factory whose location has not been finalized.
Wharton kicked off the tour in the R&D lab, where technicians honed the company’s secret formula of perovskites and other chemicals on glass squares of 10 centimeters by 10 centimeters.
“The reason why we use this size is it’s big enough that it has all the failure modes of a very large panel, but it’s small enough that we can run lots of experiments, and it’s just not as expensive,” he explained.
The wet lab has an uncanny humanoid appearance: a row of beefy arms extends from elevated glass boxes, as if to firmly shake a row of hands. Those “arms” are actually gloves that workers use to slide their hands into the hermetically sealed enclosures to mix chemicals.
Which chemicals? “We don’t really share our formula, but they’re basically off-the-shelf stuff,” Wharton deflected.
The lab workers start by washing the glass for any impurities, and use a slot-die machine — commonly used to apply coatings to windowpanes and tempered glass — to deposit a 1-micron-thick layer of chemicals on the glass. Then, they place the glass in an annealing machine, which Wharton likened to a fancy hot plate, so that the perovskites crystallize properly.
Next door, in the dry lab, workers add additional layers of chemicals to transport electrons and protect the perovskite crystals. They do this through processes known as sputtering, evaporation, and atomic layer deposition. Afterward, they use a laser machine, about the height of an average person, to etch pinstripes in the glass, dividing it into thin strips that each function as cells.
The process differs entirely from silicon solar cell production. For instance, perovskites don’t need threads of silver to conduct electricity; thanks to the physical properties of perovskites themselves, electricity flows freely across their surface. They belong in the same family as thin-film solar, the alternative to conventional silicon that First Solar has been making in the U.S. for years, but few others have succeeded at.
The main event now happens across the hallway, where the pace ramps up considerably.
Instead of humans manually mixing the secret recipe ingredients, a series of robots combine the chemicals, wash and coat the much bigger glass panels, and roll them through the stations on an automated conveyor system. This automation not only allows for much faster production, Wharton noted, but also is far more precise than the work of human hands. Because of that, he hopes that the automated line, once fully calibrated, will churn out panels that perform even better than what his team produced in the lab.
The factory has the capacity to produce merely 40 megawatts each year; the largest U.S. solar panel factories churn out gigawatts annually. Tandem won’t max out its capacity, Wharton noted, because the goal is to prove that large-scale manufacturing works for perovskites, not to build a stockpile of panels to sell just yet.
For now, Tandem is honing its process engineering, translating techniques from the lab scale to the much bigger machinery, Wharton said. The line is making 10 to 20 panels a day during this learning phase, he said; by June, it should pump out identical panels that perform as well as or better than the R&D specimens.
“The goal would be to get thousands of panels out there to show that we can replicate the process, to show that we can have these outdoor trials with customers and with the national labs and others,” Wharton said.
Conventional silicon-based solar has taken over the grid, in the U.S. and globally, on the back of precipitous declines in cost. But it faces a long-term problem: There’s a theoretical limit to how efficient real-world silicon solar panels can be at converting sunlight to electricity, and that’s in the high 20% range. For tandem panels with perovskites, the theoretical limit is more like 45%, Wharton said.
“Even though we’re at 30%, there’s so much more room to improve, whereas silicon is kind of hitting its natural limits,” Wharton said. “They’ve basically squeezed almost all the lemon juice they’re going to get out of that lemon.”
Hence, the race to actually bring perovskites to market, pursued by the likes of Oxford PV, Swift Solar, Caelux, and others. So far, startups have publicized stunning efficiency records in a laboratory context that have not made their way into commercial products. Technology that works in a tiny test cell often works differently in a larger format. And perovskites tend to break down over time, losing their productivity far sooner than would be acceptable in grid infrastructure that has to run for decades. More broadly, venture-backed startups have raised billions of dollars to disrupt mainstream solar, with little to show for it after decades of work.
Greg Reichow, at venture capital firm Eclipse Ventures, had been searching for startups that could bring the kind of inflection point to solar that he’d experienced working at solar panel maker SunPower when it pushed the limits of efficiency in the early 2000s. He thought perovskites could be that next breakthrough, if a few pieces came together.
“We never saw somebody that can do both a big jump forward on efficiency, and do it at a demonstrated panel size that was relevant for an actual product, and demonstrate the durability that you need,” said Reichow, who ended up leading Tandem’s $50 million Series A fundraise last year. “When we met the team at Tandem, it was pretty clear that they had a path to go to all three.”
The initial customer orders have validated the economics for the product, Reichow added. The efficiency improvements are so large that they create project-wide savings for developers, reducing costs for land, labor, and other components, like steel and trackers. Those savings support a price point that will be profitable for Tandem, he said.
Unlike in earlier rounds of cleantech investment, the U.S. has made major strides toward building homegrown solar manufacturing to wean itself off China’s far better-established manufacturing base. But so far, U.S. factories have generally replicated the solar technology that is already being made on a much larger scale in China. Perovskites hold the promise of leapfrogging the state-of-the-art in the market today, giving the U.S. an advantage that hasn’t been secured by China already (at least, not yet). If that happened, the U.S. could produce much more domestic clean energy without additional dependence on the silicon supply chain that China has so intentionally and successfully dominated.
If Tandem or a competitor can produce working perovskites at large factory scale, there will finally be a growing industrial ecosystem to support widespread production in the U.S.
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.
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