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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.
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.”
Vermont’s first neighborhood-scale geothermal project is expected to break ground this summer as part of an affordable housing development, providing what developers hope is a blueprint for cost-effective, all-electric new construction in the Green Mountain State and beyond.
“We are decarbonizing and providing the natural energy of the earth to heat and cool our buildings,” said Amy Demetrowitz, chief operating officer of Champlain Housing Trust, one of the nonprofit developers behind the project. “The model is as awesome and as simple as that.”
Across the country, states with ambitious climate goals are looking for ways to cut emissions by weaning their buildings off natural gas and oil heat. Geothermal loops have emerged as a promising solution. These systems use emissions-free electric heat pumps to transfer thermal energy into and out of the earth, and deliver it to multiple households — not unlike pipes carrying water to homes across a neighborhood.
In 2024, utility Eversource launched a geothermal network in Framingham, Massachusetts, that includes some 140 retrofitted buildings; an expansion that will double the network’s size is in development. Work is underway in New Haven, Connecticut, on a geothermal system that will serve the city’s historic train station as well as about 1,000 units of public housing planned nearby.
The Vermont project is smaller; it will heat and cool 36 units at the Riggs Meadow development in the northern town of Hinesburg. An additional eight units and an on-site childcare center will have air-source heat pumps.
The geothermal project will have 12 to 16 boreholes drilled as far as 400 feet into the ground, where the temperature is a steady 45 to 50 degrees Fahrenheit year-round. In the cold weather, liquid pumped down these narrow wells will pick up heat from the earth and deliver it to the buildings above. In hot weather, the process will be reversed, with the system cooling the buildings by transferring heat back into the ground.
Champlain Housing Trust and Evernorth — another affordable housing developer partnering on the project — will foot the bill for the interior equipment, while utility Vermont Gas Systems will pay for and own the in-ground infrastructure, covering an estimated $275,000 in up-front costs that could be hard for a nonprofit like the trust to manage. Champlain Housing Trust, which covers utilities for tenants, will pay Vermont Gas a monthly “geothermal access fee” of $25 to $35 per unit to offset this spending.
“It’s not going to be wildly profitable for us, but it’s going to be a valuable learning experience as we figure out how we’re going to grow this over time,” said Neale Lunderville, president and CEO of Vermont Gas.
The plan took root in 2022 when Jan Blomstrann, former chair and CEO of Hinesburg-based renewable energy firm NRG Systems, donated 46 acres of land to Champlain Housing Trust for affordable housing development, specifying that she wanted the project to use renewable energy. The organization was already working toward decarbonizing its developments, so the request was a natural fit, Demetrowitz said.
At the time, Vermont Gas was considering ways to expand its offerings and keep its business strong as the future of natural gas becomes more uncertain in the face of climate regulations and shifting consumer demand. Currently, Vermont households rely heavily on fossil fuels to stay warm, but the state has a mandate to reduce greenhouse gas emissions by 80% by 2050 from 1990 levels. Decarbonizing home heating is a major element of the state climate plan.
With all that in mind, the utility in 2022 launched a program to sell or lease air-source heat pumps to customers. Geothermal seemed like an obvious next step, building on the company’s existing strengths, including managing long-term investments and installing and managing underground infrastructure.
“We’re really good at providing thermal energy services,” said Morgan Hood, director of product management for Vermont Gas. “There’s a lot of commonality with geothermal.”
While other projects, like the one in Framingham, have retrofitted existing neighborhoods to use geothermal, Vermont’s more dispersed population offers few places where enough households are close enough together for such an effort. Vermont Gas, therefore, set its sights on new construction.
Vermont Gas received a federal grant to study the feasibility of using a geothermal network at the Riggs Meadow development and to design the system. A second grant through the same program was expected to help pay for construction, but the Trump administration froze the funds, putting the project in limbo.
Instead of giving up, the team adapted. The original plan was for a geothermal network, a system that manages the diverse thermal needs of its different members: For example, the heat extracted by cooling a neighborhood ice rink might be used to warm an adjacent apartment building.
That initial scheme would have allowed Vermont Gas to learn valuable lessons about designing and managing a geothermal network, but the housing development didn’t actually require that level of complexity — generally, all the units would need either heating at the same time or cooling at the same time. This uniformity allowed Vermont Gas to shift to a simplified, lower-cost plan: Four buildings will each be served by their own geothermal loop. The company also decided not to pursue federal tax credits, as the cost of complying with the eligibility requirements would have outweighed the benefit.
“We had to pivot,” Hood said. “We needed to cut costs so we could still charge the customer base an acceptable amount.”
The partners hope this system, which is expected to be completed within a year, proves cost-effective enough to reproduce in future developments. As Vermont attempts to address housing shortages, geothermal systems could keep down both emissions and residents’ energy bills. But the approach has promise beyond local borders, Lunderville said.
“There are a lot of places across the country where we could replicate something just like this,” he said.
A correction was made on April 14, 2026: This story originally misstated how the geothermal access fee would be paid to Vermont Gas. The Champlain Housing Trust, not individual tenants, will pay the fee to the utility. The story was also updated to include the estimated cost of the project for Vermont Gas.
Fervo Energy, the leading next-generation geothermal startup, is ramping up plans to build out new power plants.
The Houston-based company has signed a three-year binding agreement with Turboden America, which will supply 1.75 gigawatts of organic Rankine cycle turbine capacity for Fervo’s forthcoming geothermal projects in the United States. The startup will use the equipment to convert heat pulled from deep underground into carbon-free electricity for data centers and the grid.
Fervo, which is reportedly preparing for an IPO, is currently building the first 100 megawatts of its 500-MW Cape Station in Beaver County, Utah. The project, which will be the world’s largest enhanced geothermal system, is slated to start producing power later this year.
Turboden America is already supplying over half of Cape Station’s total turbine capacity. The company, a subsidiary of the Italian manufacturer Turboden, says it will expand its U.S. operations to fulfill the deal, which calls for nearly three dozen 50-MW power-plant units.
The agreement, announced Tuesday, sheds more light on Fervo’s development plans beyond Cape Station, which broke ground about two and half years ago.
Fervo declined to share specific details about where and when it intends to deploy the new units. However, the company has “multiple projects in various stages of progress” and is pursuing “multi-year, multi-gigawatt offtake partnerships with both utilities and hyperscalers,” Sarah Jewett, Fervo’s senior vice president of strategy, told Canary Media in an email.
She added that the Cape Station site has an estimated 4.3 GW of capacity potential, based on internal and independent estimates. Fervo is also developing an enhanced geothermal system in Nevada, called Corsac Station, which is set to supply 115 MW of electricity to Google and the utility NV Energy.
This week’s development with Turboden “helps streamline project execution and accelerate deployment as our project pipeline advances,” Jewett said.
Together, Cape Station and the new turbines represent over 2.2 GW in geothermal power capacity. If completed and brought online, that amount would be equal to more than 50% of the current installed capacity of U.S. geothermal plants — which provide less than 1% of the country’s total electricity generation. Virtually all those existing plants rely on conventional hydrothermal resources, such as geysers and hot springs.
“Geothermal energy will be essential in stabilizing a strained power grid with clean, firm energy, and Fervo has shown strong leadership in advancing the sector,” Paolo Bertuzzi, president of Turboden America and CEO of Turboden, said in a statement. “With this announcement, we are prepared to scale delivery in the U.S. market and add megawatts of new generation wherever and however they are required.”
In signing the deal, Fervo and Turboden are aiming to avoid a potential bottleneck that threatens to slow the larger buildout of next-generation geothermal: the power-plant supply chain.
Today, the global market for organic Rankine cycle systems, heat exchangers, and other components is concentrated among a small set of manufacturers based in Israel, Turkey, and parts of Europe. Until very recently, those companies had little reason to scale production or revamp designs, given the sector’s limited growth. Most geothermal equipment is highly customized, and it can take over 18 months to bring it stateside.
“The ORC market has always been a very niche market and quite stable in the past,” Bertuzzi told Canary Media in an earlier interview.
But recent U.S. innovations in geothermal technology are making it possible to harness Earth’s heat from a wider range of places than conventional geothermal plants can reach. For instance, Fervo’s Cape Station uses horizontal drilling techniques and fiber-optic sensing tools to fracture hard, impermeable rocks and create artificial reservoirs. The startups Sage Geosystems and Quaise Energy are taking a similar approach, while companies like Rodatherm Energy and XGS Energy are building novel closed-loop systems deep underground.
Turboden, which is owned by Mitsubishi Heavy Industries, said it can presently deliver about 20 of its 50-MW turbine units per year. Nearly half of its global business is from the geothermal industry. The rest is from biomass-burning power plants as well as industrial facilities that use waste heat to generate electricity, such as data centers and gas-compressor stations.
The manufacturer is now set to scale production in both Italy and the United States in order to meet the growing demand from next-generation geothermal developers like Fervo. In an email, Turboden said it is adopting “multiple business and procurement models … to ensure larger volumes and faster delivery times, including domestic content to support tax credit mechanisms for American customers.”
Geothermal energy is on the cusp of a renaissance in the United States. But outdated and piecemeal rules could delay development of the around-the-clock, carbon-free energy source.
Next-generation geothermal is something of a golden child, backed by everyone from climate advocates to leaders in the drilling-obsessed Trump administration. Investors are pouring billions of dollars into the sector. A huge, first-of-a-kind project in Utah will start delivering power this fall, marking a milestone for this new wave of geothermal technologies — and fueling hopes that the energy source can help the U.S. keep pace with skyrocketing demand.
But companies won’t be able to quickly build dozens more of these power plants without updated regulations and standards for developing geothermal projects, industry insiders and experts say.
Today, permitting requirements are fragmented and can vary at the state and local levels, a reflection of the modest role geothermal has historically played in America’s energy sector. However, next-generation technologies are promising to unleash development in areas where harnessing Earth’s heat was previously too difficult or too expensive.
So companies are calling for a more standardized approach to permitting, instead of the bespoke, project-by-project reality they currently face. That will require lawmakers to act, but also the industry itself to develop better systems for defining projects and sharing data.
Meanwhile, pressure is growing within and outside the industry to create more safeguards for preventing accidents and high-profile mistakes that could harm communities and the environment — and could damage the industry’s reputation before it can truly launch.
“We want geothermal to advance as a clean energy solution that can be available anytime that is needed, anywhere that it is needed,” said Angela Seligman, a senior geoscientist at the nonprofit Clean Air Task Force. “But we also want it to stay as a source of clean energy, and we want the good actors … to be the ones who build new projects.”
Here are just a few of the ideas gaining traction for safely accelerating geothermal projects.
An obvious but essential step for creating rules is to establish exactly how next-generation technologies work and what their impacts might be.
The emerging industry has an ever-expanding vocabulary to describe its tools and techniques, but there’s still little consensus about what those terms all mean, said Jamie Beard, executive director of Project InnerSpace, a geothermal research and advocacy organization.
For example, Fervo Energy’s flagship, 500-megawatt Cape Station project is an “enhanced geothermal system” that uses hydraulic fracturing techniques gleaned from the oil and gas industry. Other developers might take a similar approach but use different words to describe it. The same goes for “advanced” and “closed loop” geothermal systems, which broadly include projects that circulate fluids in sealed underground pipes but can still involve intensive drilling methods and encompass a variety of materials.
“Right now, everybody’s kind of calling themselves what they want,” Beard said. “You can’t standardize, and you also can’t build trust about a technology” in this way, she added.
Last month, Project InnerSpace unveiled an initiative to start defining projects in more concrete terms. The Geothermal Resources Management System, which is modeled on the petroleum industry’s system, aims to establish a global framework for classifying and evaluating geothermal reserves. The main idea is to give banks and insurers more clarity and confidence in potential projects. But it would also support larger efforts to establish industry protocols for things like limiting groundwater contamination and avoiding industrial accidents, Beard said.
In the U.S., new bipartisan legislation to accelerate geothermal development is also geared toward creating more public transparency from the sector.
Sens. John Hickenlooper (D-Colorado) and Steve Daines (R-Montana) recently introduced the GEO Power Act, which would require the Department of Energy to help fund geothermal projects in states with limited or no existing geothermal power generation. It also prioritizes data sharing within the industry to “de-risk” future projects and to help regulators, communities, and business partners better understand and address potential impacts, according to the office of Sen. Hickenlooper.
Perhaps no risk looms as large over the next-generation geothermal universe as human-caused earthquakes.
The mistakes made on earlier enhanced geothermal systems are notorious. In France, Switzerland, and South Korea, the process of injecting water at high pressure to fracture rocks underground triggered seismic activity that was strong enough to damage buildings, rattle surrounding cities, and create public backlash.
In response to such events, in 2012, the U.S. Department of Energy revised its induced seismicity protocol, which describes a “traffic light” system for the real-time monitoring and measuring of vibrations caused by geothermal development. Any U.S. geothermal project that receives federal funding — which is virtually all of them today — is required to set up seismicity monitoring stations and follow the DOE’s guidance.
But as the industry matures, projects will likely no longer need government support, meaning they won’t have to follow the system of red, amber, and green lights in their operations. Seligman said that the Clean Air Task Force is pushing for the federal government to require all geothermal projects to adhere to the protocol.
“We want to be really careful about induced seismicity, so that it’s not something that will hinder the advancement of the geothermal industry,” she said.
The startups Eavor Technologies and XGS Energy told Canary Media they would have no issue adhering to a universal protocol. Both firms claim their systems are designed to mitigate such risks from the start. They say their closed-loop technologies don’t require fracking or injecting and withdrawing fluids from the ground — the main drivers of seismicity in geothermal wells.
“Maintaining public trust is vital for the entire geothermal sector,” said Neil Ethier, Eavor’s vice president of commercial and business development. In December, the Canadian startup began delivering power to the grid from its flagship operation in Germany, which is slated to produce over 8 MW of electricity and 64 MW of district heating when fully completed.
XGS is developing a 150-MW closed-loop system in New Mexico that’s expected to provide clean power for Meta’s data centers by 2029. Last week, the Houston-based firm said it was partnering with oil-and-gas services giant Baker Hughes on the exploration and engineering phases of the geothermal project.
Lucy Darago, the chief commercial officer for XGS, said that blanket requirements run the risk of adding “superfluous” rules for companies like hers, and that regulators should instead adopt measures that are “fit to purpose” and reflect the nuances in next-generation systems. She said that XGS is active in ongoing discussions with policymakers in states such as Colorado and New Mexico, which are revising permitting structures to accelerate geothermal development.
“Should we be required to drill a monitoring well and maintain a seismic program that could add millions of dollars to overall project costs?” Darago asked. “We probably will, especially for early projects. But should that be a perpetual part of our regulatory regime? I think that’s an open question, and one that we’d ultimately like our regulators to decide.”
As state and federal agencies work to revise rules for geothermal projects, industry leaders in the U.S. and other countries are also looking to show a token of good faith by proactively committing to certain standards.
Last fall, for instance, Fervo released the Geothermal Sustainable Development Pact, a voluntary framework meant to guide the industry’s growth. The 37-point plan includes steps like adopting DOE’s protocol for reducing seismic risk, prioritizing efficient water use, minimizing land disruption, and engaging with communities.
“As geothermal scales to meet rising energy demand, we have a responsibility to raise the bar on how these multi-decade projects are developed, and not just exclusively focus on the technology itself,” Tim Latimer, Fervo’s CEO and co-founder, said by email.
“Geothermal benefits from decades of lessons across energy: what worked in oil and gas, what worked in renewables, and where both fell short,” he added. “We don’t see it as an either-or situation. It’s not growth or responsibility. It’s both.”
No other companies have signed Fervo’s pact so far, though Latimer said the startup is inviting others across the industry to adopt and build on its principles. The environmental groups Sierra Club and NW Energy Coalition, an alliance of over 100 organizations and businesses in the Pacific Northwest, have said they fully endorse the pact.
“I think everybody will benefit from it, especially at this early stage of an exciting new era,” said Fred Heutte, a senior policy associate for the NW Energy Coalition.
He said that in his home state of Oregon, the startups Mazama Energy and Quaise Energy are working to build novel geothermal projects near the Newberry Volcano. Oregon currently has one large-scale conventional geothermal project — the 33-MW Neal Hot Springs plant — but most states have no geothermal development at all, given the industry’s traditional limitations.
With next-generation systems, “there’s going to be a lot more places that will be looked at for geothermal development … and that’s going to raise issues about land impact, community impact,” Heutte said. “I think the industry is well aware of the risks of problems like that and is trying to get out in front of it.”
Geothermal energy is rapidly advancing in the U.S. and globally, thanks to the arrival of next-generation technologies and skyrocketing power demand from data centers. Yet as more companies drill down deep to harness Earth’s heat, the industry is poised to hit a major snag on the surface.
Geothermal power plants rely on “turbomachinery” — turbines, heat exchangers, and other components — to generate and deliver electricity. But the limited supply chain and high cost of that equipment threaten to delay the industry’s efforts to supply huge amounts of clean electricity around the clock, according to Project InnerSpace, a geothermal research and advocacy organization.
On Tuesday, the group announced a new initiative with the nonprofit foundation XPrize to tackle that above-the-crust challenge.
XPrize will run a global competition to incentivize researchers and companies to design power-plant systems that not only require less time and money to produce than today’s, but that also can be more readily installed across a wider range of geothermal projects.
Project InnerSpace will fund initial efforts to design the competition, though the full prize amount won’t be announced until it officially launches this summer. The partners said they’re talking with industry players at the ongoing CERAWeek energy conference in Houston to develop key criteria for the contest.
The idea is to “unlock innovation that markets alone are too slow or too constrained to deliver,” David Babson, XPrize’s executive vice president of energy, climate, and nature, said in a news release. XPrize has spearheaded nine climate-related competitions to date, including a $100 million challenge for carbon-removal technologies that was funded by Elon Musk’s charitable foundation.
In the U.S., geothermal energy produces just 0.4% of total utility-scale electricity generation. Conventional geothermal technologies rely on naturally occurring reservoirs of hot water and steam that are found in only a handful of places, like California’s Geysers area and Nevada’s Great Basin.
However, recent innovations are breathing new life into the industry after decades of slow growth. Enhanced drilling techniques honed from oil and gas development, novel closed-loop systems, and more sophisticated mapping tools are making it possible to access heat in deeper, hotter, and drier locations than traditional systems can go.
“The subsurface solutions that will drive scaled development of next-generation geothermal energy are well on their way,” said Jamie Beard, executive director of Project InnerSpace. “We now need to match that momentum aboveground.”
That includes developing more “modular, integrated, and high-performance” geothermal surface plants than currently exist, according to the prize announcement.
Today, the global market for organic Rankine cycle technology and other equipment that geothermal plants use is concentrated among a small set of manufacturers based in Israel, Turkey, and parts of Europe. Until very recently, those companies had little reason to scale production or revamp designs, owing to the sector’s limited growth. Most geothermal equipment is highly customized, and in the U.S., it can take over 18 months to bring it stateside.
As the cost of drilling geothermal wells declines significantly, topside systems are expected to account for up to 50% of total project expenses and much of the risk of delays, Project InnerSpace wrote in a March report.
The turbomachinery supply chain will soon “be the bottleneck standing between next-generation geothermal and the gigawatt-scale deployment the world needs,” Beard said.
Supply chain constraints are hardly unique to geothermal. For fossil-gas power plants, the waitlist for new combustion turbines can stretch three to five years — and that was before the war now raging in the Middle East began disrupting global flows of critical materials.
Geothermal suppliers, for their part, aren’t sitting on their hands. Turboden, an Italian turbine-maker owned by Mitsubishi Heavy Industries, said it is preparing to boost production capacity in Italy and make more parts through its U.S.-based subsidiary to meet demand from next-generation geothermal and other sectors, including waste-heat recovery. Last fall, Turboden America was picked to supply equipment for three organic Rankine cycle units at Fervo Energy’s flagship Cape Station project in Beaver County, Utah.
“The volume of this business is growing significantly,” Paolo Bertuzzi, CEO of Turboden, said of geothermal.
The U.S. pipeline of pilot-scale and commercial projects is expanding in Western states like Colorado, Nevada, Utah, and Oregon. The sector is seeing a surge of support from private investors and government agencies that view geothermal as a timely and carbon-free way of meeting the nation’s soaring electricity demand.
Most recently, Fervo said it closed $421 million in new debt financing last week for the first phase of its 500-megawatt Utah project. The startup’s enhanced geothermal system uses fracking and horizontal drilling to create artificial reservoirs that circulate water and generate steam. Experts said the deal, led by major global banks, is a vote of confidence in the potential for enhanced systems to generate utility-scale returns.
As funders pile on, the Trump administration has protected key tax credits and accelerated permitting timelines for geothermal testing and exploration activities — in stark contrast to its efforts to block new wind and solar projects. In Congress, a bipartisan bill introduced last week would allow the Department of Energy to offer “innovative financing approaches” to advance next-generation geothermal in new states and regions.
Given the favorable conditions, an enhanced geothermal system of up to 500 megawatts in the western U.S. could enter into commercial production within roughly three to four years of active development, down from the timeline of seven to 10 years that’s frequently mentioned for conventional geothermal projects on federal land, according to recent research by the Center for Public Enterprise, a nonprofit think tank.
“That’s an incredible reduction,” said Mitchell Smith, a senior associate at the center, particularly for utilities looking to quickly bring clean power on the grid.
Still, the center’s report assumes that geothermal developers don’t encounter any “serious failure modes” when building their power projects. That can include lengthy interconnection queues as well as big delays in securing power-plant turbines — the very problem the XPrize competition aims to solve.
This story was originally published by Grist. Sign up for Grist’s weekly newsletter.
Mike Fleming was always interested in geothermal energy — how it works, how sustainable it is, and how efficiently it can heat homes and businesses. But Fleming, who has a decade of experience drilling wells in New England, didn’t see it as a career path.
That changed when his boss recommended him for a position at Phoenix Foundation Co. in late 2024. Part of the job involved overseeing drilling for geothermal projects. There were some differences between the roles, but there were plenty of commonalities, too. The technical skills, focus on safety, and need for precision are the same. And ultimately, “You’re making a hole in the ground, you’re putting some plastic pipe down there, and you’re sealing the hole,” said Fleming.
What felt routine at first is part of an emerging frontier in energy. Fleming’s work focuses on what’s called conventional geothermal, which requires drilling some 200 to 500 feet into the ground in search of subsurface earth that hovers between 50 and 60 degrees Fahrenheit — a temperature millions of residential heat pumps nationwide use to warm or cool homes year-round.
Geothermal provided about 0.36 percent of the country’s energy in 2024, by one estimate, but there are extraordinary amounts of it to be accessed at greater depths. Companies boring thousands of feet into the earth, a technique called enhanced geothermal, can reach rock as hot as 750°F — hot enough to power buildings, factories, even communities. That creates tremendous opportunities for oil and gas workers and others with drilling experience. As many as 300,000 people already possess the required skills, according to a 2024 U.S. Department of Energy report.
The Trump administration has looked favorably upon this renewable energy even as it has smothered wind and solar. The One Big Beautiful Bill Act preserved its tax credits through 2033, and the DOE recently announced $171.5 million for next-generation geothermal field tests.
It’s still too early to see a massive workforce transition, experts said, but they’ve seen evidence of growth. Another DOE report released in 2024 showed the domestic geothermal workforce inching up to 8,870 people. Globally, the industry employs around 145,000 workers. Many of those people simply go where the work is, fulfilling, say, a contract for an oil company before landing one with a clean energy outfit, said Cindy Taff, CEO of geothermal startup Sage Geosystems. “Drilling rig companies recognize this growth,” she said.
Taff spent 36 years at Shell. Frustrated that the oil behemoth wasn’t investing in geothermal, she co-founded Sage Geosystems in 2020. She sees a broad range of fossil fuel workers, from drillers to geologists, who will fit right into the renewables sector, arguing that the same industry that evolved from simple land wells to offshore operations in water thousands of feet deep has a vast pool of technical expertise. “What people tend to overlook is that the oil and gas industry over the last 100 years has really done a lot of innovative stuff,” she said.
One promising way to reach exceedingly deep rocks is by hydraulically fracturing them, running water through the path that eventually heats up and can be flashed into steam for power. Jonathan Ajo-Franklin, a geophysicist and professor at Rice University, said that there should be very little need to reinject large volumes of wastewater into the ground as a part of the geothermal fracking process. The oil and gas industry’s wastewater disposal has been linked to earthquakes in Oklahoma and West Texas.
Ajo-Franklin has worked with startups like Fervo Energy to conduct research on enhanced geothermal. He said that major oil companies “haven’t made big investments” in this area while they wait for the technology to be proven out. Nonetheless, he sees a lot of skill overlap between the fields.
Much of the U.S. oil industry focuses on extracting oil from rock that doesn’t naturally let it flow, he said. They’ve spent decades developing the technology and refining the complex techniques needed to maximize production — expertise readily transferable to drilling for heat.
Jamie Beard, executive director of the advocacy group Project InnerSpace, sees that potential and wants the Trump administration to back early-stage pilots. To build support, her organization hosted an event called MAGMA — short for Make American Geothermal More Abundant — last year to bring together industry leaders, policymakers, and Energy Secretary Chris Wright to make the case for next-generation geothermal. Wright expressed support for the industry.
In Beard’s view, there are a plethora of opportunities for geothermal, including powering data centers. “Oil and gas looks at that opportunity and says, ‘Well, hell, if we’re cranking out these projects and they’re natural gas, why can’t we crank out these projects and they could also be geothermal?’” she said.
Brock Yordy, founder of the Geothermal Drillers Association and a third-generation driller who started at 16, compares the transferability of drilling skills to hanging a painting. Walls made of brick, drywall, or wood might require a different bit, but “the base fundamentals are the same,” he said.
He sees this moment as an opportunity to get in on the ground floor of an exciting new line of work. “There’s not many jobs where you’re going to, by 500 feet, be drilling a piece of the subsurface that hasn’t been touched in 25,000 to 100,000-plus years,” he said. “It’s like being Indiana Jones. It’s exciting to think about.”
Geothermal startup Quaise Energy is pushing to build out its first “superhot” power plant this year as more money flows to next-generation geothermal projects.
The Houston-based company says it’s developing a 50-megawatt plant in central Oregon that will tap into significantly hotter geothermal resources than its competitors do, using the firm’s novel rock-melting technology. Quaise broke ground on that site, called Project Obsidian, last year and plans to drill a well this year that will allow it to validate the subsurface conditions, which are expected to reach over 300 degrees Celsius (572 degrees Fahrenheit).
“That’s really in full swing in Oregon,” Harry Kelso, the communications manager for Quaise, told Canary Media.
Quaise is seeking $100 million in Series B financing to support its first commercial plant in Oregon, as Axios first reported last week and Kelso confirmed. The company is looking to secure another $100 million in grants and debt for the project, which it plans to bring online by 2030. It has already signed a power-purchase deal for the initial 50 MW with an undisclosed customer and is working to ink agreements for an additional 200 MW in future capacity, he said.
Eight-year-old Quaise is riding the wave of interest in cutting-edge geothermal technologies.
The United States is clamoring for new sources of electricity, particularly from projects that can produce power around the clock and without carbon emissions. Next-generation geothermal, a broad umbrella that includes a variety of improvements on conventional systems, promises to deliver that — but the sector is still in the early stages of development.
Already this year, investors have closed major funding rounds for startups Sage Geosystems and Zanskar. Fervo Energy, which aims to bring an initial 100-MW enhanced geothermal system online in October, filed for an IPO in January. Just last week, the Department of Energy announced $171.5 million in funding to support field-scale tests of next-gen technologies.
Strong Republican support for the industry also spurred Congress last year to keep tax credits in place for geothermal, even as the Trump administration revoked incentives for wind and solar.
This year “is by far the most exciting time for geothermal in a while, because you have an insatiable need for power,” said Curtis Cook, founder and CEO of Rodatherm Energy Corp., referring to demand from data centers and electrification more broadly. His Salt Lake City–based geothermal startup closed a $38 million Series A funding round last fall to develop its “closed-loop” geothermal pilot plant on federal lands in Utah.
As more startups advance projects this year, potential investors and lenders will gain a better understanding of the capital and operating expenses associated with these emerging technologies. “That’s an inflection point for meaningful growth within the industry,” Cook said.
In Oregon, Quaise’s Project Obsidian will initially use conventional drilling tools to begin building an enhanced geothermal plant near the Newberry Volcano. This approach involves fracturing rocks and pumping them full of water to create artificial reservoirs, which harness Earth’s heat to drive steam turbines on the surface.
Fervo and the government-backed Utah Forge initiative are also developing enhanced systems. But Quaise says it could be the first to operate a commercial plant in superhot rock. These resources are not only dramatically more efficient at generating energy but are also widely available — so long as your equipment can withstand the scorching and corrosive conditions.
To that end, as early as next year, Quaise aims to start deploying its novel millimeter-wave drilling techniques at its power plant. The technology uses high-frequency beams to melt and vaporize rocks, with the goal of accessing hotter resources that are typically found several miles below where traditional drilling equipment can reach.
Quaise has raised a total of $120 million so far from investors to accelerate testing and development, including from Mitsubishi and the oil-and-gas drilling contractor Nabors Industries.
Last year, Quaise said it successfully used its tech to drill to a depth of around 330 feet at a test site near Austin, Texas. Now, it’s gearing up to drill to nearly 3,300 feet later this year. For context, that’s less than half as deep as the vertical wells at Fervo’s first project, a 3.5-MW enhanced geothermal plant in Nevada. But Quaise says it’s working to advance the technology and reach depths of 16,000 feet and far below at the Oregon site.
“We’re bringing those two factors together — superhot geothermal and the drilling technology — so that we can do this just about anywhere” in the world, Kelso said. “That’s the whole ambition, and why this year is so important.”
This story was originally published by Colorado Public Radio. Sign up for CPR’s weekly climate newsletter.
Last spring, Occidental Petroleum, an oil and gas company better known as Oxy, began drilling a massive hole in the shadow of a natural gas processing plant south of Greeley.
Drilling rigs are a common sight in Weld County, an area known for producing the vast majority of oil and gas extracted in Colorado. In this case, however, Oxy erected the tower for a different purpose: not to mine fossil fuels, but to tap carbon-free heat roughly 20,000 feet beneath the Earth’s surface.
The project, known as the Geothermal Limitless Approach to Drilling Efficiencies (GLADE), was supported by a $9 million grant issued by the U.S. Department of Energy in 2022. Its goal was to test whether new drilling techniques could reduce the cost and time required to drill superdeep geothermal wells, a potential global clean-energy game-changer.
Oxy has yet to detail its progress publicly and has declined multiple interview requests from CPR News. Its reports to state regulators, however, show that the company completed its drilling work nearly a year ago, working far faster than traditional superdeep drilling projects. The company started drilling in April 2025, digging twin boreholes almost four miles below the surface over less than six weeks, according to state permitting documents unsealed last month.
In a written statement, Jennifer Brice, an Oxy spokesperson, said the project set “new drilling milestones” for Colorado, and the company is now working to assess the experimental project with its academic and government partners.
The results could reveal whether similar projects — or the GLADE project itself — could support a new generation of geothermal power plants. Estimates suggest the bottom of the wells might exceed 450 degrees Fahrenheit. In concept, Oxy could link the bottom of the boreholes, either with additional drilling or by fracking open the surrounding rock. The resulting loop could heat water or another fluid to generate electricity at the surface.
For more than a century, geothermal power plants have been confined to areas with hot springs or volcanic activity, like Iceland or California’s Geysers region. With the GLADE project, Oxy may have demonstrated that fossil fuel companies are well positioned to overcome those limitations. By cutting the cost of reaching high temperatures far below the Earth’s surface, far more communities could harness 24/7, climate-friendly energy available almost anywhere.
“It’s very promising to see an oil company actually jump in with a drill bit instead of standing around thinking about it,” said Roland Horne, a professor of earth sciences and the director of the Stanford Geothermal Program at Stanford University.
Geothermal has long been the sleeping giant of renewable energy.
The resource currently meets less than 1% of global electricity demand, but humanity has only scratched the surface of its potential, according to a recent report from the International Energy Agency. Far more places can now consider geothermal energy due to recent breakthroughs in drilling and hydraulic fracturing developed by the oil and gas industry.
By using the same techniques to tap underground heat, the report estimates that geothermal could meet global electricity demand 140 times over. Unlike wind and solar, geothermal power plants could also fit into compact footprints and supply steady electricity, no matter the weather.
The main constraint is a basic fact about the Earth’s crust: The deeper you dig, the hotter it gets. With wells less than two kilometers deep, the analysis found that only a handful of countries could reach high enough temperatures to make electricity. At seven kilometers, geothermal could be possible in almost any area of the world.
Reaching those depths is difficult but not impossible. During the Cold War, Soviet geologists spent almost 20 years digging the Kola Superdeep Borehole more than 12 kilometers, or 7.5 miles, deep to study the Earth’s crust, setting the record for the world’s deepest hole. In Colorado, a 22,000-foot-deep oil and gas well in Moffat County holds the statewide record, according to a spokesperson for the state Energy and Carbon Management Commission.
Pressure and heat at those depths wreak havoc on mechanical equipment. With the GLADE project, Oxy set out to prove it could overcome those challenges by working faster and more cost-effectively than past superdeep drilling efforts.
The company itself hasn’t released any results, but state records show it dug one of its two wells in 18 days. Horne, the Stanford geothermal expert, said that pace would put Oxy in league with Fervo, a leading geothermal startup that drilled a nearly 16,000-foot-deep geothermal well in southwest Utah in 16 days last year. “That’s pretty impressive,” Horne said.
Other experts have characterized the effort as a success. Amanda Kolker, the manager of the geothermal laboratory program at the National Lab of the Rockies in Golden, said the GLADE project proved it’s possible to dig deep into sedimentary basins, large-scale depressions more commonly explored for oil and gas resources. The Denver-Julesburg Basin is one of many sedimentary basins in the western U.S.
“This achievement could unlock new geographies for geothermal technology deployment in the United States,” Kolker said.
One question is whether Oxy has plans beyond research for its geothermal boreholes. By completing the GLADE project, the company may have taken one of the most difficult steps toward building Colorado’s first geothermal power plant.
Multiple studies show that Colorado has ample underground heat to support a power plant, but no commercial enterprise has built one so far. In central Colorado, a pair of entrepreneurs has spent decades trying to build a geothermal power plant near Buena Vista. Their attempts, however, repeatedly ran into pushback from local residents worried about noise and disturbing the area’s famous natural hot springs. In August 2025, the state land board threw cold water on the idea by declining to renew a key land lease for a potential power plant site.
The Weld County site is rural and surrounded by oil and gas sites, far from hot springs or towns opposed to industrial development. Such a facility would also align with goals outlined by Gov. Jared Polis. Since taking office, the governor has created new geothermal subsidies and streamlined the permitting process for future geothermal projects, including power plants.
It’s unclear whether the company has any intention of building a power plant, but federal scientists advising the project have at least considered the possibility. A 20-page analysis published by the National Lab of the Rockies in 2024 estimates the GLADE project could produce 2.2 megawatts of electricity, enough to power a small community or industrial site.
In 2024, before drilling began, the company also sent a notice to residents, explaining it planned to link the bottom of the wells and circulate water to measure thermal energy. Depending on those results, the document notes, the company hoped to “design a small test plant to generate electricity.”
Brice, the Oxy spokesperson, said the document refers to a “test plant rather than a power plant,” but didn’t explain the difference. She also declined to answer whether Oxy has already built an experimental power plant at the site or plans to in the near future. “No decisions have been made,” Brice said.
If Oxy pursues a power plant, it could hint at a new investment opportunity for Colorado’s oil and gas industry, said Michael Rigby, an energy transition facilitator with the Colorado Energy and Carbon Management Commission. He suspects that oil and gas firms are waiting for a signal — evidence that the same supply chains and workers behind fossil fuels could pivot to geothermal projects.
“There are synergies between oil and gas and geothermal,” Rigby said. “As we see more things happen, I think we will see more merging in that space.”
A correction was made on March 5, 2026: This story originally misstated Roland Horne’s first name as Ronald.
Technological advances are expanding where geothermal electricity canbe produced - making it a cost-competitive, secure alternative to gas forindustry and other power-intensive users.
This analysis examines how advances in geothermal technology are changingthe prospects for geothermal electricity in Europe: its resource potential, costsand deployment trends. The report considers how policy conditions shape thepace of new projects and geothermal’s role in evolving electricity systems.
Modern geothermal is pushing the energy transition to new depths, opening up clean power resources that were long considered out of reach and too expensive. But today, geothermal electricity can be cheaper than gas. It’s also cleaner and reduces Europe’s reliance on fossil imports. The challenge for Europe is no longer whether the resource exists, but whether technological progress is matched by policies that enable scale and reduce early-stage risk.
Tatiana Mindekova
Policy Advisor, Ember
The EU’s Geothermal Action Plan must include clear commitments to liberate Europe’s power sector from costly fossil fuel dependency. The potential to replace 42% of coal and gas generation with geothermal is simply too significant to ignore. Ember’s report highlights the crucial role geothermal plays in delivering affordable energy, security, and competitiveness. With Energy Ministers and the European Parliament calling for concrete action, it is now up to the European Commission to remove the barriers to mass geothermal deployment.
Sanjeev Kumar
Policy Director, European Geothermal Energy Council
Europe has far more geothermal potential than is commonly accounted for. Next-generation geothermal strengthens Europe’s heat sector and extends its impact to clean, secure, and reliable electricity across much of the continent. Continued investment in innovation and supportive policy can turn this resource into a major pillar of EU’s clean firm power system.
Jenna Hill
Superhot Rock Geothermal Innovation Manager, Clean Air Task Force
Technologies allow geothermal to deliver scalable and clean power across much of Europe. Not just in volcanic regions. Across the European Union, around 43 GW of enhanced geothermal capacity could be developed at costs below 100 €/MWh, placing geothermal firmly within reach as a competitive source of firm, low-carbon electricity. Yet much of this technological progress has gone largely unnoticed and geothermal is still widely viewed as unavailable across much of Europe.
Geothermal power generation was long considered viable only in volcanic regions such as Iceland or Indonesia. Conventional geothermal relied on underground rock formations that were both hot and naturally permeable, allowing water already present at depth to circulate and transport heat. These rare conditions confined large-scale deployment to a limited number of regions worldwide. As a result, geothermal energy remained a niche contributor to global electricity generation (99TWh or less than 0,5% in 2024) despite its dispatchable nature and low emissions profile.
During the last decade, progress in geothermal technologies – often referred to as ‘next generation geothermal’ – has removed the need for naturally occurring permeability, meaning the presence of open pores in rock that allow fluids to flow. New approaches can now create or enhance these flow pathways artificially. Combined with more cost-effective deep drilling and advances in power-conversion systems that enable electricity generation at lower temperatures, significantly expanding the range of geological settings suitable for geothermal power generation. As a result, geothermal deployment is expected to accelerate rapidly: by 2030, nearly 1.5 GW of new capacity is expected to come online each year globally, three times the level added in 2024. At the global level, geothermal could meet up to 15% of the growth in electricity demand by 2050.
Recent advances in geothermal systems mean that geothermal electricity can now be produced at prices comparable to coal- and gas-fired generation, even outside traditionally high-temperature zones. Focusing on projects with estimated costs below 100 €/MWh – consistent with prices (short-run marginal costs) set by coal- and gas-fired generation in European power markets – and accounting for reservoir behaviour, plant performance and drilling depth, the techno-economic potential for geothermal power in continental Europe reaches around 50 GW.
Under this threshold, Hungary accounts for the largest share, with around 28 GW, followed by Türkiye with almost 6 GW and Poland, Germany, and France with around 4 GW each.
For EU member states alone, this corresponds to around 43 GW of deployable geothermal capacity, capable of generating approximately 301.3 TWh of electricity per year given geothermal’s high capacity factor. This is equivalent to around 42% of all coal- and gas-fired electricity generation in the EU in 2025.
At these cost levels, geothermal power would be competitive with the prices set by coal- and gas-fired generation in European power markets, where short-run marginal cost has been oscillating between 90 and 150 €/MWh in 2025. Not only can geothermal power capacity be developed at low prices, but as a technology with no fuel costs, it brings the additional benefit of being insulated from fuel price volatility and exposure to rising carbon costs, strengthening its role as a stable source of firm, low-carbon electricity over time.
The potential of geothermal energy for electricity generation is expanded by changes in the design of geothermal projects. The term next-generation geothermal encompasses several design improvements to geothermal systems. These include accessing underground heat without relying on natural heat pathways, using artificial heat carriers, or creating closed-loop systems. A type of next generation technology most commonly deployed is Enhanced Geothermal System(s) (EGS). EGS can engineer reservoirs in deep, hot rock where natural water or permeability is low or absent, unlocking potential beyond traditional hotspots.
In EGS projects, wells are drilled into hot rock and permeability is created or enhanced to allow a working fluid to circulate and extract heat. The heated fluid is brought to the surface through these artificial cracks to generate electricity. Experience from recent projects shows that seismic risks resulting from such drilling can be managed through monitoring and operational controls.
Geothermal reservoirs can be operated flexibly to absorb surplus wind or solar electricity indirectly, primarily through increased pumping and injection, and later the release of stored thermal and pressure energy to generate additional power. By varying injection and production rates, operators can “charge” the reservoir and later “discharge” it to increase output during high-value periods. Simulations show that heat can be stored for several days with efficiencies comparable to lithium-ion batteries. Because this capability is built into the same infrastructure used for power generation, it adds flexibility at low additional cost.
In addition, geothermal operations can generate value beyond electricity through the recovery of critical minerals from produced brines. Lithium concentrations in geothermal brines typically range in levels that can be commercially viable using new direct lithium extraction techniques. These methods recover up to 95 % of the lithium contained in the brine, compared with roughly 60 % from hard-rock mining, while using far less water and generating almost no carbon emissions.
Geothermal electricity is already cost-competitive with fossil fuels in Europe. The levelised cost of electricity (LCOE) of geothermal power – the cost of producing one unit of electricity based on the construction and operating costs of a power plant over its lifetime – is already low, at around USD 60 /MWh, placing it below most fossil-fuel generation (~ USD 100 / MWh in Europe). This reflects geothermal’s high capacity factors and the fact that existing projects have largely been developed in favourable geological conditions using conventional designs, with average depth of well between 1 to 3km.
Drilling and reservoir development remain the dominant drivers of capital expenditure, making early-stage investment risk a central barrier for deeper and more complex projects. Over the past decade, however, drilling and reservoir-engineering techniques adapted from the oil and gas sector have reduced well costs by roughly 40%, enabling economically viable access to hotter and deeper resources. As these capabilities scale, they expand the share of geothermal resources that can be developed at competitive cost.
Geothermal electricity potential increases as drilling reaches deeper, higher-temperature resources, but the depth at which suitable temperatures occur varies significantly across countries. In the European Union, assessments limited to resources accessible at depths of up to 2,000 m — where sufficiently high temperatures are available only in a subset of locations — yield a relatively constrained level of technical potential (139GW). As access extends to deeper and hotter resources, geothermal conditions become more widely available across the EU. Extending the depth range to 5,000 m increases the estimated potential by more than 50 times, while access to resources down to 7,000 m results in an increase of roughly 180 times.
In the EU, projects that take advantage of the newly accessible resources are already under construction, reaching depths beyond 4000m. Moreover, there are existing projects that have already reached depths close to 5000m, demonstrating that utilising geothermal resources at these depths commercially is already achievable with today’s technology.
Europe played a central role in the development of geothermal energy. The world’s first geothermal electricity was produced in Italy, in 1904, and as of 2024, Europe had 147 geothermal power plants in operation. Of these, 21 have been producing electricity for more than 25 years, underscoring the long-term value of geothermal investments. In 2024, these plants produced around 20 TWh of electricity from just over 3.5 GW of installed capacity (roughly one-fifth of global geothermal capacity).
Geothermal generation in Europe remains highly concentrated. The majority of its output came from Türkiye, Italy and Iceland, which together accounted for nearly all geothermal generation in the region. Beyond these established markets, activity is spreading: several countries already produce geothermal electricity, including Croatia, France, Germany, Hungary, Austria and Portugal, while new capacity is under development in Belgium, Slovakia and Greece. Across Europe, around 50 geothermal power plants are currently moving through development, from early exploration to grid connection, with Germany leading in active projects.
Pilot EGS projects launched in France, Germany and Switzerland in the 2000s demonstrated that hot, impermeable rock could be converted into productive reservoirs. More than 100 EGS projects have now been carried out worldwide, with Europe accounting for the largest share (42), followed by the United States (33), Asia (15), and Oceania (12). More recently, EGS projects have moved from commercial demonstration to full scale development. Advanced geothermal systems are also progressing, with Europe’s first closed-loop project now operating as a grid-connected power plant in Germany.
Despite this progress, Europe is at risk of losing ground. Lengthy permitting processes, inconsistent national support and the absence of a coordinated EU strategy and accompanying policies have slowed commercial deployment. In contrast, projects in the United States and Canada are now scaling up many of the methods first tested in Europe, supported by targeted policy incentives and private investment. Delayed deployment also risks shifting learning effects, supply-chain development and cost reductions to other regions, increasing future costs for European projects even where resources are available. Without a stronger focus on market-scale financing, Europe may miss the economic and industrial benefits of technologies it helped pioneer.
Geothermal power plants could play a crucial role in meeting the fast-growing electricity demand of data centres, whose global consumption could more than double by the early 2030s. As data-centre capacity expands, geothermal offers a stable, always-available source of electricity that can be developed alongside these sites. Its continuous output helps balance the wider power system and reliably serves data centres energy-intensive operations over the long term.
Recent research by Project InnerSpace shows that if current clustering trends continue, geothermal could economically meet up to 64 percent of new data centre demand in the US by the early 2030s and even more when developments are located near optimal resources.
At the same time, AI is reshaping geothermal development. By analysing seismic and geological data, it helps identify promising sites, streamline drilling and improve performance – creating a feedback loop in which each technology accelerates the other.
Major technology companies are no longer experimenting with geothermal – they are deploying it. Announced in 2021 and now fully operational, Google’s partnership with Fevro marked the world’s first enhanced geothermal project built for a data centre. Others are following suit, with Meta signing a 150-megawatt deal with Sage Geosystems in the United States. In Europe, no similar cooperations were announced.
In the United States, geothermal power is now firmly within the clean-energy toolkit. Federal legislation such as the Inflation Reduction Act has expanded investment and production tax credits to include geothermal electricity, establishing clearer economic signals for developers. Meanwhile, geothermal enjoys bipartisan backing because it leverages drilling and subsurface expertise tied to familiar industries and offers around-the-clock output.
In Europe, several Member States, including Austria, Croatia, France, Hungary, Ireland, and Poland, have developed national geothermal road maps aimed at supporting subsurface investment, demonstration wells and domestic supply chains, in some cases backed by dedicated financing and targets.
Only more recently has momentum begun to build at the EU level. In 2024, both the EU Council and the Parliament voiced their support for accelerating geothermal and proposed a European Geothermal Alliance, to be set up by the Commission. As geothermal strongly aligns with the EU’s priorities on competitiveness, energy security and industrial decarbonisation, the forthcoming European Geothermal Action Plan is a much-needed and timely development.
However, translating strategic recognition into deployment will depend on how geothermal is integrated across broader EU policy instruments. As preparations for the next Multiannual Financial Framework advance, and initiatives such as the Industrial Decarbonisation Accelerator Act aim to strengthen permitting and demand signals for clean solutions, geothermal’s high upfront risk, long asset lifetimes and system value as a source of firm capacity make coordinated EU action particularly important. In practice, the effectiveness of European geothermal framework will hinge on progress in three areas at EU level:
Download the report here.
Hot stuff: geothermal energy in Europe [PDF]
Techno-economic geothermal capacity potentials for power in the EU are aggregated from data presented in the paper “Global geothermal electricity potentials: A technical, economic, and thermal renewability assessment” by Franzmann et al., whose cost curves are limited to the “Gringarten approach” for reservoir modelling (please refer to the original publication for further details).
Raw geothermal energy surface densities in Europe are computed starting from Global Volumetric Potential (GVP) data from the Geomap tool by Project Innerspace, in particular from the modules with 150 °C cutoff temperature (minimum for power applications) and depths of 2000 m, 5000 m and 7000 m.
GVP data points, reported on a geographical grid with 0.17×0.17 degrees latitude-longitude resolution, are then averaged over the surface of each analysed country to obtain national energy values, expressed in PJ/km2.
The conversion to useful electrical energy is then performed by multiplying each country’s total by exergy efficiency (~30%, based on a 150 °C temperature for hot rock and on a 25 °C temperature for ambient) and utilization (~20%, based on conservative ranges out of the GEOPHIRES v2.0 simulation tool) factors. Capacity equivalents are calculated assuming an 80% load factor and a 25-years lifetime for a modern geothermal power plant. Results from the steps in this paragraph were used to validate the methodology through benchmarking with aggregated values from “The Future of Geothermal Energy” report by IEA.
The extraction of the original GVP data by Project Innerspace was performed in November 2025. Features and availability of modules within the Geomap tool might have changed since then.
Estimates for electricity generation in the EU are based on an 80% load factor, consistent with the rest of the methodology and representative of modern geothermal power plants. While cumulative generation and capacity estimates for 2025 only would yield a load factor of around 65%, future technological (improvements in plant operations) and market (increases in electrification and grid availability) conditions can justify assumptions for utilization of geothermal power capacity at or above this level.
Throughout the report, “Europe” refers to the European Union plus Iceland, Norway, Switzerland, Türkiye, United Kingdom and Western Balkan countries, reflecting the geographical scope of geological resource assessments and existing geothermal deployment. Where analysis refers specifically to the European Union, this is stated explicitly.
The authors would like to thank several Ember colleagues for their valuable contributions and comments, including Elisabeth Cremona, Pawel Czyzak, Reynaldo Dizon, Burcu Unal Kurban, Eli Terry, and others.
We would also like to extend our gratitude to our partners Clean Air Task Force and European Geothermal Energy Council for providing external review as well as valuable data and insights.
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