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New Haven, Connecticut, has broken ground on an ambitious geothermal energy network that will provide low-emission heating and cooling to the city’s bustling, historic Union Station and a new public housing complex across the street.
The project will play a crucial role in the city’s attempt to decarbonize all municipal buildings and transportation by the end of 2030. As one of Connecticut’s first geothermal energy networks, it will also serve as a case study of how well the technology can both lower energy costs and reduce greenhouse gas emissions as the state considers promoting wider adoption of these systems.
“At the end of the day, you’re going to have the most efficient heating and cooling system available for our historic train station as well as roughly 1,000 units of housing,” said Steven Winter, New Haven’s executive director of climate and sustainability. “Anything we can help do to improve health outcomes and reduce climate change–causing emissions is really valuable.”
In climate-conscious states across the country, thermal energy networks are emerging as a promising way to reduce reliance on fossil fuels for heating, lower utility bills, and create a pathway for the gas industry to transition its business model for a cleaner-energy future. These neighborhood-scale systems use ground-source heat pumps and a web of underground pipes to deliver heating and cooling to connected buildings.
The thermal energy for heating can come from a variety of sources, including geothermal systems, industrial waste heat, and surface water. Because no fossil fuels are directly burned to produce heat, the only emissions are those created generating the electricity to run the network. At the same time, the systems insulate customers from volatile and rising natural gas prices.
“There’s a lot of excitement around networked geothermal because it actually offers solutions to a lot of problems,” said Samantha Dynowski, state director of Sierra Club’s Connecticut chapter. “It can be a more equitable solution for a whole neighborhood, a whole community — not just a single home.”
The practice of deploying such systems as a neighborhood loop is relatively new, but the component parts are well established: Geothermal heat pumps have been around for more than 100 years, and the pipe networks are very similar to those used for natural gas delivery.
“The backbone technology is the same kind of pipe you use in the gas system,” said Jessica Silber-Byrne, thermal energy networks research and communications manager for the nonprofit Building Decarbonization Coalition. “They’re not experimental. This isn’t an immature technology that still needs to be proved out.”
There are a handful of networked geothermal systems around the United States, owned by municipalities, private organizations, and universities. A couple of miles away from the Union Station project, at Yale University, development is underway on a geothermal loop serving several science buildings.
But the idea is catching on among gas utilities, too. The nation’s first utility-owned geothermal network came online in Framingham, Massachusetts, in June 2024, and just received an $8.6 million federal grant that will allow it to double in size. Across the country, 26 utility thermal energy network pilots are underway, and 13 states have passed some form of legislation exploring or supporting the approach, according to the Building Decarbonization Coalition.
In Connecticut, a comprehensive energy bill that passed earlier this year established a grant and loan program to support the development of thermal energy networks. Advocates are now pushing Gov. Ned Lamont, a Democrat, to issue the bonds needed to fund the new initiative.
The New Haven network could provide a concrete example of the opportunities offered by such systems.
The plan began when the federal government was seeking applications for its Climate Pollution Reduction Grant program, an initiative created by President Joe Biden’s 2022 Inflation Reduction Act. Union Station seemed like an excellent property to retrofit because of its age, its size, and its prominent role in the city: Nearly a million travelers pass through the station each year, making it one of Amtrak’s busiest stops and an excellent platform for demonstrating the potential of geothermal networks.
“We thought it would be a powerful message to send for this beautiful landmark building that’s also the gateway to the city,” Winter said.
In July 2024, the federal program awarded the proposal just under $9.5 million; though there were questions earlier in the year about whether the Trump administration would attempt to block the money, the grant program ultimately proceeded. Planners expect federal tax credits and state incentives to cover the remaining $7 million in the project budget.
The network will use as many as 200 geothermal boreholes. Fluid will circulate through pipes in each of these wells, picking up thermal energy stored within the earth; in hotter weather, when cooling is needed, the systems will transfer energy back into the ground.
The city began drilling the first test boreholes in November. The results were promising: One test hole was able to extend down 1,200 feet, significantly farther than the 850 feet projected, Winter said. If more boreholes can be drilled that deep, it could mean fewer holes are needed overall — and thus less materials — making the project more efficient, he said.
Construction of the network is still in the early stages. The test boreholes should be completed this month, and the design of the ground heat exchanger — the underground portion of the system in which the thermal energy is transferred — is about halfway done, Winter said. The city is also preparing to accept proposals for the retrofit of the heating and cooling systems in the station itself.
The goal is to have the system up and running in the latter half of 2028. The apartment units, which are still in the design phase, will be connected to the system as they are built.
Even as the initial plan comes together, New Haven is already considering the possibility of expanding the nascent network to include more buildings, such as other apartment units under development nearby, existing buildings in the neighborhood, and a police station around the corner, Winter said.
“Ideally, we end up with a municipally owned thermal utility that can help decarbonize this corner of the city and provide affordable, clean heating and cooling,” he said.
Since spring of last year, North Carolina’s largest utility has been testing whether household batteries can help the electric grid in times of need — and now the company wants to roll out the plan to businesses, local governments, and nonprofits, too.
Duke Energy has already paid hundreds of North Carolinians to let it tap power from their home storage systems when electricity demand is highest. It’s Duke’s first foray into running a “virtual power plant,” in which the company manages electricity produced and stored by consumers, much as it would control generation from its own facilities.
In September, the utility proposed a similar model for its nonresidential customers, asserting that the scheme will save money by shrinking the need for new power plants and expensive upgrades to the grid. The recognition signals a way forward for distributed renewable energy and storage as state and national politicians back away from the clean energy transition.
The initiative now needs approval from the five-member North Carolina Utilities Commission, where the virtual-power-plant model has faced some skepticism. But the apparent merits of Duke’s plan, which has broad backing, may be too enticing for commissioners to ignore — especially when the state is grappling with rising rates and voracious demand from data centers and other heavy electricity users.
“In an era of massive load growth, something that should lower costs to customers while helping meet peak demand — to me, it’s an absolute no-brainer,” said Ethan Blumenthal, regulatory counsel for the North Carolina Sustainable Energy Association, an advocacy group. “I’m hopeful that [regulators] see it the same way.”
Duke’s trial residential battery incentives grew out of a compromise with rooftop solar installers. Like many investor-owned utilities around the country, the company sought to lower bill credits for the electrons that solar owners add to the grid. When the solar industry and clean energy advocates fought back, the scheme dubbed PowerPair was born.
The test program provides rebates of up to $9,000 for a battery paired with rooftop photovoltaic panels. It’s capped at roughly 6,000 participants, or however many it takes to reach a limit of 60 megawatts of solar. Half of the households agree to let Duke access their batteries 30 to 36 times each year, earning an extra $37 per month on average; the other half enroll in electric rates that discourage use when demand peaks.
The incentives have been crucial for rooftop solar installers, who’ve faced a torrent of policy and macroeconomic headwinds this year, and they’ve proved vital for customers who couldn’t otherwise afford the up-front costs of installing cheap, clean energy.
But the PowerPair enrollees already make up 30 megawatts in one of Duke’s two North Carolina utility territories and could hit their limit in the central part of the state early next year, leaving both consumers and the rooftop solar industry anxious about what’s next.
Duke’s latest proposal for nonresidential customers — which, unlike the PowerPair test, would be permanent — is one answer.
The proposed program is similar to PowerPair in that it’s born of compromise: Last summer, the state-sanctioned customer advocate, clean energy companies, and others agreed to drop their objections to Duke’s carbon-reduction plan under several conditions, including that the utility develop incentives for battery storage for commercial and industrial customers. The Utilities Commission later blessed the deal.
“This was pursuant to the settlement in last year’s carbon plan,” said Blumenthal, “so it’s been a long time coming.”
While many industry and nonprofit insiders refer to the scheme as “Commercial PowerPair,” its official title is the Non-Residential Storage Demand Response Program.
That name reflects the incentives’ focus on storage, with solar as only a minor factor: Duke wants to offer businesses, local governments, and nonprofits $120 per kilowatt of battery capacity installed on its own and just $30 more if it’s paired with photovoltaics.
The maximum up-front inducement of $150 per storage kilowatt is much less than the $360 per kilowatt offered under PowerPair. But more significant for nonresidential customers could be monthly bill credits: about $250 for a 100-kilowatt battery that could be tapped 36 times a year, plus extra if the battery is actually discharged.
Unlike households participating in PowerPair, which must install solar and storage at the same time to get rebates, nonresidential customers can also get the incentives for adding a battery to pair with existing solar arrays.
“That could be very important for municipalities around North Carolina that have already installed a very significant amount of solar, but very little of that is paired with battery storage,” said Blumenthal.
Duke has high hopes for the program, projecting some 500 customers to enroll. Five years in, the resulting 26 megawatts of battery storage would help it avoid building nearly 28 megawatts of new power plants to meet peak demand, saving over $13.6 million. That’s significantly more than the cost of providing and administering the incentives, which Duke places at nearly $11.8 million.
“The Program provides a source of cost-effective capacity that the Company’s system operators can use at their discretion in situations to deliver economic benefits for all customers,” Duke said in its September filing to regulators. “Importantly, the Company received positive feedback from its customers … when sharing the details of the Program.”
Indeed, the proposal has been met with support not just from the Sustainable Energy Association and other clean energy groups but also organizations like the North Carolina Justice Center, which advocates for low-income households. It earned praise from local governments represented by the Southeast Sustainability Directors Network and conditional support from the state-sanctioned customer advocate, known as Public Staff, too.
The good vibes continued last week, when Duke responded positively to detailed suggestions from these parties on how to improve the program. That included a request from Public Staff that the company raise the per-customer limit on battery capacity to align with the maximum amount of solar that a business or other nonresidential consumer can connect to the grid, which is currently 5 megawatts.
“Larger batteries sited at larger customer sites can help provide more significant system benefits and can reduce the need for incremental utility-owned energy storage installed at all ratepayers’ expense,” the agency told regulators in its November comments. It recommends a cap tied to a customer’s peak demand; for example, a business that consumes more energy at once should get incentives for a bigger battery. Duke agreed in its Dec. 5 comments, calling that limit “reasonable.”
Still, questions remain about how to make the incentives most impactful.
Public Staff, for instance, believes Duke should increase its monthly payment to customers for keeping their batteries charged and ready to deploy. This “capacity credit” is now set at $3.50 per kilowatt but effectively reduced to $2.48, because the utility assumes that a percentage of users won’t properly maintain their systems, based on its experience with households. The company calls that a “capability factor,” but the agency dubs it “collective punishment” for all customers and says it should be eliminated or recalibrated for “more sophisticated” nonresidential participants.
Raleigh, North Carolina–based 8MSolar, a member of the Sustainable Energy Association, is among the many installers that have been eagerly anticipating Duke’s proposal.
The program on its own likely won’t “move the needle unless the incentives get bumped up,” said Bryce Bruncati, the company’s director of sales. However, the scheme could tip the scales for large customers when stacked on top of two federal tax opportunities: a 30% incentive available through the end of 2027 and a deduction tied to the depreciation value of the system — up to 100% thanks to the Republican budget law passed this summer.
“The combined three could really have a big impact for small- to medium-sized commercial projects,” Bruncati said. The Duke program would represent “a little bit of icing on the cake.”
Whatever their size and design, the fate of the incentives rests entirely with the Utilities Commission, now that the final round of comments from Duke and other stakeholders is in. There’s no timeline for a decision.
At least one commissioner, Tommy Tucker, has voiced skepticism about leveraging customer-owned equipment to serve the grid at large. “I’m not a big fan of the [demand-side management] or virtual power plants because you’re dependent upon somebody else,” the former Republican state senator said at a recent hearing, albeit one not connected to the Duke program.
Still, Blumenthal waxes optimistic. After all, Tucker and three other current members of the commission are among those who ruled last year that Duke should present the new incentive program.
“They seem to recognize there is value to distributed batteries being added to the grid,” Blumenthal said. “The fact that [the proposal] is cost-effective is key because the idea is, the more of it you do, the more savings there are.”
Two corrections were made on Dec. 10, 2025: This story originally misstated the number of times a year that Duke can tap a PowerPair participant’s battery; it is 30 to 36 times a year, not 18. The story also originally misstated the enrollment Duke expects for the nonresidential program; the utility expects 26 megawatts of batteries, not 26,000 customer participants.
See more from Canary Media’s “Chart of the week” column.
If you had to guess which country gets the largest share of its electricity from solar, you might understandably toss out the name of a balmy island nation. Or perhaps you’d pick a country with swaths of blistering desert. At the very least, somewhere notoriously hot and sunny. Right?
Well, you would be wrong. The global leader is Hungary, according to a recent report from think tank Ember that pulls from full-year 2024 data and only considers nations that generated over 5 terawatt-hours of solar.
The Central European country got nearly one-quarter of its electricity from solar panels last year, leapfrogging Chile, which had held the top spot since 2021. Hungary’s win is no fluke: From January through October this year, solar grew to account for about one-third of power generated in the nation of 10 million.
It’s quite the shift. Just five years ago, Hungary got only 7% of its power from solar. Ember attributes the rapid growth to robust policies supporting both utility-scale and residential installations.
Rounding out the top five countries on Ember’s list are Greece, Spain, and the Netherlands. The top 10 is dominated by countries in the European Union, which is chipping away at coal- and gas-fired electricity.
To be clear, Hungary is not producing more electrons with solar panels than any other country. That distinction goes to China, which generates far more terawatt-hours’ worth of clean power than anywhere else, even if it only gets about 8% of its electricity from solar.
We’ll check back in next year to see if Hungary has retained its improbable title. The competition will be stiff. After all, the solar boom is a worldwide phenomenon.
Big companies have spent years pushing Georgia to let them find and pay for new clean energy to add to the grid, in the hopes that they could then get data centers and other power-hungry facilities online faster.
Now, that concept is tantalizingly close to becoming a reality, with regulators, utility Georgia Power, and others hammering out the details of a program that could be finalized sometime next year. If approved, the framework could not only benefit companies but also reduce the need for a massive buildout of gas-fired plants that Georgia Power is planning to satiate the artificial intelligence boom.
Today, utilities are responsible for bringing the vast majority of new power projects online in the state. But over the past two years, the Clean Energy Buyers Association has negotiated to secure a commitment from Georgia Power that “will, for the first time, allow commercial and industrial customers to bring clean energy projects to the utility’s system,” said Katie Southworth, the deputy director for market and policy innovation in the South and Southeast at the trade group, which includes major hyperscalers like Amazon, Google, Meta, and Microsoft.
The terms of the commitment were first sketched out in a letter agreement between Georgia Power and CEBA last year and then codified in a July settlement agreement between the utility, staff at the Georgia Public Service Commission, and other stakeholders that cemented the utility’s long-term integrated resource plan.
The “customer-identified resource” (CIR) option will allow hyperscalers and other big commercial and industrial customers to secure gigawatts of solar, batteries, and other energy resources on their own, not just through the utility.
Letting data centers procure their own energy resources could solve a lot of problems for utilities — like the risk of sticking their customers with the cost of building power plants that may be unneeded if the AI boom goes bust. That’s a real concern for Georgia Power, which plans to spend more than $15 billion to build 10 gigawatts of new gas plants and batteries by 2031. This move could dramatically increase customers’ bills and is almost entirely motivated by gigantic — yet highly uncertain — projections of how much energy that data centers will need.
The tech giants behind most of those data centers could also benefit from being able to track down their own clean energy. The carbon-free resources would not only help in meeting hyperscalers’ aggressive climate targets; they are also likely to be cheaper and faster to build than gas plants, which face yearslong backlogs and rising costs.
The CIR option isn’t a done deal yet. Once Georgia Power, the Public Service Commission, and others work out how the program will function, the utility will file a final version in a separate docket next year.
And the plan put forth by Georgia Power this summer lacks some key features that data center companies want. A big point of contention is that it doesn’t credit the solar and batteries that customers procure as a way to meet future peaks in power demand — the same peaks Georgia Power uses to justify its gas-plant buildout.
But as it stands, CEBA sees “the approved CIR framework as a meaningful step toward the ‘bring-your-own clean energy’ model,” Southworth said — a model that goes by the catchy acronym BYONCE in clean-energy social media circles.
The CIR option is technically an addition to Georgia Power’s existing Clean and Renewable Energy Subscription (CARES) program, which requires the utility to secure up to 4 gigawatts of new renewable resources by 2035. CARES is a more standard “green tariff” program that leaves the utility in control of contracting for resources and making them available to customers under set terms, Southworth explained.
Under the CIR option, by contrast, large customers will be able to seek out their own projects directly with a developer and the utility. Georgia Power will analyze the projects and subject them to tests to establish whether they are cost-effective. Once projects are approved by Georgia Power, built, and online, customers can take credit for the power generated, both on their energy bills and in the form of renewable energy certificates. Georgia Power’s current plan allows the procurement of up to 3 gigawatts of customer-identified resources through 2035.
Letting big companies contract their own clean power is far from a new idea. Since 2014, corporate clean-energy procurements have surpassed 100 gigawatts in the United States, equal to 41% of all clean energy added to the nation’s grid over that time, according to CEBA. Tech giants have made up the lion’s share of that growth and have continued to add more capacity in 2025, despite the headwinds created by the Trump administration and Republicans in Congress.
But most of that investment has happened in parts of the country that operate under competitive energy markets, in which independent developers can build power plants and solar, wind, and battery farms. The Southeast lacks these markets, leaving large, vertically integrated utilities like Georgia Power in control of what gets built. Perhaps not coincidentally, Southeast utilities also have some of the country’s biggest gas-plant expansion plans.
A lot of clean energy projects could use a boost from power-hungry companies. According to the latest data from the Southern Energy Renewable Association trade group, more than 20 gigawatts of solar, battery, and hybrid solar-battery projects are now seeking grid interconnection in Georgia.
“The idea that a large customer can buy down the cost of a clean energy resource to make sure it’s brought onto the grid to benefit them and everybody else, because that’s of value to them — that’s theoretically a great concept,” said Jennifer Whitfield, senior attorney at the Southern Environmental Law Center, a nonprofit that’s pushing Georgia regulators to find cleaner, lower-cost alternatives to Georgia Power’s proposed gas-plant expansion. “We’re very supportive of the process because it has the potential to be a great asset to everyone else on the grid.”
Isabella Ariza, staff attorney at the Sierra Club’s Beyond Coal Campaign, said CEBA deserves credit for working to secure this option for big customers in Georgia. In fact, she identified it as one of the rare bright spots offsetting a series of decisions from Georgia Power and the Public Service Commission that environmental and consumer advocates fear will raise energy costs and climate pollution.
“They’re proposing something that makes total sense and would help some companies be able to say ‘We’re powering our stuff with 100% clean energy,’” Ariza said of the CIR option. That’s particularly important at a time when many hyperscalers are backing away from their clean energy targets in their hunt for power for AI data centers, she noted.
Despite those benefits, the CIR framework’s omissions are substantial enough that CEBA did not join stakeholders like Walmart, the Georgia Association of Manufacturers, and the Southern Renewable Energy Association trade groups in signing on to it.
CEBA wanted companies to be able to procure a full range of carbon-free generation resources — such as geothermal and small modular nuclear reactors — rather than just renewable energy and renewables paired with batteries. The trade group also sought a pathway for customers to bring projects forward on a rolling basis more quickly than the current settlement agreement would allow.
But one of the biggest issues CEBA has with the current CIR plan is that it “does not recognize the full capacity value of customer-funded clean, firm resources to the grid,” Southworth said. Capacity value is a measure of how power plants, batteries, and other resources meet peak power demands during the handful of hours per year that determine how much generation and grid infrastructure utilities need to build.
That’s a significant gap. If the resources that big customers secure under the CIR aren’t considered part of the solution to this challenge — if their capacity value isn’t factored in — they may not be able to reduce Georgia Power’s need for gigawatts of gas-fired power plants, which are the traditional utility backstop for ensuring adequate energy supplies.
This would be bad for Georgia Power customers at large, who would end up paying for more gas plants than are actually needed after the data centers driving up power demand secure their own resources instead. It could also saddle data centers and other big customers with growing capacity-related costs that their self-secured projects could otherwise help reduce.
“A well-designed CIR program that recognizes the capacity value of customer-funded clean resources is a win-win-win for large customers, Georgia Power, and all ratepayers,” Southworth said. “Participating customers pay the incremental cost of new clean, firm projects; the utility gets capacity it can count on; and nonparticipating customers benefit from a more diverse, less gas-dependent resource mix without taking on the full cost or fuel price risk of those projects.”
CEBA has ideas for how Georgia Power could financially compensate customers for the capacity value of the resources that they procure. The utility already calculates “avoided capacity values” for the renewable energy, battery, and fossil-fueled resources it brings to the table in its requests for proposals. Georgia Power could provide a capacity credit of similar value to subscribing customers for the projects they procure.
CEBA will “continue to work with the company and commission staff,” Southworth said. Her group sees Georgia Power’s long-term plan approved this summer “as establishing the floor, not the ceiling, for what CIR can become.”
A big shift at the Public Service Commission could lay the groundwork for a reassessment of the program. Last month, Georgia voters elected two Democratic challengers — health care consultant Alicia Johnson and clean-energy advocate Peter Hubbard — to replace Republican incumbents Tim Echols and Fitz Johnson.
The two new commissioners have both pledged to tackle high and rising electricity costs for Georgia Power residential customers. Across the country, utilities and regulators are striving to force data center developers to take on the costs they’re imposing on power grids, rather than foisting them on everyday utility customers.
“Capacity is still an open question” that the Public Service Commission can take up as it decides on the CIR option, said Whitfield of the Southern Environmental Law Center. “Georgia Power is certainly on record that they don’t prefer it to be accredited, which makes sense for them. They want to build more and profit more,” as a regulated utility that earns guaranteed profits on its capital investments. “But that is going to be very much a live issue.”
This story was first published by Inside Climate News.
The U.S. Department of Energy has approved an $8.6 million grant that will allow the nation’s first utility-led geothermal heating and cooling network to double in size.
Gas and electric utility Eversource Energy completed the first phase of its geothermal network in Framingham, Massachusetts, in 2024. Eversource is a corecipient of the award along with the city of Framingham and HEET, a Boston-based nonprofit that focuses on geothermal energy and is the lead recipient of the funding.
Geothermal networks are widely considered among the most energy-efficient ways to heat and cool buildings. The federal money will allow Eversource to add approximately 140 new customers to the Framingham network and fund research to monitor the system’s performance.
The federal funding was first announced in December 2024 under the Biden administration. However, the contract between HEET and the Department of Energy was not finalized until Sept. 30 and was just announced Wednesday. The agreement, which allows construction to move forward, comes as the Trump administration is clawing back billions of dollars in clean energy funding, including hundreds of millions of dollars in Massachusetts.
“This award is an opportunity and a responsibility to clearly demonstrate and quantify the growth potential of geothermal network technology,” Zeyneb Magavi, HEET’s executive director, wrote in a statement.
The existing system provides heating and cooling to approximately 140 residential and commercial customers in the western suburb of Boston. The network taps low-temperature thermal energy from dozens of boreholes drilled several hundred feet below ground, where temperatures remain steady at 55 degrees Fahrenheit. A network of pipes circulates water through the boreholes to each building, enabling electric heat pumps to provide additional heating or cooling as needed.
“By harnessing the natural heat from the earth, we are taking a significant step toward increasing our energy independence and promoting abundant local energy sources,” Charlie Sisitsky, Framingham’s mayor, wrote.
Progress on the project is a further indicator that despite their opposition to wind and solar, the Trump administration and Republicans in Congress appear to back geothermal energy.
President Donald Trump issued an executive order on his first day in office declaring an energy emergency that expressed support for a limited mix of energy resources, including fossil fuels, nuclear power, biofuels, hydropower, and geothermal energy.
The One Big Beautiful Bill Act, passed by Republicans and signed by Trump in July, quickly phases out tax credits for wind, solar, and electric vehicles. However, the bill left geothermal heating and cooling tax credits approved under the Inflation Reduction Act of 2022 largely intact.
A reorganization of the Department of Energy announced last month eliminated the Office of Energy Efficiency and Renewable Energy but kept the office for geothermal energy as part of the newly created Hydrocarbons and Geothermal Energy Office.
“The fact that geothermal is on this administration’s agenda is pretty impactful,” said Nikki Bruno, vice president for thermal solutions and operational services at Eversource. “It means they believe in it. It’s a bipartisan technology.”
Plans for the expansion project call for roughly doubling Framingham’s geothermal network capacity at approximately half the cost of the initial buildout. Part of the estimated cost savings will come from using existing equipment rather than duplicating it.
“You’ve already got all the pumping and control infrastructure installed, so you don’t need to build a new pump house,” said Eric Bosworth, a geothermal expert who runs the consultancy Thermal Energy Insights. Bosworth oversaw the construction of the initial geothermal network in Framingham while working for Eversource.
The network’s efficiency is anticipated to increase as it grows, requiring fewer boreholes to expand. That improvement is due to the different heating and cooling needs of individual buildings, which increasingly balance each other out as the network expands, Magavi said.
The project still awaits approval from state regulators, with Eversource aiming to start construction by the end of 2026, Bruno said.
“What we’re witnessing is the birth of a new utility,” Magavi said. Geothermal networks “can help us address energy security, affordability and so many other challenges.”
In the race to build America’s first small modular reactors, the U.S. Department of Energy has picked its front-runners.
On Tuesday, the agency awarded a total of $800 million in grants, originally allocated under the Infrastructure Investment and Jobs Act, to two projects developing different kinds of 300-megawatt light-water reactors.
These third-generation reactors are shrunken-down, less powerful versions of the time-tested first- and second-generation designs that make up the vast majority of the nation’s fleet of 94 large-scale reactors.
Neither of the third-generation designs — nor any of the fourth-generation models, which use coolants other than water to reach higher temperatures and which the Trump administration has also invested in — has yet been approved by the Nuclear Regulatory Commission. And $400 million each for the two just-selected projects is likely to cover only a sliver of their total costs. Getting the green light on a design before a reactor is built doesn’t necessarily always work. The first new large-scale reactors built from scratch in the U.S. in a generation came online as a pair over the past two years but were billions of dollars over budget, in part because construction revealed necessary tweaks to the blueprints that then took developers months to get approved by the NRC. Still, the effort is part of the Trump administration’s push to boost both generations of SMRs in a high-stakes, multibillion-dollar bid to reinforce the nation’s world-leading nuclear industry before China, with its rapid construction of new reactors, becomes the No. 1 fission user.
The federally owned Tennessee Valley Authority will get $400 million to build the first BWRX-300, the reactor designed by a joint venture between the U.S. energy behemoth GE Vernova and the Japanese industrial heavyweight Hitachi. Over the past three years, GE Hitachi Nuclear Energy’s design has emerged as a leader in America’s SMR race, thanks to GE and Hitachi’s long history of successfully building large-scale boiling-water reactors.
In May, Ontario Power Generation, the state-owned utility in Canada’s most populous province, finalized plans to build what’s likely to be the first SMR in North America, one of four BWRX-300 to eventually be built at its Darlington nuclear plant.
Piggybacking off OPG’s effort, the TVA — among the few entities in the U.S. that mirror Canada’s government-owned utility model — plans to construct America’s first BWRX-300 at its Clinch River site, just south of Oak Ridge, Tennessee. Estimates from the Massachusetts Institute of Technology suggest the reactor will cost significantly more than the far more powerful large-scale Westinghouse AP1000 reactor, which the U.S. finally completed two of at Southern Company’s Alvin W. Vogtle Generation Electric Generating Plant in northern Georgia over the past two years. But the theory with SMRs is that less powerful machines will require a higher quantity of reactors, and that the identical design will bring down costs. The Energy Department grant is meant to discount the price tag of that second-of-a-kind unit.
The other half of the DOE funding has been awarded to Holtec International, which established itself in nuclear power over the last three decades as the industry’s undertaker. The Florida-based manufacturer designed and deployed droves of concrete dry casks meant to keep spent reactor fuel safely stored on-site at nuclear plants until the U.S. government comes up with a solution for radioactive waste. A few years ago, the company entered into the decommissioning business, buying a handful of defunct nuclear plants with the goal of taking them apart. Recently, however, it has looked to become an operator.
Last year, the Energy Department’s Loan Programs Office — recently renamed the Office of Energy Dominance Financing — finalized a $1.5 billion loan to finance the restart of one of Holtec’s plants. The single-reactor Palisades nuclear plant in western Michigan had been the most recent U.S. atomic station to shut down earlier than needed as competition with cheap natural gas and renewables made the facility’s upkeep too costly for its owner, utility giant Entergy. The company sold the plant to Holtec for disassembly in 2022. But as demand for nuclear power has surged in recent years, Holtec proposed reopening the station.
Then, in February, Holtec unveiled fresh plans to expand Palisades with a pair of its SMR-300s. The 300-megawatt reactors are also based on a design used for decades: the pressurized-water reactor, which is even more common than the boiling-water reactor that GE specialized in during the heyday of reactor construction in the mid-20th century.
In a statement, Kris Singh, Holtec’s chief executive officer and chair, called the grant an “essential enabler” of the company’s plans to build the SMR-300, and pointed to Holtec’s exclusive partnership with the South Korean industrial giant Hyundai Engineering and Construction as evidence that the reactor’s design is “marinated with four decades of practical corporate experience.”
“Holtec realizes the future of nuclear energy as a source of reliable baseload electricity to power the economy of the future is realized only if we, in the industry, make the reactors predictably cost competitive,” Singh said. “We consider it our duty to lead the industry in building, owning, and operating the first SMR-300 plant in the United States.”
The Energy Department funding doesn’t guarantee that either project will be completed. NuScale, a fellow third-generation nuclear developer, received $583 million from the Energy Department to fund what was supposed to be the nation’s first SMR plant in Idaho on behalf of Utah Associated Municipal Power Systems, a collection of public utilities in the Beehive State. But the project still went under amid rising costs in November 2023.
The theory that smaller, less powerful reactors will yield lower costs has yet to be proved. So far, only one major SMR has entered into service worldwide, in Russia, where it’s operating on a floating barge in Siberia. The Kremlin-owned Rosatom, the world’s No. 1 exporter of civilian nuclear technology, hasn’t filled its order books for more SMRs and has instead concentrated on large-scale reactors. Likewise, the country building the most nuclear reactors, China, is working toward completing its first third-generation SMR on Hainan. However, the unit is largely seen as destined for export to countries with less demand for large-scale reactors, while China’s two biggest state-owned nuclear utilities have continued focusing on building gigawatt-size units.
The U.S., too, has come around to large-scale reactors. In October, the Trump administration announced a deal to spend $80 billion on 10 new AP1000s, in a move that E&E News suggested made Westinghouse America the new “national champion” in nuclear.
But in a statement, Secretary of Energy Chris Wright suggested there’s room for multiple kinds of reactors.
“President Trump has made clear that America is going to build more energy, not less, and nuclear is central to that mission,” Wright said. “Advanced light-water SMRs will give our nation the reliable, round-the-clock power we need to fuel the President’s manufacturing boom, support data centers and AI growth, and reinforce a stronger, more secure electric grid. These awards ensure we can deploy these reactors as soon as possible.”
Two new battery projects on Virginia’s remote eastern peninsula could signal a growing trend in the clean-energy transition: midsize energy-storage units that are bigger than the home batteries typically paired with rooftop solar, but cheaper and quicker to build than massive utility-scale projects.
The 10-megawatt, four-hour batteries, one each in the tiny towns of Exmore and Tasley, represent this “missing middle,” said Chris Cucci, chief strategy officer for Climate First Bank, which provided $32 million in financing for the two units. Batteries are a critical technology in the shift to renewable energy because they can store wind and solar electrons and discharge them when the sun isn’t shining or breezes die down.
When it comes to energy storage, “we need volume, but we also need speed to market,” Cucci said. “The big projects do move the needle, but they can take a few years to come online.” And in rural Virginia, batteries paired with enormous solar arrays — which can span 100-plus acres — face increasing headwinds, in part over the concern that they’re displacing farmland.
The Exmore and Tasley systems, by contrast, took about a year to permit, broke ground in April, and came online this fall, Cucci said. Sited at two substations 10 miles apart, the batteries occupy about 1 acre each.
Beyond being relatively simple to get up and running, the systems could help ease energy burdens on customers of A&N Electric Cooperative, the nonprofit utility that owns the substations where the batteries are sited, said Harold Patterson, CEO of project developer Patterson Enterprises.
Wait times to link to the larger regional grid, operated by PJM Interconnection, are up to two years. So for now, the batteries will draw power only from the electric co-op, Patterson said. Once they connect to PJM, the batteries will charge when system-wide electricity consumption is down and spot prices are low. Then, the batteries’ owner, Doxa Development, will sell power back when demand is at its peak, creating revenue that will help lower bills for co-op consumers.
“That’s the final step to try to drive down power prices” for residents of Virginia’s Eastern Shore, Patterson said. “Get it online and increase supply in the wholesale marketplace.”
Though the batteries aren’t paired with a specific solar project, they are likely to lap up excess solar electrons on the PJM grid. And since they’ll be discharged during hours of heavy demand, they could help avert the revving up of gas-fired “peaker plants.”
“Peaker plants are smaller power plants that are in closer proximity to the populations they serve, and [they] are traditionally very dirty,” Cucci said. “They’re also economically inefficient to run. Battery storage is cleaner, more efficient, and easier to deploy.”
Gas peaker plants are wasteful partly because of all the energy required to drill and transport the fuel that fires them, said Nate Benforado, senior attorney at the Southern Environmental Law Center, a nonprofit legal advocacy group.
“Then you get [the fuel] to your power plant, and you have to burn it,” Benforado said. “And guess what? You only capture a relatively small portion of the potential energy in those carbon molecules.”
Single-cycle peaker plants, the most common type, can go from zero to full power in minutes, much like a jet engine. Their efficiency ranges between 33% and 43%.
“Burning fossil fuels is not an efficient way to generate energy,” Benforado said.
“Leaning into batteries is the way we have to go. They’re efficient on the power side but also on the price side.”
Texas proves the financial case for batteries. The state has its own transmission grid, no monopoly utilities, and no state policies to speed the clean-energy transition. Yet it’s gone from zero to some 12 gigawatts of batteries in five years.
In Virginia, A&N Electric Cooperative isn’t the only nonprofit utility investing in energy storage: The municipal utility in the city of Danville, on the North Carolina border, announced earlier this year that it’s building a second battery project of 11 megawatts. Its first system, a 10.5-megawatt battery, which went online in 2022, is on track to save customers $40 million over two decades, according to Cardinal News.
“You look at Texas, where developers are trying to make money on projects,” said Benforado. “And now you see co-ops and municipalities saying, ‘This can save our customers significant amounts of money.’ That, to me, is very telling about the economics of batteries.”
Those economics are even rosier in light of the federal tax credits available for grid batteries, among the few green incentives to survive the budget bill that congressional Republicans passed this summer. Those credits start phasing down in 2033.
While nonprofit utilities in Virginia aren’t impacted by a 2020 state law that requires investor-owned Dominion Energy and Appalachian Power Co. to decarbonize by 2045 and 2050, respectively, they help show what’s possible for the state.
“We need to build things,” Benforado said, especially in the face of skyrocketing demand from data centers. “The question is, are we going to build clean resources or not? We need to build batteries, not gas.”
Climate First Bank and Patterson Enterprises, for their part, have more midsize energy-storage systems in the works. In fact, in December they expect to break ground on another 10-megawatt project — in Wattsville, 20 miles up the road from Tasley.
“We are talking to a lot of developers on projects ranging from 2 megawatts to 10 or 15 megawatts,” Cucci said. “A lot of those players are saying, ‘Let’s shift a little more heavily into storage.’”
WESTERN MACEDONIA, Greece — For more than a decade, Lefteris Ioannidis had been saying what no one wanted to hear: Coal is dying, and it’s time to prepare for what comes next.
He could see the writing on the wall while serving as mayor of Kozani, the largest city in Western Macedonia, even as other local politicians wanted to build new power plants and dig more coal from the region’s sprawling mines. The president of the coal workers’ union said Ioannidis was dead wrong.
But coal production had been sagging since the early 2000s. The power plants were getting too costly to run, thanks to new pollution rules. And extracting and burning the fossil fuel — which in Western Macedonia is mined in vast open pits that over the decades have destroyed homes, entire villages, and lives — was clearly incompatible with the European Union’s vision for a green future.
Still, even Ioannidis didn’t believe Greece would abandon coal so soon.
Just over a decade ago, more than half the country’s electricity was produced by burning through mountains of lignite, the lowest-grade form of coal. Now, if all goes according to plan, Greece aims to shutter its last two coal-fired power plants next year and stop producing coal from most of its mines, including one that is among the largest in Europe. In coal’s place, the country is building clean energy — mostly solar — at a feverish pace.
Western Macedonia, a landlocked and sparsely populated region far north of Athens and the iconic whitewashed buildings of the Cyclades islands, is at the center of this rapid transition.
The region sits atop the biggest lignite deposits in Greece. Over the course of six decades, the once state-owned PPC Group pulled hundreds of millions of metric tons of coal from the area’s soil, producing thousands of jobs and eventually most of Greece’s electricity — along with devastating environmental and health consequences.
Today, things are changing. Blue-black lakes of solar panels shimmer across the valley floor, busily converting the bountiful Greek sun into clean energy, while others wait to be plugged into the grid. The installations stretch to the edges of quiet mines and surround idled power plants. Lonely plumes of steam escape from the cooling towers of the few coal units that remain online, wavering in the wind like white flags of surrender.
Soon, PPC will complete the construction of 2.1 gigawatts of solar in Western Macedonia, erected mostly on top of remediated coal lands. It will be the largest cluster of solar panels in Europe. Most of it was built within the last 12 months.
The success of the region’s energy transition is undeniable. But so too is the failure to build an economy for the post-coal era. Even though Greece announced back in 2019 that it would eliminate coal, uncertainty reigns over Western Macedonia’s future, and the region remains wracked by poverty and unemployment.
“We had an economy dominated just from coal, and everybody knew that the coal would have to end,” said Ioannidis. “But nobody did anything to prevent the disaster. It’s like the Titanic — everybody dancing on board, but the disaster is coming.”
Most of PPC Group's massive solar cluster in Western Macedonia was built recently, as is visible when comparing satellite imagery from October 2024 to April 2025.
The situation underscores an urgent question as 17 other European nations work to eliminate coal over the coming years: How can a country do what’s right for the planet without wronging the people who depend on fossil fuels for jobs?
The European Union is searching for answers: In 2021 it created a €17.5 billion fund “to ensure no one is left behind on the road to a greener economy.”
The following year, Greece became the first country to have a just-transition plan approved by this fund. But to date, only a sliver of the nearly €1 billion allocated specifically to Western Macedonia has trickled into the impacted communities. There’s not yet a large-scale flagship project in operation — something to demonstrate what a world without coal might look like.
Ioannidis says the lack of progress is unacceptable, the result of a top-down, Athens-led approach that has left little room for the locals to shape their own destiny.
“The main path is to create a bottom-up strategy,” he said. “But I’m not optimistic. I’m not waiting for anything from the government. For them, Western Macedonia is only a very small part of Greece. … Anything outside Athens, it’s not a priority.”
This sense of fatalism hangs over the region like smog. Frustrated by the lack of progress, many residents are leaving in search of better prospects.
It’s a devastating feedback loop: Every working-age resident who pursues a job in Athens or Thessaloniki, every young person who goes off to university and never returns, is one less person to help wrest Western Macedonia from the quicksand of its dirty past. The task of inventing the future becomes harder with each departure — and the sense that it is possible to do so becomes that much more remote.
On a warm Sunday evening in September, every bench in Plateia Nikis, Kozani’s main plaza, was full.
Conversation rose from the tavernas that line the west side of the plaza. Groups of teenagers roamed the pedestrian-only street that feeds into the plaza from the south, pushing one another around and giggling their way into one of several nearby arcades. A child kicked a soccer ball in the plaza’s center and suddenly 10 more appeared; a game began. Another cut across the match, running not after the ball but to hug her grandmother, whom she had spotted from across the way. An elderly couple sat next to me on a bench, and the man offered me a cigarette. I declined politely in Greek, and together we watched silently as the fading sun painted the Kozani clock tower gold.
Just blocks away, the atmosphere was far less vibrant. As I walked away from Plateia Nikis, the bustling shops and cafés gave way to empty storefronts, their smudged windows covered in white paper signs with big red letters that read “ΕΝΟΙΚΙΑΖΕΤΑΙ” — “for rent.”
Outside a bar on one of these side streets, I met up with Sokratis Moutidis, the longtime editor-in-chief of Chronos Kozanis, Western Macedonia’s oldest newspaper. He and two other residents who sat with us explained that these quiet streets were once home to nice shops.
The contrast illustrates how Western Macedonia is struggling to adapt to the end of coal, its core industry for over half a century.
Then entirely state-owned and known as the Public Power Corporation, PPC opened its first major lignite power plant in 1959, perched on the edge of a coalfield located about 15 miles north of Kozani. Its smokestack jutted from the valley floor, a symbol of Greece’s rapid modernization; it was the tallest structure in the nation upon completion.
In the decades that followed, PPC built a total of 15 coal-fired units across the region, which provided over 70% of Greece’s electricity at its high-water mark. (The newest one, Ptolemaida 5, was brought online in 2023 — four years after the country decided to eliminate coal — at a cost of nearly €2 billion. PPC will convert it to gas by 2028.) Western Macedonia’s mines swelled in step with its coal fleet, and by the early 2000s Greece was the world’s fourth-largest producer of lignite.
Coal created not just jobs for miners and engineers but also a bustling secondary economy of mechanics, truck drivers, and lunch-spot proprietors. As much as 20% of the working population was employed directly or indirectly by the sector, according to a 2020 World Bank study. Lignite generated a whopping 42% of Western Macedonia’s gross domestic product.
But as soon as world leaders signed the Kyoto Protocol in 1997, awakening at last to the reality of climate change, the clock started ticking, Ioannidis said. It became inevitable that someday time would run out for coal — in Western Macedonia and beyond.
The only question was when.
As mayor of Kozani from 2014 to 2019, Ioannidis was not content to wait around for an answer. In 2016, he organized the city’s first public discussion about life after lignite. He also convinced the World Bank to visit the region in order to create a road map for how it could move beyond coal.
But by the time the World Bank recommendations came out in 2020, the post-lignite era was already hurtling toward Western Macedonia. The year before, just months into his first term, Greek Prime Minister Kyriakos Mitsotakis had stood before the United Nations Climate Action Summit and pronounced that Greece would “close all lignite power plants, the latest by 2028,” an inspired target for a country in which the industry was so deeply entrenched. That timeline has since been accelerated to 2026.
“We lost many decades to understand the problem, to realize the problem,” said Ioannidis. “Now we don’t have time.”
Though Mitsotakis’ announcement was couched in soaring rhetoric about the imperative to deal with climate change, it was ultimately long-simmering regulatory and economic forces that brought lignite to its knees.
In 2005, the EU launched the Emissions Trading System, a cap-and-trade program that puts a price on carbon dioxide emissions. The scheme hit lignite especially hard because it emits more than other forms of coal do. Five years later, the EU clamped down on air pollution from industrial sources. Meanwhile, the cost of natural gas, wind, and solar power began to plummet. These trends converged, and as the region’s carbon price slowly crept up, the profitability of PPC’s lignite plants went down.
Still, the phaseout came as a surprise.
“In Greek, when we want to say we are in shock, we say ‘Our legs were cut,’” said Ioannis Fasidis, a 44-year-old coal miner and power plant worker who is now president of Spartakos, a major union of PPC workers, via Moutidis, who translated. “It was a shock.”
That shock is still reverberating throughout Western Macedonia.
No region in Greece, itself a shrinking nation, is losing people faster. Between 2011 and 2021, the year of the most recent census, Western Macedonia lost 10.3% of its population. It has one of the highest youth unemployment rates in Europe: In 2023, more than one-third of young people there were out of work, compared with nearly 22% nationwide and 11% across the EU.
The future of Western Macedonia, it feels, is slipping away — even as the region drives the increasingly ambitious Greek energy transition forward.
In April, Mitsotakis and PPC Chairman and CEO Georgios Stassis stood outside the decommissioned Kardia power plant and unveiled a €5.75 billion “green” vision for Western Macedonia.
Some of that plan is already underway — namely PPC’s colossal solar installations and the company’s work restoring already inactive mine lands. But it also included more aspirational proposals, like turning two lignite mines into pumped hydroelectric facilities and converting Ptolemaida 5 to a hydrogen-ready gas-burning facility. In total, PPC says the plan could create up to 20,000 construction jobs and 2,000 permanent jobs.
“If we wanted to be very fast in phasing out coal and developing renewable energy — and mostly solar — we had to leverage all of the weapons in our armory. There, we owned the land, we had space. We owned the grid connections,” explained Elena Giannakopolou, the chief strategy officer of PPC. “That’s why Western Macedonia was such a special place for us. It was our vehicle to the new day.”
I could see that new day dawning when I visited PPC’s expansive Western Macedonia facilities in September.
Immediately outside the silent turbine hall of the former Kardia power plant, whose four units were shut down between 2019 and 2021, electric boilers now sit to help heat Kozani’s buildings during the city’s chilly winters — a job previously done by the lignite plants. Across the street, construction was newly underway on a gas-fired thermal plant that will also help with heating. Five minutes up the road, PPC’s first-ever grid battery facility was being built. The red-and-white cooling tower of Ptolemaida 5 stood in the distance.
A short drive away was the Kardia mine, which once fed piles of lignite to the units of the power plant that shares its name. From within the mine, some PPC engineers explained how the great crater will gradually fill with rain and groundwater and be repurposed as a pumped-hydro station, an old-school form of energy storage that harnesses gravity to squirrel away electricity. Already, a deep blue pond sat on the mine floor as if to suggest the future.
Past the Kardia complex, fields of solar panels stretched so far that when I looked out from among them, I could see only the region’s most striking features in the distance: the occasional coal excavator rising like a skyscraper; the towers of the half-dead, half-alive Agios Dimitrios coal-fired plant; and the mountain peaks that ensconce the Ptolemaida basin, the physical delimiters of a region whose fate was determined by geological machinations long ago.
PPC’s rapid transformation from a lignite giant to a “powertech” firm that develops clean energy and gas is a microcosm of Greece’s energy transition more broadly.
Earlier this year, the country increased its renewable energy targets under its EU-mandated National Energy and Climate Plan. Previously, Greece aimed to get 66% of its electricity from renewables by 2030 — a figure it flirted with this spring. Now it’s targeting 76%, and the virtual elimination of fossil fuels from its grid by 2035. (PPC, meanwhile, says it will see its emissions plummet by a staggering 85% between 2019 and 2028.) Mitsotakis, whose country was once singled out as a laggard on clean energy, is now taking to the Financial Times’ op-ed pages to lecture other nations on “golden rules” for the green transition.
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For all the progress on renewables, however, fossil fuels are not yet in the country’s past.
Natural gas, that pesky “bridge fuel,” is on the rise in Greece. Once a comparatively small part of the Greek grid, it provided nearly 40% of the country’s power across 2024. The nation has opened major import infrastructure for liquefied natural gas, positioning itself as a hub for Europe, and is proudly courting Chevron and Exxon Mobil to explore for the fossil fuel off the coast of Crete.
Some influential groups are also pushing to keep burning coal.
One prominent example is the coal workers’ union led by Fasidis. We met at a shady café on a hot afternoon in Kozani, and Moutidis, the local journalist, translated. A serious but not unfriendly man, Fasidis brought his two preteen daughters along, who chimed in occasionally when Moutidis was stuck searching for a word.
Fasidis is in active negotiations with PPC about the future of his roughly 1,800 mine and power plant workers. Though he welcomes the company’s new investment plan, he was clear on what the union really wants.
“Our main goal is for lignite, coal, to be alive,” he said. “This is the main demand of the union.”
He clarified that it is “not an economical point of view” but rather one based on energy security concerns. Greece imports all the natural gas it consumes; lignite remains its core domestic fossil fuel. This fact offered Fasidis and his workers a brief reprieve three years ago, after Russia invaded Ukraine and spurred the worst European energy crisis since the 1970s oil shock that pushed Greece to embrace lignite to begin with.
“But it’s not realistic today to talk about lignite,” said Ioannidis, who later pulled up a chair and joined the conversation with Fasidis — a man he had clashed with as the mayor soothsaying the end of coal.
“Lignite is a dead man,” Ioannidis concluded.
That reality was hard to forget even when I stopped by the Agios Dimitrios power plant during my tour of PPC’s energy complex.
In the hulking facility’s coal yard, I was surrounded by screeching conveyor belts carrying lignite, and my eyes watered and nostrils stung from the caustic swirls of coal dust. But I could also see some telling graffiti spray-painted on one of the power plant’s cooling towers. A decade ago, activists had climbed the steel structure and left behind a message: “GO SOLAR” — a message that now, with all the challenges it brings, the region is heeding.
But for all the clean energy being built in Western Macedonia, the boom is creating little wealth for the people who live there.
Konstantinos Siampanopoulos, a 34-year-old resident of Kozani, is a case in point.
Siampanopoulos is a restless entrepreneur. Details of venture after venture dribbled out as we spoke over meze at a Kozani taverna. There’s the fur clothing brand he founded, the accounting firm he runs, and, most recently, a facility where locals can play the squash-like racquet sport padel.
Siampanopoulos is also a longtime investor in renewable energy, one of the few locals who managed to get in early on the region’s solar boom. In 2010, he and his father developed their first solar installations. In partnership with other investors, their portfolio grew to 16 megawatts, including some small hydropower projects. But as the country has become awash in solar, he told me, what was once a prescient and profitable bet has soured.
Holding up a phone displaying the real-time market dashboard from Greece’s grid operator, he showed me the problem for small investors. “Tomorrow, the price is zero. It’s zero for many hours,” he said. “We signed the contract that if the price is zero for more than two hours, we are not paid.”
Put simply: Greece often has more solar power than it can use. Plans to build energy storage will help alleviate this problem, but that’s small comfort for investors like Siampanopoulos right now. Under the current conditions, he and his coinvestors were hardly able to keep up with the loan payments on their installations, let alone earn an attractive profit. They sold 10.8 MW of their portfolio in August.
These price dynamics, among other challenges, have made it difficult for locals to profit from the energy transition.
Overall, at least 95% of the operational or licensed renewable projects in Western Macedonia are owned by large investors, per April 2024 data from Greece’s transmission and distribution grid operators shared by Siampanopoulos; he obtained and analyzed the data in his capacity as a member of the Kozani Chamber of Commerce and president of the local photovoltaic investors’ group. That means only a fraction of the wealth is going directly to residents.
“I characterize this as an air bridge, by which income is transferred from Western Macedonia to somewhere else,” said Lefteris Topaloglou, a professor who runs the Energy Transition and Developmental Transformation Laboratory at the University of Western Macedonia.
In one sense, this is nothing new. Although majority owned by Greece until 2021, PPC was still a single large entity — headquartered elsewhere, in Athens — that controlled the energy infrastructure in Western Macedonia.
But the coal-fired power plants made up for this centralized ownership with jobs. Solar provides neither significant revenue nor employment to residents. PPC declined to disclose the exact number of permanent jobs that its solar installations have created in Western Macedonia to date.
In some ways, this is a good thing. Solar results in so few jobs once installed because it requires no fuel and little maintenance. That’s one reason it is the cheapest form of energy, and that affordability is itself why solar is growing at blazing speed worldwide — giving humanity a chance to kick our self-destructive habit of burning fossil fuels like lignite.
Coal, by contrast, creates jobs because it is extractive. Humans must pilot excavators that disfigure the Earth to produce coal, which then must be transported by humans to power plants, where yet more humans oversee operations. Its economic benefits are a direct function of its pollution, of its destruction; its jobs are paid for with the health of workers and nearby residents and that of the planet.
But the point remains for the people of Western Macedonia: Solar isn’t bringing them jobs.
“This is the employment paradox of the green energy boom,” said Topaloglou.
On a brisk and sunny morning in early October, the marble sidewalks of Athens slick from the previous day’s uncharacteristic downpour, I met Alexandra Mavrogonatou in her office near the Hellenic Parliament.
She offered me an espresso, a comfortable seat, and a history lesson. In June 2022, she explained, Greece became the first country to receive European Commission approval for its €1.63 billion just-transition plan. Most of the money comes from the EU’s broader Just Transition Fund, which supports 96 regions across the bloc.
Mavrogonatou is the head of the directorate of strategic planning and coordination of funds for Greece’s Just Transition Special Authority. That means she oversees the implementation of the country’s just-transition program, from which Western Macedonia was allocated about €994 million. The rest is split between the country’s other main lignite area, Megalopolis, and then among the islands and other mainland regions.
To date, her agency has made some progress: It has approved projects amounting to 50% of the funds and inked contracts with awardees for almost 35% of the funds, she said. But through September, she told me, less than 5% of the money had actually been given to the beneficiaries.
“This percentage may seem low, but we need to take into consideration that we are a newly established program,” Mavrogonatou said. “We’ve had no projects coming from a previous programming period, so we started from scratch — from zero.”
Most of the funding approved by Mavrogonatou’s office so far is for projects in Western Macedonia, she said.
Entrepreneurship has been a main focus, and the office to date has greenlit more than 500 such investments for the region, she said. It funded the creation of a coworking space and a startup incubator in Kozani. The 22-person accounting firm Siampanopoulos manages received approval for funding, and he’s working on securing money for his padel hub, too. The agency has also funded regional support offices in Kozani and the city of Florina — “one-stop shops” for entrepreneurs, she said — as well as a skills development and employment center in Kozani.
But during my five days in Western Macedonia, locals dismissed these sorts of programs as not enough. They are not unwelcome, necessarily, but viewed as insufficient. Ioannidis called them “very, very soft actions.”
“We are full of soft actions and programs,” he told me, weeks before my conversation with Mavrogonatou, while on a break from his job managing a 40-person health clinic in town. As we spoke at his favorite café, the former mayor fielded a steady stream of greetings. Some passersby pulled up a chair, Ioannidis poured them a glass of beer, and they sat and chatted before continuing on their way.
“That’s enough with soft actions, trips, discussions, studies,” he said. “We need jobs. We need something concrete.”
Ioannidis’ frustration is shared by many in the region: Even though it’s been six years since Mitsotakis’ fateful announcement, there’s been no large-scale job creation, and there’s not a clear and broadly understood vision for how to change that.
Above all, the residents I spoke to feel that they’ve had no chance to participate in planning for what comes next.
When I brought up these criticisms to Mavrogonatou in Athens, she said she “totally” disagrees with the notion that locals have had no voice. She pointed to working groups in Western Macedonia, which are staffed by representatives from the local university and municipalities and which are under the supervision of the region’s governor. The idea, she said, is to provide a way for one unified stream of feedback to flow to Athens.
Be that as it may, the perception that the transition is being mismanaged is real — and that perception is eroding trust in the entire process. Ongoing field research from Fenia Pliatsika, a doctoral student in Topaloglou’s lab, found a high level of concern that the transition is suffering because of a lack of trust and “tokenistic participation,” echoing similar peer-reviewed findings published by Topaloglou and Ioannidis in 2022.
Perceived inconsistencies in the government’s stance on clean energy threaten to wash away what little confidence remains.
Again and again, throughout my time in Western Macedonia, residents called out two projects as confusing and unfair.
First, there’s the waste-to-energy facility. Under an EU regulation, Greece needs to rapidly decrease the amount of trash it puts into landfills. Its proposed solution is to construct six incinerators around the country that will burn garbage for energy. That includes a facility PPC intends to build at the site of Ptolemaida 5, to which waste would be trucked in from as far as the island of Corfu. Opposition runs deep. Fasidis singled it out as the only proposed new investment the union is against. As I returned from touring PPC’s energy complex, a protest against the plant was winding down, the shouts of opposition still ringing through Kozani’s narrow streets.
Then, there is the lignite mine in the village of Achlada, near Florina. The facility, which is not owned by PPC, ships its coal across the border to North Macedonia, home to one of the most polluting power plants in Europe. The mine has a contract in place until 2028.
Locals make the point that the government is all but eliminating the industry that has anchored their economy for decades in the name of a green energy transition while embarking on two projects that undermine that very effort. In their view, the government is still allowing dirty activities — but only the ones it finds convenient.
Back in Athens, Mavrogonatou urged patience. She stressed that her agency has had only a few years to achieve something difficult — the wholesale transformation of a regional economy — and that results will take time. The projects approved so far will create 2,500 permanent jobs in Western Macedonia, she said. Her team has until 2030 to spend the money.
“We’re trying to do the best we can for the area,” she said. “We’re not perfect. No one is perfect in this world, but I am pretty sure that very soon, especially during 2026, the area will start seeing the first results of our effort.”
The microchip factory her office approved for funding in 2024 is one example. Greek telecoms firm Intracom plans to break ground soon on a €45 million facility and complete construction by 2027. It will create at least 150 skilled jobs.
She also pointed to her agency’s plan to build an “innovation zone” at the University of Western Macedonia’s main campus. It’s a sweeping idea that includes everything from a green hydrogen hub to a supercomputer, as well as mechanisms for university researchers to commercialize their work via startups. Funding for the project has been approved, but construction has not yet begun.
The projects are all part of the nebulous plan to turn the energy-rich region into something of a tech hub for Greece.
Perhaps the most promising venture on this front is one that Mavrogonatou’s office has nothing to do with: a huge data center proposed by PPC as part of its April investment plan.
The €2.3 billion, 300-megawatt facility would replace the lignite field outside the Agios Dimitrios plant. PPC says it can have the data center online by 2027, a potentially appealing timeline for tech firms that are struggling to swiftly secure energy to power their artificial intelligence strategies.
“Time to market is one of the most critical, if not the most critical, points in this decision,” said Giannakopolou of PPC. “Building the building is not difficult. What’s difficult is to have grid connections, to have electricity to power the data center.”
If the demand is there, PPC says it can scale the facility to 1,000 megawatts — a move that would make it among the largest data centers in Europe and also spur the company to outfit Ptolemaida 5 with a 500 MW combined-cycle gas turbine. The facility would, in theory, help propel the area’s startup ecosystem by attracting young, tech-savvy professionals. PPC declined to disclose exactly how many jobs the data center or its related gas-turbine upgrades would generate.
But these visions of a high-tech economy are tentative at best. PPC has to convince a major tech company to set up a data center in Western Macedonia — and that’s just the first step. PPC said that negotiations are active but declined to provide further detail.
Marquee projects promised to the region have fallen apart before. A €1.4 billion lithium-ion battery manufacturing facility was supposed to bring more than 2,000 permanent jobs; it was abandoned late last year. An €8 billion green-hydrogen complex that pledged an audacious 18,000 direct jobs fizzled out after failing to secure European Commission funding.
Amid these false starts, the pleas for patience from Athens have worn thin. As the journalist Moutidis put it in a message after I spoke with Mavrogonatou, “Since 2019, they’ve been saying, ‘Next year things will be better — just be patient.’”
The hope, of course, is that the cynicism is wrong. That the big ideas do work out — that, very specifically, the data center gets built. The residents I spoke to want the region to see a large-scale project that isn’t coal, not only for the much-needed jobs it will bring but also for the symbolic weight — for the suggestion that it’s possible for Western Macedonia to reinvent itself.
“The first buildings, the beginning of the construction — it will be a good signal,” said Ioannidis. “We need a good signal here. We need a flagship investment. This is the main problem: The people here don’t see a good signal and lose their belief in this process.”
“This is not political,” he clarified, before pausing, searching for the word in English. “It’s psychological.”
In 2017, the early leaders in energy storage made an audacious bet: 35 gigawatts of the new grid technology would be installed in the United States by 2025.
That goal sounded improbable even to some who believed that storage was on a growth trajectory. A smattering of independent developers and utilities had managed to install just 500 megawatts of batteries nationwide, equivalent to one good-size gas-fired power plant. Building 35 gigawatts would entail 70-fold growth in just eight years.
The number didn’t come out of thin air, though. The Energy Storage Association worked with Navigant Research to model scenarios based on a range of assumptions, recalled Praveen Kathpal, then chair of the ESA board of directors. The association decided to run with the most aggressive of the defensible scenarios in its November 2017 report.
In 2021, ESA agreed to merge with the American Clean Power Association and ceased to exist. But, somehow, its boast proved not self-aggrandizing but prophetic.
The U.S. crossed the threshold of 35 gigawatts of battery installations this July and then passed 40 gigawatts in the third quarter, according to data from the American Clean Power Association. The group of vendors, developers, and installers who just eight years ago stood at the margins of the power industry is now second only to solar developers in gigawatts built per year. Storage capacity outnumbers gas power in the queues for future grid additions by a factor of 6.5, according to data compiled by Lawrence Berkeley National Laboratory.
“Storage has become the dominant form of new power addition,” Kathpal said. “I think it’s fair to say that batteries are how America does capacity.”
Back in 2017, I was covering the young storage industry for an outlet called Greentech Media, a beat that was complicated by how little was happening. There was much to write about the “enormous potential” of energy storage to make the grid more reliable and affordable, but it required caveats like “if states change their grid regulations to allow this new technology to compete fairly on its merits, yada yada yada.”
Those batteries that did get built in 2017 look tiny by today’s standards. The locally owned utility cooperative in Kauai built a trailblazing 13-megawatt/52-megawatt-hour battery, the first such utility-scale system designed to sit alongside a solar power plant. And 2017 saw the tail end of the Aliso Canyon procurement, a foundational trial for the storage industry in which developers built a series of batteries in Southern California in just a handful of months to shore up the grid after a record-busting gas leak — adding up to about 100 megawatts.
“You saw green shoots of a lot of where the industry has gone,” said Kathpal.
California passed a law creating a storage mandate in 2010, then found a pressing need for the technology to neutralize the threat of summertime power shortages. Kauai’s small island grid quickly hit a saturation point with daytime solar, so the utility wanted a battery to shift that clean power into the nighttime. These installations weren’t research projects; they were solving real grid problems. But they were few and far in between.
Kathpal recalled one moment that encapsulated the storage industry’s early lean era. At the time, he was developing storage projects for the independent power producer AES. One night around midnight, he parked a rented Camry off a dirt road and pointed a flashlight through a sheet of rain. It was his last stop on a trip to evaluate potential lease sites for grid storage ahead of a utility procurement — looking at available space, proximity to the grid, and stormwater characteristics. But once the utility saw the bids, it decided not to install any batteries after all.
“The storage market is built not only from Navigant reports but also from moments like that,” he said. “We had to lose a lot of projects before we started winning.”
Now that same utility is putting out a call for storage near its substations — exactly the kind of setting Kathpal had toured in the rain all those years ago.
Indeed, many of the projects connected to the grid this year started with developers anticipating future grid needs and putting money on the line for storage back around the time ESA was formulating its big goal, said Aaron Zubaty, CEO of early storage developer Eolian.
“Eolian began developing projects around major metro areas in the western U.S. starting in 2016 and putting the queue positions in that then became operational in 2025,” Zubaty said. The 200-megawatt Seaside battery site at a substation in Portland, Oregon, is one example.
Though the storage industry pioneers somehow nailed the 35-gigawatt goal, market growth defied their expectations in several important ways.
ESA had expected more of a steady ramp to the 35 gigawatts, said Kelly Speakes-Backman, who served as its chief executive officer from 2017 to 2021. But the storage market ran into plenty of false starts, such as when states passed mandates to install batteries but never enforced them, and when federal regulators ordered wholesale markets to incorporate storage but regional implementation dragged on for years.
The ESA report predicted that 2018 deployments would cross the 1-gigawatt threshold, which didn’t actually happen until 2020. But real installations significantly outpaced the expected numbers in the run-up to 2025. The group hoped to hit 9.2 gigawatts installed this year, and instead the industry is on track to deliver 15 gigawatts.
“Once it hit, it really hit,” Speakes-Backman said.
The regional breakdown of storage growth didn’t play out as ESA expected, either. The analysis anticipated that the Northeast would install more than 10 gigawatts, nearly as much as the Southwest (including California and Hawaii); after all, it noted, New England states had passed “aggressive greenhouse gas reduction policies.”
In fact, the Northeast has done exceedingly little to build large-scale storage. (Zubaty told me that “largely dysfunctional power markets combined with utilities that have excessive regulatory capture” thwarted many good battery projects there.)
But other regions surpassed ESA’s expectations. California, Texas, and Arizona alone hold roughly 80% of all U.S. battery storage capacity. This lopsided concentration of storage could be seen as a weakness of the industry. Noah Roberts, executive director of the recently formed Energy Storage Coalition, which advocates for storage in federal arenas, said the pattern reflects how storage has sprung up in spots that suffer acute grid stress.
“Where energy storage has been deployed to date, it is and has been concentrated in areas that have had the greatest reliability need,” he said. “That is Texas and California, where in the early 2020s there were blackouts or brownouts that were quite significant.”
Now, Roberts said, other regions can look at California and Texas for empirical data on how the storage influx has helped reliability while lowering grid costs, for instance by avoiding power scarcity during heat waves and pushing down peak prices. “We’re really seeing the broadening of the geographic footprint of energy storage deployment,” he said, to regions like the Midwest and the mid-Atlantic, which are grappling with unanticipated load growth.
Indeed, the ESA did not foresee the artificial intelligence boom sending power demand through the roof. Instead, its report predicted, “Electrified transportation will likely provide the largest source of new system load.” Now the storage industry has emerged as the biggest player in constructing firm, on-demand power plants, at the exact time that rapid power construction has become the key limiting factor in the AI arms race.
The storage market outdid expectations in one other major way. In 2017 the storage industry was intently focused on getting batteries installed, not so much on where they came from. Since then, bipartisan sentiment has shifted from unfettered global trade to a distinct preference for American manufacturing. The U.S. has made batteries for electric vehicles for years now, but the lithium iron phosphate (LFP) batteries favored for grid storage have come almost exclusively from China. Now manufacturers are opening domestic cell production for grid storage, just in time for new rules that constrain federal tax credits for battery projects with too much material from China.
LG Energy Solution opened a factory to produce battery cells for grid storage in Michigan this summer that is capable of producing up to 16.5 gigawatt-hours at full capacity; the company expects to raise its North America capacity to 40 gigawatt-hours by the end of 2026. “All of our projects integrated before 2022 combined are smaller than some of our newer individual projects,” noted Tristan Doherty, chief product officer of LG Energy Solution subsidiary Vertech, which focuses on grid batteries.
Tesla is opening domestic LFP battery fabrication in 2026. Fluence announced the first shipment of its “domestically manufactured energy storage system” in September. Newcomers with novel chemistries for longer-duration storage are joining the fray, such as Form Energy and Eos Energy, both of which operate factories outside Pittsburgh.
“By the end of next year, we anticipate reaching the milestone of producing as many domestic energy storage battery cells as we need for demand,” Roberts said. “That is a pretty miraculous story that not many industries have the ability to say they’re able to accomplish.”
The storage industry was vindicated in stretching its aspirations beyond what many thought was possible. Those early adopters knew their technology was valuable, but even they didn’t guess how it would connect with the generational forces reshaping the U.S. economy, from AI to the onshoring of industry.
A clarification was made on Dec. 4, 2025: This story has been updated to reflect that LG Energy Solution’s goal to reach 40 GWh of battery-manufacturing capacity is for North America as a whole, not just for the company’s Michigan plant.
Geothermal energy is undergoing a renaissance, thanks in large part to a crop of buzzy startups that aim to adapt fracking technology to generate power from hot rocks virtually anywhere.
Meanwhile, the conventional wisdom on conventional geothermal — the incumbent technology that has existed for more than a century to tap into the energy of volcanically heated underground reservoirs — is that all the good resources have already been mapped and tapped out.
Zanskar is setting itself apart from the roughly one dozen geothermal startups currently gathering steam by making a contrarian bet on conventional resources. Instead of gambling on new drilling technologies, the Salt Lake City–based company uses modern prospecting methods and artificial intelligence to help identify more conventional resources that can be tapped and turned into power plants using time-tested technology.
On Thursday, Zanskar unveiled its biggest proof point yet.
The company announced the discovery of Big Blind, a naturally occurring geothermal system in western Nevada with the potential to produce more than 100 megawatts of electricity. It’s the first “blind” geothermal system — meaning that the underground reservoir has no visible signs, such as vents or geysers, and no data history from past exploration — identified for commercial use in more than 30 years.
In total, the United States currently has an installed capacity of roughly 4 gigawatts of conventional geothermal, most of which is in California. That makes the U.S. the world’s No. 1 user of geothermal power, even though the energy source accounts for less than half a percentage point of the country’s total electricity output.
The project is set to go into development, with a target of coming online in three to five years. Once complete, it will be the nation’s first new conventional geothermal plant on a previously undeveloped site in nearly a decade, though it may come online later than some next-generation projects.
“We plan to build a power plant there, and that means interconnection, permitting, construction, and drilling out the rest of the well field and the power plant itself. But that’s all pretty standard, almost cookie-cutter,” said Carl Hoiland, Zanskar’s cofounder and chief executive. “We know how to build power plants as an industry. We’ve just not been able to find the resources in the past.”
Prospecting is where Zanskar stands out. While surveying, the company’s geologists found a “geothermal anomaly” indicating the site’s “exceptionally high heat flow,” according to a press release. The team then ran the prospecting data through the company’s AI software to predict viable locations to drill wells in order to test the temperature and permeability of the system.
Zanskar drilled two test wells this summer. Roughly 2,700 feet down, the drills hit a porous layer of the resource with temperatures of approximately 250 degrees Fahrenheit. The company said those “conditions exceed minimum thresholds for utility-scale geothermal power” and “contrast greatly” with other areas in the region, which would require digging as far down as 10,000 feet — potentially viable for the next-generation technologies Zanskar’s rivals are pitching.
The firm’s announcement comes as the U.S. clamors for more electricity, in large part because of shockingly high forecasts of power demand from data centers. Many of the tech companies developing data centers, like Google and Meta, are eager to pay big for “clean, firm” power — electricity that is carbon-free and available 24/7. Geothermal, whether advanced or conventional, is a tantalizing option for meeting those standards, and tech giants already anchor some next-generation projects.
Ultimately, Zanskar thinks it can convince data centers to colocate near where it finds resources.
If it’s able to find additional untapped resources that are suitable for conventional technology, Zanskar could deliver new geothermal power faster and cheaper than the flashier startups on the scene can. Those firms, including Fervo Energy and XGS Energy, are making significant progress in bringing down the cost of their drilling techniques, but they are still using new technologies that remain more expensive than the traditional approach, which has been refined over time.
“The core reason we started the company is we came to believe that the Department of Energy’s estimates of hydrothermal potential were just orders of magnitude too low and were all based on studies that are over 20 years old,” Hoiland said. “We think that there’s 10 times more out there than they thought, and that every one of those sites can be 10 times more productive in terms of the number of megawatts they can generate.”
Among the notable cheerleaders of this same theory? The chief executive of the leading next-generation geothermal company. Responding to a post on X from Zanskar cofounder and chief technology officer Joel Edwards describing how much more conventional geothermal remains untapped, Fervo CEO Tim Latimer wrote, “Joel makes a great point about geothermal that you see all the time in resource development: when technology improves, turns out there’s a lot more of something than we thought.”
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