Hot water and low river levels have hampered nuclear power in Europe this summer, forcing a reckoning over plant preparedness.

Europe’s increasingly hot summers come with a worrying trend. The air conditioning that the continent long eschewed as an American indulgence is becoming a necessity, and some of the nuclear reactors needed to run those cooling units are tapping out right as thermometers spike. This summer was especially bad: The series of extreme heat waves that roasted Europe, killing thousands and fueling historic wildfires, also severely impacted the rivers that provide water to cool thermal power plants such as nuclear stations.

In France and Switzerland, nuclear plants went offline as river temperatures rose, to prevent the discharge of warm water into sensitive aquatic ecosystems. In Romania, Hungary, and Bulgaria, nuclear plants built along the Danube River either shut down or reduced output as drought dropped the water levels below intake pumps.

Critics of nuclear power have seized on the moment to challenge whether nuclear energy is as reliable and efficient as its supporters claim.

“Strange that anyone would support new nuclear, which depends on cooling, in the face of an ongoing superlinear global temperature rise,” Mark Z. Jacobson, a Stanford University professor who has long advocated for replacing atomic energy with renewables such as wind, solar, and hydropower, wrote in a post on X after France took 6.3 gigawatts of nuclear plants offline amid the heat wave.

At the heart of the issue is the large supply of water that nuclear plants need to cool their reactors. The problem is most acute in Europe, where many plants rely on rivers — unlike in Asia, where most stations are built near the ocean, or in North America, where reactors more often have cooling towers that help avoid problems with overheated water supplies. Experts say that Europe’s situation has more to do with how its individual plants are engineered and that the flaws are fixable.

“There are multiple solutions to this,” said Madison Hilly, managing director of the nuclear consultancy Radiant Energy Group. But ​“if you don’t like nuclear, this is the annual occurrence that basically allows you to try … and say, ​‘No, actually nuclear is not reliable and it can’t be built for a changing climate.’”

The climate challenge for Europe’s nuclear plants is twofold. First, above-average river temperatures trigger environmental regulations barring the release of water that’s too warm. Second, drought conditions mean that the water levels are too low for the plants’ intake pumps to work. Along the Danube, the intake pumps that pull cooling water into the plant weren’t constructed to handle the low water levels reached this summer. When these plants were designed and built between the 1970s and 1990s, ​“there was no awareness of the dramatic changes in river flow rates and temperatures that we are witnessing now,” said Jacopo Buongiorno, the director of science and technology at the Massachusetts Institute of Technology’s Nuclear Reactor Laboratory.

Still, he said, ​“moving the intake is technically feasible, albeit expensive.”

“One has to put things in perspective. Even a severe heat wave like the one experienced by Europe this summer reduces the average capacity factor of these plants by only a few percent on an annual basis,” Buongiorno said. ​“And while all the attention goes to a handful of struggling facilities located on problematic rivers, the vast majority of nuclear power plants go through the summer heat without any issue. Nuclear plants remain the most reliable power generators on the planet.”

Making nuclear plants more resilient

The most obvious solution to water levels dropping below the intake pump is, as Buongiorno described, to lower the equipment. It’s difficult to say exactly how much that would cost, since the renovation of the relevant components would amount to a bespoke engineering project.

But virtually every structure at a nuclear plant is expensive, and renovating part of an existing plant typically costs more than building that section from the ground up. Case in point: Most nuclear plants in the U.S. and Asia were built with cooling towers, the hyperboloid structures that are often the most visible component of a nuclear plant and which prevent the discharge of too-hot water. The towers also allow a plant to recirculate and reuse water in a closed-loop cycle. In 2009, a study that Tetra Tech prepared for California’s Ocean Protection Council found that adding a cooling tower to a built plant would cost about $87 million. Accounting for inflation, that would be roughly $135 million today. Such renovations also take years.

The recent disruptions ​“call for an upgrade in Europe’s nuclear preparedness for extreme climate events that sadly are now a new norm,” said Adam Błażowski, the Poland-based chair of the pro-nuclear climate group WePlanet.

As a short-term solution to the water-level problem, the Hungarian government sank two barges near the Paks nuclear power station, Hungary’s only such plant, to artificially hike the river levels enough to keep water flowing into the plant’s two units.

While ​“numerous ideas and technical solutions for securing the cooling water needed for operation have appeared in the press and on social media,” cautioned the HUN-REN Centre for Energy Research, a government laboratory for studying nuclear and renewable energy, ​“reaching a final, well-founded decision requires the professional evaluation of nuclear safety and electricity generation alongside a number of other considerations — navigation, water and agricultural management, flood protection, and so on.”

“However tempting these proposals may seem from the standpoint of security of supply, economic efficiency — and, should the water level later rise on a sustained basis, the restart of the other units — they conflict with the fundamental principles of nuclear safety and are therefore unacceptable under any circumstances,” the organization said in the statement.

Still, the HUN-REN Centre noted, the problems with specific nuclear plants in France, Romania, and Hungary shouldn’t detract from the critical role nuclear has played in keeping the lights on across the region.

“In these very days, avoiding a collapse of the electricity system owes much to the nuclear power plants operating in the Czech Republic and Slovakia — which are almost entirely identical to Paks NPP but use cooling towers instead of fresh water cooling,” the HUN-REN Centre said. ​“This also demonstrates that nuclear power plants with different cooling solutions respond differently to extreme hydrological conditions.”

A prime example in Arizona

For proof that nuclear plants can be designed to operate in extreme heat and drought, simply look to Arizona.

The three-reactor Palo Verde nuclear plant provides more than one-quarter of Arizona’s electricity. Perennially drought afflicted, the Copper State — now facing fresh cuts to its allotment from the Colorado River under the Trump administration’s plan to ration the region’s dwindling freshwater source — built the plant to run on recycled wastewater from Phoenix, 50 miles away. It could serve as a model for future plants.

“Palo Verde uses recycled water from the city of Phoenix, so it’s pretty much self-sustaining. It’s also an example of brilliant engineering,” Buongiorno said. ​“They managed to build and successfully operate a three-reactor nuclear power plant in the middle of the desert, without becoming a burden on the city water supplies.”

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For next-gen geothermal to scale, drilling costs must drop. Startup Hephae says its novel tech can make that happen — and developers like Fervo are giving it a try.

Thousands of feet beneath the desert valley of southwest Utah, a slender tool tucked inside a drill pipe is barreling through hot granite. The rod-shaped device, built by the startup Hephae Energy Technology, is a tracker of sorts, wirelessly sending data to help operators above steer the drill below and to measure rock conditions.

The work is underway at Fervo Energy​’s Cape Station, the largest project in the nation using nascent techniques to tap earth’s heat for clean energy. The 500-megawatt endeavor could usher in an era of next-generation geothermal development — but only if the industry can bring down drilling costs.

That’s where tools like Hephae’s can help.

Oil and gas firms have long used similar ​“measurement-while-drilling systems” to bore holes underground. But off-the-shelf parts aren’t designed to withstand the higher rock temperatures that geothermal companies aim to reach, which makes the equipment less efficient and costlier to operate.

Hephae’s founders, veterans of the fossil fuel industry, saw an opportunity to create a more advanced version for the burgeoning next-gen geothermal market. ​“We realized that companies like Fervo need the same exact tools that we’ve been working on for the last 45 years,” Steve Krase, Hephae’s CEO, recently recalled.

“They just need to work a hell of a lot hotter,” he added.

Hephae deployed its high-temperature device for the first time commercially at Cape Station earlier this year and has since used it there it additional times, Krase said. His firm will soon ship another of its high-tech rods to the startup Mazama Energy, which has started drilling its commercial pilot facility near the Newberry Volcano in central Oregon.

These and other next-generation geothermal projects are poised to become a significant source of on-demand electricity in the western U.S. over the coming decades. Unlike traditional geothermal plants, the newer systems don’t rely on finding natural hot-water pockets to generate heat; they can go wherever rocks are sufficiently scalding.

Yet the fledgling sector will struggle to scale unless companies dramatically reduce the time and money it takes to drill new wells — each of which can require millions of dollars, and together represent as much as half the expense of building new geothermal plants.

“Any way that you can get geothermal to be [cost] competitive with other sources of energy, like nuclear, solar, and wind, … will be pretty crucial,” said Zainab Gilani, an energy and power research associate at Cleantech Group, a consulting firm.

Houston-based Hephae is among a growing number of drilling-focused firms working to reach that goal. The company — whose name evokes the ancient Greek god of fire, Hephaestus — raised nearly $18 million in venture capital funding in July to build more tools to rent to geothermal developers.

All told, seven startups have secured $393 million in total venture investment since 2021 to develop cutting-edge drilling systems and components for geothermal power, according to Cleantech Group. That includes Quaise Energy​’s recent $134 million fundraise to advance its rock-melting technology and build its first geothermal plant, also near Oregon’s Newberry Volcano.

Geothermal firms ​“are basically trying to get underground as cheaply as possible,” said Stephanie Díaz, a senior associate for technology and innovation at BloombergNEF. She said the pursuit is a ​“rising tide that lifts all boats,” given how innovation spreads.

Investors are backing firms along the supply chain as a way to get exposure to the geothermal market, but without taking on the risk of building a first-of-a-kind project. ​“Instead of having to figure out an entire power plant, you just need to figure out one component that is essential to creating the power plant,” Díaz said.

How Hephae’s tech could curb geothermal costs

Krase and his co-founder, John Clegg, launched Hephae in 2020 to adapt their oil and gas expertise for geothermal wells.

Their measurement-while-drilling system fits into a thick steel tube that connects to the rock-cutting drill bit. Sensors and rounded circuit boards — stacked like chips in a Pringles can — gather subsurface data and transmit it through a sequence of pressure pulses, enabling engineers to steer the drill through the challenging environment.

Conventional versions of the tool are built to operate at relatively lower temperatures — around 175 degrees Celsius (347 degrees Fahrenheit) — where oil and gas reserves are typically found. But for geothermal firms, the higher the rock temperature, the more energy they can wring out of the system, making each well more cost-effective and productive.

Right now, that means geothermal developers must occasionally pause for extended periods to cool the drilling fluid inside the wells to avoid overheating the electronics. This ​“nonproductive time” can cost operators roughly $500,000 to $1 million per well, since they’re still paying to rent a drilling rig they’re not using, according to Krase.

Hephae says its unique design can withstand temperatures up to 210℃, reducing work delays by directing heat away from the sensors and circuits as they operate. Before shipping the tool to Cape Station, the company put the technology through its paces at an Oklahoma test facility and in Texas at a high-temperature gas well — another possible market for Hephae.

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“Fervo has been really supportive, because they know their success depends on being able to get to the good rock,” Krase said.

Fervo, for its part, has already made significant strides in recent years to reduce drilling times and access deeper resources in Utah. In May, the startup became the first next-gen geothermal firm to go public, and Cape Station is expected to be the largest project of its kind in the world when it comes fully online by 2028.

The company declined to comment for this story, but it shared an earlier statement from Elliot Howard, Fervo’s director of drilling and completions.

“Fervo is encouraged by the early progress of our collaboration with Hephae, whose novel high-temperature innovations have the potential to contribute positively to [enhanced-geothermal-system] economics, unlock higher-energy geothermal resources, and further cement the competitiveness of next-generation geothermal power,” Howard said in a July press release announcing Hephae’s fundraise.

With its new funding, Hephae plans to triple the number of tools in its arsenal, from six to 18 by the second quarter of next year. That total could reach 40 tools by the end of 2027 as Fervo, Mazama, and future partners advance their geothermal projects.

Hephae is also investing in R&D to design systems for temperatures above 300℃, which it hopes to launch by 2030.

Gilani of Cleantech Group said that Hephae’s partnerships with Fervo and Mazama make it well positioned to grow with the wider next-gen geothermal industry. If Hephae can play a part in bringing the projects online, ​“that will both help Hephae to scale and will also help the industry overall,” she said.

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Last year, Gov. Newsom vetoed bills promoting home batteries, smart thermostats, and EV chargers to curb energy costs. Will he do the same this year?

Last year, California Gov. Gavin Newsom vetoed a slate of bills meant to expand virtual power plants that could offset the state’s fast-rising electricity costs. Will he do the same this year?

Earlier this month, two virtual power plant bills made it through a key legislative hurdle. Lawmakers must vote on the bills by Aug. 31. Should they pass, Newsom, a Democrat, would have until the end of September to sign or veto them.

Californians pay some of the most expensive electricity rates in the continental U.S., an issue of increasing political salience. Climate advocates, clean energy groups, and supportive lawmakers say the state can curb these costs by tapping into its nation-leading fleet of rooftop solar–charged batteries, remote-controllable EV chargers, and other household devices — in other words, the collective components of virtual power plants.

The bills propose two different approaches for using VPPs to bring down costs: Senate Bill 913 would harness them to blunt the edge of costly grid peaks, while Senate Bill 905 could encourage California’s major utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — to use VPPs to reduce costly grid investment.

“If we can call on these resources, it is a massive win-win. People get paid, and it also saves everybody in California money,” Sen. Josh Becker, a Democrat who authored both bills, said at a Monday press conference in Sacramento promoting ​“local, affordable” clean energy policies.

SB 913 would give the California Public Utilities Commission until mid-2028 to craft regulations that allow VPPs to play a role in providing resource adequacy. That’s the term for the increasingly costly services that every utility and community energy provider must secure from gas-fired power plants, battery banks, and other dispatchable resources to keep the grid running when demand for power peaks.

VPPs could cover more than 15% of the state’s peak grid demand and deliver $550 million in annual utility customer savings by 2035, according to a 2024 analysis by consultancy The Brattle Group for GridLab.

“Many of these resources are sitting on the sideline because our rules have not kept up with technology,” said Becker, who also penned one of last year’s vetoed VPP bills.

VPPs face multiple barriers to being counted toward resource adequacy, from measurement protocols that erode their value during heat waves to rules that ban home batteries from getting credit for power they inject back onto the grid.

Meanwhile, Californians are paying roughly $1 billion per year to extend the lives of fossil-fueled ​“peaker” gas plants needed for only a handful of hours per year, he said. ​“We can get rid of those if we take better advantage of what’s already in people’s homes.”

SB 913 has won backing from dozens of environmental groups, trade organizations, and companies that manufacture, install, and manage the devices that constitute VPPs. Utilities Pacific Gas & Electric and Southern California Edison withdrew their opposition to the bill after amendments were added to it in late June.

California leads the country in home batteries and electric vehicles, and has millions of homes that could adjust the power usage of smart thermostats, water heaters, and other devices during the handful of hours per year when the grid is under the greatest strain.

Distributed batteries could be a particularly powerful tool. A July 2025 utility test of home batteries delivered more than 500 megawatts of grid relief over a two-hour period corresponding to when California’s grid tends to face its greatest stress during summertime heat waves.

The state currently has 2.5 gigawatts of residential batteries and more than 600 megawatts of batteries at commercial properties, according to the California Energy Commission.

SB 913 could make it more lucrative for households with these ​“behind-the-meter batteries” to commit their spare power to the grid. That could encourage more participation in VPP programs, said Brandon García, California policy director at trade group Advanced Energy United.

It’s particularly important to create new incentives for households with batteries to participate in VPPs given that California’s largest such program faces the threat of being defunded and disbanded, he said.

That program is called Demand Side Grid Support, and it has grown to one of the largest VPPs in the country, including nearly 75,000 homes with smart thermostats and flexible load devices, and nearly 130,000 homes with batteries. But DSGS is operated by the California Energy Commission using state taxpayer funds — and under a budget proposal from Newsom’s administration, that funding could be cut and the program shut down next year.

Many of the groups supporting SB 913 are also calling on Newsom and lawmakers to extend DSGS for a few more years, to avoid stranding the companies that have invested and the households that have enrolled in it.

“If there’s not a program to keep these resources online with some level of compensation until a resource adequacy pathway is created, those resources will go somewhere else,” García said.

In an echo of debates over rooftop solar in California, the state’s Public Utilities Commission and utilities have argued that it’s unfair to pay households for VPP participation, because it shifts the costs of running the grid onto utility customers who don’t have batteries, EV chargers, or other eligible devices.

García said that allowing VPPs to compete with gas plants, utility-scale batteries, and other providers of resource adequacy could help resolve these concerns. That’s because VPPs competing in those markets ​“only get enrolled if they’re lowest-cost resources — and we are confident that they will be the lowest-cost resources.”

SB 905, meanwhile, targets an even bigger cost driver in California: utility grid investments.

Among the bill’s wide array of utility affordability measures is a provision that would require the Public Utilities Commission to establish ​“grid utilization” metrics for the state’s three big utilities. That data could reveal where utilities are using their existing grids more or less efficiently, and potentially encourage them to employ batteries, flexible-load controls, and other VPP-style approaches to smooth out the peaks in electricity demand that drive much of the need for new grid infrastructure.

California’s utilities are planning tens of billions of dollars of investments on their sprawling distribution grids to keep up with growing power demand and mitigate wildfire risks. Using VPPs to reduce peak loads on those circuits and substations could allow them to defer billions of dollars of those investments, reducing upward pressure on rates, Becker said.

“We’re not saying we’re not going to build anything new,” Becker told Canary Media in a Monday interview. ​“But let’s make the best use of the existing resources that are already out there, that we’ve already paid for, before we go off spending a lot of money on new resources.”

It’s unclear whether Newsom will respond to this year’s VPP policies differently than he did last year’s. The three bills he vetoed in 2025 were passed by large majorities and proposed relatively minor changes in state VPP policy. Newsom’s veto statements cited the risk that they could disrupt existing grid reliability and planning methods.

Those arguments haven’t sat well with lawmakers pushing for VPP reforms. ​“We should be leaning in a lot more to innovation, especially on clean energy,” state Assemblymember John Harabedian, a Democrat who authored one of the VPP bills vetoed last year, said at an event in Sacramento earlier this month. ​“How do we utilize the grid in a more efficient way? I think technological innovation will help us do that.”

Becker declined to predict if Newsom would sign his VPP bills. ​“We’re focused on getting it passed,” he told Canary Media. ​“Then we’ll focus on the governor’s team and the governor’s reply.”

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