In June 2024, a small company called Zanskar purchased a geothermal power plant in New Mexico that was failing fast. The water coming from the underground reservoir was getting colder by the day, making the plant uneconomical to run.

Now, two years later, that plant is running at full capacity again, thanks to a new well. With the help of advanced modeling and modern drilling technology, the company was able to identify a better potential well site, drill down thousands of feet, and revive the entire operation.

As the world looks for more sources of emissions-free electricity that are available 24-7, Lightning Dock shows there’s still hidden potential deep beneath our feet. 

Conventional geothermal power plants rely on having the right underground conditions. Water flows through fractured hot rocks to harvest heat and then through a power plant to generate electricity. If the water isn’t hot enough or not enough flows, the power plant can’t work efficiently.

Lightning Dock came online in 2013, and the site historically had two production wells that were used to feed the power plant. It’s common to see temperatures drop at a well site over time, typically at a rate of 1 to 2 °F per year. In the period before Zanskar took over the site, Lightning Dock saw temperatures drop by 50 °F over five years, a rate of 10 °F per year. When the company purchased the facility, the water going into the power plant was just 250 °F, while the plant was designed to operate at temperatures of at least 310 °F. 

When Zanskar mapped the underground conditions at Lightning Dock using advanced modeling techniques, they discovered that the wells were only hitting the very top of the reservoir there. Those production wells were quite shallow (at just 2,500 feet deep) and not in the best location, says Joel Edwards, Zanskar’s cofounder and CEO.

The company’s modeling predicted that if the company were to drill another, deeper well in a new spot, the plant would be able to run efficiently. The team drilled a new well that reaches a depth of 8,000 feet and started operation in May 2025.

After a full year, the well is still flowing at more than 4,000 gallons per minute. The plant has “completely turned around,” Edwards says. “It looks really exciting.”

The data so far shows that the plant should be successful for years to come. “Ultimately you need to run these things for long time frames to get confidence in their performance over long time frames,” Edwards says.

The progress at Lightning Dock could be good news for other geothermal sites too. The conventional wisdom in geothermal energy is that the deeper you go, the hotter it gets. But there’s usually a trade-off: With those depths come rocks that are packed tighter together. So drilling deeper could mean the hot water can’t flow as effectively, a problem for anyone trying to use it to generate electricity in a power plant.

What the team found, however, was that the flow actually increased in the area where they drilled the new well. “That fundamentally changes how you think about not just Lightning Dock but all hydrothermal assets in America and what the potential can be for all of them,” says Ben Brenner, director of federal affairs at Zanskar. 

Over the past year of operation, Lightning Dock generated over twice the electricity it would have with the old wells. This is a relatively small power plant, with a capacity of 15 megawatts going to the local grid (about enough to power 11,000 US homes).

Oil and gas developers have chased resources deeper underground over the past few decades. Operations started relatively close to the surface, but oil and gas production can stretch down 20,000 feet or more today. “I think that arc is going to play out in geothermal,” Edwards says. While typical geothermal well fields range from 3,000 to 5,000 feet deep, it could become more common to go deeper in the future, he adds.  

The company plans to do further development at the Lightning Dock site: with a few years of development and an upgrade to the power plant, it could get even more electricity out of this area, Edwards says.

There’s been a lot of buzz and investment in enhanced geothermal systems—projects that aim to expand where geothermal resources can be used. Fervo Energy, for example, uses fracking techniques to open up rock that would otherwise be too closed off for traditional geothermal energy.

But there’s still plenty of “low-hanging fruit” in the geothermal world, Edwards says. Many of these conventional resources have plenty of potential—they just need a second look.

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Outside the small town of Paducah, Kentucky, a wealth of uranium is locked away in thousands of storage cylinders filled with waste material from a now-closed nuclear enrichment facility. Lasers could help get it out.

A company called Global Laser Enrichment (GLE) is looking to reprocess this old material with a new technology called laser enrichment. It could be more efficient than conventional enrichment methods, allowing the company to refresh the material and produce feedstock at the same concentration as a natural mined source. And in the future, the company claims, laser enrichment could be used to make material for nuclear fuel, including the kind used in advanced reactors.

Nuclear power provides about 9% of global electricity today, and that fraction could tick up as major world powers like the US and China look to build new reactors, including some based on next-generation technology. New, cheaper methods to obtain fuel could help ensure that those nuclear projects stay on track.

Naturally occurring uranium is largely made up of uranium-238 (over 99%) and uranium-235 (about 0.7%). Uranium-235 is the fissile type, meaning that, when hit with slow low-energy neutrons, it can sustain a chain reaction that generates electricity. So reactors generally use material with a higher concentration of U-235 than what’s pulled from the ground. Today’s conventional reactors usually use low-enriched uranium, typically is about 5% U-235, though some advanced reactor designs will use fuel that’s up to 20% U-235.

Today, centrifuges are the dominant tech used to enrich uranium. The equipment essentially takes uranium-containing material and spins it around incredibly quickly, so the heavier material (which contains U-238) spins out to the edge, while the lighter material (which has U-235) stays closer to the center. (If you’ve ever swung a mustard bottle to get the last of it out, you’ve used the same basic idea behind a centrifuge.) Then the material that has a higher concentration of U-235 can go on to be made into nuclear fuel.

Laser enrichment, on the other hand, takes advantage of the fact that all molecules vibrate and rotate at an atomic scale in ways that depend on their specific material. Even different uranium isotopes have distinct fingerprints.

Lasers are so precise they can target one particular material (like molecules that contain U-235, for example). If you shine a laser at a mixture, you can selectively excite just the material you’re targeting, giving it a bit more energy. This changes the way it behaves, which can make it easier to separate out the material you want using chemical or physical methods.

A wide range of separation approaches have been developed in research and industry. Some aim to electrically charge U-235 atoms, allowing them to be moved with electrostatic or magnetic fields. Others change how the material reacts chemically. 

The details of GLE’s specific technology are classified, and company officials declined to share how the process works. 

There’s been interest in using lasers for uranium enrichment for decades, says Charles Forsberg, a principal research scientist in nuclear science and engineering at MIT. 

However, in their early days lasers tended to be high-maintenance, unstable and difficult to operate. They’ve improved dramatically, making laser enrichment a more attractive prospect than it was during the early research.

Even more than technological improvements, a recent geopolitical shift could boost new enrichment technology. Russia has the largest uranium enrichment ecosystem in the world, and the country has historically dominated the market. “Nobody in the West was going to build a new enrichment plant while the Russians flooded the world with enriched uranium,” says Forsberg. 

Since the start of the Ukraine war, however, countries including the US and UK have taken steps to limit or ban imports of Russian uranium. That’s opened the door for companies to set up new enrichment operations, including some that use new technologies, Forsberg says.

Demand for fuel is increasing as countries look beyond Russia for uranium supply. “The gap is just becoming bigger and bigger, and this technology is right in the middle,” says Christo Liebenberg, president of LIS Technologies, one of the companies aiming to build laser enrichment capacity in the US.

LIS Technologies was founded in 2023, and the company recently purchased a 200-acre site in Oak Ridge, Tennessee. It’s currently in the pre-application process with the US Nuclear Regulatory Commission for its facility. The company plans to take in natural-grade uranium and make a product that’s roughly 5% U-235, though it hopes to eventually make more concentrated material that can be used as fuel for next-generation reactors.

GLE is taking a different approach: Rather than using its technology to enrich freshly mined material to the 5% concentration that can be used in fuels, it’s hoping to start by rehabilitating old waste.

The company has a contract with the US Department of Energy to reprocess waste material at the enrichment site in Paducah. The facility could enrich up to 200,000 metric tons of material that contains small amounts of uranium leftover from an older enrichment process.

GLE is taking the material that’s at least 0.25% U-235 and enriching it to about 0.7%. That material can then be further processed and slotted into the uranium supply chain in place of freshly mined material. “It’s kind of like a large aboveground uranium mine for us,” says Nima Ashkeboussi, vice president of government relations and communications at GLE.

While each one of its units is more complex and expensive than a centrifuge, far fewer are needed to do the same work. A similar centrifugation plant would have many thousands of centrifuges working together, but a full-scale plant using GLE’s laser enrichment process would have fewer than a thousand of its units, says Stephen Long, the company’s CEO. Up-front investment should be smaller, and operating costs are also expected to be lower, partly because the process uses less energy than centrifuges, Long says.

GLE has a testing facility in Wilmington, North Carolina. In fall 2025, the company completed a demonstration pilot, processing several hundred kilograms of uranium. It decommissioned that system and is currently putting together a new demonstration at the North Carolina plant, which would show how the technology works at commercial scale.

The company also applied for a license with the US Nuclear Regulatory Commission for its proposed facility in Paducah. The final safety evaluation should be finished in November, and the final approval should come in 2027, Long says. The plan is to start processing material at the plant by 2030.

In the long run, there’s plenty of uranium on the planet to keep reactors running for decades. But as interest in nuclear power grows and the geopolitics of fuel shift, there could be short-term gaps or price spikes that alternative sources could help smooth out.

Laser enrichment plants could turn out to be cheaper than existing technologies, says Stephen Greene, a senior fellow at the Nuclear Innovation Alliance. But as with most new technologies, “you don’t really know until you try to build one.”

On July 3, as a heat wave swept the region, New York State’s grid imported 52 gigawatt-hours of electricity from Canada—enough to meet about 9% of its total electricity demand that day.

Some of that power shuttled in on a 339-mile power line stretching from Quebec to Queens called the Champlain Hudson Power Express (CHPE). It opened in May and is officially the longest underground transmission line in North America.

An underground power line might not sound all that exciting, but this could be a big deal for the state’s grid planning, and for emissions. It could provide up to 20% of New York City’s electricity demand, largely with abundant hydropower from Quebec.

One wrinkle: The line has been down for most of this month, and some experts are concerned about how drought will affect the power supply feeding it. Let’s look at how the CHPE transmission line could help shape the future of our grid, and what barriers it needs to overcome to make a difference.

Planning for the CHPE (which is charmingly pronounced “chippy”) started 15 years ago, with the permitting process formally beginning in March 2010. The vision was to build infrastructure to better connect Quebec and southern New York.

Over 99% of Quebec’s electricity comes from renewable sources; most demand is met with hydropower, though the province’s wind capacity is growing quickly. New York has some hydropower of its own, as well as nuclear and wind, but the state still relies on fossil fuels for most of its energy generation.

Transmission Developers, a company owned by the alternative asset management firm Blackstone, and Hydro-Québec, the province’s manager of generation and transmission, partnered to build CHPE. Construction began in late 2022 and wrapped up earlier this year. The total cost for the privately funded project turned out to be  $6 billion.

The construction of this line was a feat. It’s made up of a bundle of two high-voltage direct-current power cables, each measuring roughly five inches across. Developers buried the bundle underground or underwater across the length of New York State. Much of the line was laid at the bottom of the Hudson River, requiring special boats that shot water jets deep into the sediment to create trenches for the cable.

Connecting grids together can help accelerate the transition away from fossil fuels. The ability to move electricity to where it’s needed could also help limit the amount of new capacity we need to build. Research has shown that interconnection can help cut emissions and lower system costs.

But CHPE is off to a slow start and has seen two outages so far. The first, on July 1, was reportedly caused by a trip at a converter on the Canadian side of the border. The second outage began on July 4, and the power line is still down as of the morning of July 22.

Some experts say this isn’t unusual for a new infrastructure project. Other power lines have seen similar startup challenges, and the equipment hasn’t really been fully tested until it’s in operation, Normand Mousseau, a physics professor at Université de Montréal, told the Gazette.

Officials traced the issue to a damaged section of cable on the US side of the border, and the company that manufactured the line sent experts to investigate the cause, according to reporting from RTO Insider, a trade publication. 

The damaged portion of the cable has been removed and replaced, says Lynn St-Laurent, a spokesperson for Hydro-Québec. “It is currently estimated that the remaining work, including necessary post-repair testing, will be completed by the weekend.”

Similar woes have afflicted the New England Clean Energy Connect line, which opened in January, stretching 145 miles from Quebec to Maine. That project has also seen outages, and very little additional energy has flowed into the Northeast.

The good news for New York is that the grid wasn’t relying on CHPE yet. “Our planning studies did not assume CHPE would be available this summer, and that was one reason the grid performed reliably during the heat wave earlier this month,” Kevin Lanahan, a spokesperson for the New York Independent System Operator, the state’s grid management company, said in a statement. “A core principle of reliability planning is not relying on any single project.” 

The idea is that eventually, states and regions will be able to rely—at least in part—on these projects, so there is pressure to get them working smoothly: Building massive transmission lines is a major long-term investment. In future years, as the equipment gets stress-tested and utilities begin to feel more confident in the projects’ reliability, they could play a bigger role on the grid.

One thing to keep an eye on moving forward is the condition of Quebec’s hydropower fleet: The region has seen intense drought for the past three years, eating into the water reserves used to generate electricity. That could mean there won’t always be abundant hydropower to ship across the border—even if the transmission lines are able to carry it. 

This article is from The Spark, MIT Technology Review’s weekly climate newsletter. To receive it in your inbox every Wednesday, sign up here. 

It feels as if it should be illegal to even think about heating appliances during the height of summer—seriously, these heat waves in New York have been brutal—but we need to talk about heat pumps.

The appliances use electricity for heating, they’re incredibly efficient, and they’re on the rise. (For what it’s worth, many heat pumps can also be run in reverse to cool buildings.) In the US, heat pump sales have doubled over the past 15 years, according to a new report. And they’re winning the heating race against fossil fuels, outpacing natural-gas furnaces by 32% during the first quarter of 2026.

These stats are especially striking at this moment, because a key tax credit for heat pumps just ended with the close of 2025. But you wouldn’t know it from looking at the data. Why are heat pumps still so hot?  

In case you need a quick refresher, heat pumps use electricity to essentially move heat from one spot to another. A refrigerant moves around a loop in the device, expanding and compressing, gathering and releasing heat at different points in the cycle. (For a more in-depth look at the thermodynamics, this explainer I wrote in 2023 still holds up.)

The result is an appliance that can be incredibly efficient. Once you pay for and install a heat pump, it’s generally significantly cheaper to run than a gas or oil furnace or other types of electric heating systems. And because they’re more efficient and don’t involve burning fossil fuels, heat pumps can be a major help in decarbonizing buildings.

One of the major hurdles to wider use of heat pumps is the appliances’ cost: They tend to be more expensive to buy and install than gas furnaces. For this reason, many governments offer incentives to encourage their adoption. In the US, people who installed heat pumps between 2023 and 2025 were eligible for up to $2,000 in tax credits.

Last year, though, the Trump administration slashed those tax credits, along with many of the other incentives that were part of the 2022 Inflation Reduction Act. Effective January 1, 2026, no more financial help for heat pumps.

I think I’ve seen this film before, and I didn’t like the ending. Tax credits of up to $7,500 for new EVs ended on September 30, 2025. In the quarter leading up to that deadline, sales spiked as people rushed to take advantage of the incentive. Then they fell off a cliff. Things are starting to normalize now, but clearly the tax credit’s sunset had a major effect.

But as it turns out, heat pumps are an entirely different story. In the first few months of 2026, sales have actually gone up, as Lucas Davis, an energy economist and UC Berkeley professor, points out in a new analysis.

Heat pump shipments were flat from December to January and have seen a gradual rise since then, according to data from the Air Conditioning, Heating, and Refrigeration Institute, a trade group that represents about 90% of the US market. This increase from winter into spring follows a seasonal trend seen in previous years—and it’s actually a bit stronger in 2026.

This data isn’t what you’d expect to see if losing the tax credit were hurting demand. As Davis lays out in his post, it seems the credit wasn’t really convincing people to install heat pumps, or at least the case for doing so was sufficient without the added incentive.

“It appears that the U.S. market for heat pumps is strong enough that it does not depend on tax credits,” Davis writes.

In 2024, MIT Technology Review put heat pumps on our annual list of breakthrough technologies. “We’ve entered the era of the heat pump,” I wrote at the time.

While heat pump sales have been up and down over the last few years, the era is going strong. The appliances have outsold gas furnaces in the US for the last four years. It’s not just the US, either. Countries including China and Germany have seen strong movement to heat pumps in recent years.

There’s rarely a straight path to adoption for new technology, especially something that requires so many individual households to make a significant change. But it’s encouraging that a major decarbonization tool is going strong, even when roadblocks pop up.

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I was really looking forward to July 4, and not just because I love a poolside barbecue. This year the American holiday also marked a big symbolic deadline for US nuclear power.

Last year the Trump administration set a goal to see three new microreactors achieve criticality, a technical milestone establishing that a reactor can sustain a chain reaction, by the nation’s 250th birthday. And just in time, four reactors did so.

It was a lofty goal, and seeing not just three but four companies meet it is certainly a positive sign for emerging nuclear technologies at a time when the world is facing increased need to increase electricity supply and address climate change with emissions-free technologies.

But achieving criticality doesn’t mean a reactor is ready to provide electricity for the grid (or at all, for that matter). Let’s untangle what this program’s success could mean for nuclear power in the US, and where these companies might go from here.

The Reactor Pilot Program essentially opened a special door for prototype reactors to fast-track development. In August, the US Department of Energy selected 11 reactor projects for the program and offered them land and support from the national labs system. These are all microreactors; the large light-water reactors that dominate the grid today are tens or even hundreds of times their size. 

Antares Nuclear was the first to achieve criticality, reaching the milestone in June in its Mark-0 test reactor. Reactors from Valar Atomics, Deployable Energy, and Aalo Atomics followed. (Aalo hit the mark in the early hours of July 4—an inspiring example of just barely meeting a deadline.)

The speed with which these companies hit this milestone is impressive, especially in an industry known for massive projects that frequently blow past deadlines and stated budgets. (Valar, Antares, and Aalo were all founded in 2023, and Deployable started in 2025.) But reaching criticality and running a reactor that can produce electricity are two totally different things.

All these reactors reached what’s called zero-power criticality. Basically, it’s a test of whether you can start a nuclear chain reaction, with no meaningful power coming from the reactor. “A zero-power-criticality test can be achieved without making real engineering progress on fuel or design,” Kathryn Huff, a former assistant secretary for nuclear energy and chair of the Department of Nuclear Engineering and Engineering Physics of the University of Wisconsin–Madison, said on an episode of the Catalyst podcast earlier this year.

Now, with the completion of this program, the companies will need to continue their work to make power, which could involve some big technical challenges. In some cases they’ll need to add significant equipment, like the cooling systems to transfer the heat out of the reactor core.

The companies are projecting aggressive timelines moving forward. Aalo says it’s already begun work on the second reactor and plans to produce 10 megawatts of electricity to power an on-site data center in 2027. Deployable Energy says it plans to deploy commercial reactors by 2028. 

I tend to take timelines from startups, especially in nuclear, with a grain of salt. Not only are these remarkably complex technical machines, but companies often run into problems outside their own control, like regulatory challenges—which these new projects could soon face. 

The Nuclear Regulatory Commission is in charge of civilian and commercial nuclear use in the US, and historically, the process to get nuclear reactors approved has been quite slow.

The agency did propose a new framework for microreactor approvals earlier this year, which is designed to speed up the process—but it’s yet to be seen how quickly things will move. (And it’s worth noting here that some nuclear experts have questioned whether the agency under the Trump administration is loosening nuclear rules too much.)

Some nuclear supporters aren’t applauding the microreactor milestone. Federal focus on the program is an “unhelpful diversion” from goals to meaningfully increase nuclear capacity, according to one analysis by Third Way, a public policy think tank. “Artificially accelerating project timelines is a short-term solution, not a long-term fix,” the memo reads. 

Criticality is a big first step, but a lot will still have to happen for any of these microreactors to come online, much less for these small reactors to be a significant source of electricity for the grid. 

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