The US is hitting records for the rapid growth of its energy storage market. That’ll go a long way to shoring up the grid, increasing reliability and also cutting emissions, since batteries can help store energy from intermittent renewables like wind and solar.

Crucially, this is all happening with the help of cheap Chinese batteries, though there’s been a concerted effort to reduce the US’s reliance on them. Most recently, in an executive order in late August, the Trump administration declared a national emergency that essentially bans Chinese batteries from being used in grid-scale energy storage systems.

There’s an argument to be made about reducing reliance on any single source of a crucial energy technology. But all this tension raises a broader question for me: How much should countries take advantage of cheap, available tech, versus cutting off major sources to force development of their own factories even if that comes at a higher cost?

This is hardly America’s first push to move away from Chinese influence in the battery supply chain. One of the major policy tools used in recent years is restricting the tax credits designed to incentivize use of the new technologies. Limiting the types of projects that are eligible can help reduce the cost of local technologies so they’re more competitive with otherwise cheaper imported options.

Back in 2022, the US government designed the tax credits that were part of the Inflation Reduction Act to restrict where a battery’s minerals could be mined, processed, or recycled, as well as where a battery and its components were assembled.

Those tax credits underwent a makeover in 2025, but the Trump administration has taken a similar tack. New legislation requires that starting in 2026, 55% of the cost of materials used for new energy storage projects must come from outside China and other restricted countries or the projects won’t qualify for tax credits. 

And we can’t forget about tariffs. Import taxes for batteries increased to 25% in January, up from 7.5%.

But the new executive order is a more drastic move. It bans the installation of “any foreign-produced bulk-power system electric equipment” that poses a national security risk. The order specifically calls out battery energy storage systems, as well as inverters and transformers.

“An outright ban was a bit of a surprise, and it does create a bit of concern for domestic players in the US,” says Shan Tomouk, energy storage and energy lead for Benchmark Mineral Intelligence, an energy industry analyst.

The move is likely to slow deployment of grid-connected energy storage projects in the near term, according to analysis from BloombergNEF, an energy consultancy. Projects could face delays as developers wait for clarity on the rules.

Depending on the detailed guidance from the Department of Energy, which is expected by the end of the year, some projects may need to find alternative sources for their cells, whether they’re domestically produced or imported from other countries. These will likely be more expensive than Chinese imports, says Isshu Kikuma, an energy storage analyst at BloombergNEF. “Worst case, those projects could get canceled,” he says.

Technically, the order applies even to existing energy storage plants, though it’s unlikely that they’ll be taken offline because of their batteries’ origin. Since most of these plants currently use Chinese batteries, enforcing the order to the letter would essentially mean removing most installed battery energy storage from the US grid, Kikuma says.

In the longer term, the US will eventually be able to meet its own demand for batteries. The country could have enough capacity by about 2030, though some factories may not ramp up or run at their full capability, meaning domestic supply won’t actually meet demand until later in the 2030s. 

New factories from LG Energy Solutions, Samsung SDI, Ford, and SK On are set to come online or ramp up by next year. In an ironic twist, a slowing EV market is helping, as some factories originally designed for vehicle batteries are retooling to build cells for grid storage instead. 

But it will come at a cost. Today, batteries produced in the US are still significantly more expensive than those made in China. Even switching to imports from other countries like South Korea would likely be more expensive.

This is a crucial issue that goes beyond the US and even beyond batteries. China is miles ahead of much of the rest of the world on technologies like solar panels and batteries. Through years of government support and experience with research and manufacturing, the nation is an energy powerhouse.

There’s a delicate political balance to maintain as the world figures out how to navigate this situation. There’s cheap technology on offer, which can help drastically reduce emissions and energy costs. But there can be risks associated with relying too much on any one player for crucial technologies.

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

Battery installations hit a new record in the US in the second quarter of 2026. In total, 20.2 gigawatt-hours of new capacity came online, according to a new report. That’s enough to supply the daily electricity needs of about 700,000 homes.

The surge is putting the country on a trajectory to see 71 gigawatt-hours of batteries installed in 2026, a 20% increase over last year. This growth is being driven by a combination of cheaper batteries and an urgent need for more energy storage capacity as renewables such as solar and onshore wind power are added to the grid. 

Massive, utility-scale systems are leading the way; they’re responsible for most of the record-setting quarter. Seven new gigascale battery installations (those with a capacity of over one gigawatt-hour) came online during the three-month stretch, according to the report, published by Benchmark Mineral Intelligence and the Solar Energy Industries Association.

“It really came down to a handful of big projects,” says Shan Tomouk, energy storage and energy lead for Benchmark Mineral Intelligence.

But there was also growth in the category of so-called behind-the-meter batteries, which include both residential and industrial battery storage systems. These projects, generally smaller than utility-scale installations, are typically owned and operated by homeowners or businesses rather than utilities or power providers. 

In the behind-the-meter category, data centers led the way, making up about three-quarters of new batteries in the commercial sector. But residential batteries saw a sharp slowdown. These systems are often installed in homes to store power from solar panels or serve as a backup source in case of a blackout. Home installations are projected to drop by 16% in 2026 compared with last year, according to the report.

That drop happened largely because a tax credit that helped subsidize home battery systems ended in 2025, Tomouk says. Home installations should recover by the end of the decade, he adds. And tax credits for nonresidential batteries have largely survived.

Overall, batteries are a bright spot in energy right now. “This is one of the strong sectors in the US,” says Isshu Kikuma, an energy storage analyst at BloombergNEF, an energy consultancy.

As the battery market continues to grow, one major trend to keep an eye on is a move toward US-made technology. Today, nearly all the systems coming online use cells made in China, though some are put together into complete energy storage systems in the US.

Tariffs were already pushing the US energy storage industry toward domestic production. And beginning this year, energy storage tax credits required projects to limit their reliance on batteries imported from China. There’s a lot of manufacturing capacity set to come online in the US, though these factories probably won’t be able to meet demand until at least 2030 or so, Tomouk says, so prices could tick up.

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 CTO.

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.

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

Correction: A previous version of this article misstated the title of Joel Edwards. He is Zanskar’s CTO, not CEO.

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.

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

Solar geoengineering is often portrayed as a sort of emergency brake. Something along the lines of Pull in case of climate emergency to scatter light-reflecting particles to bounce sunlight out of the atmosphere and cool the planet.

But it might be less like a simple brake and more like a complicated, entirely unsolved puzzle.

Some researchers are starting to look into how nations or companies would go about trying to cool the planet—and there’s a lot to figure out. My colleague James Temple dug into these engineering challenges in his latest feature story. My biggest takeaway? This all might be a lot harder than I thought.

I’ll admit, I’ve always thought of geoengineering as a relatively low-tech solution. That’s partly because over the years we’ve seen some companies do their own low-cost guerrilla “experiments,” tossing balloons up into the atmosphere and claiming to have made some small dent in climate change.

But to actually actively cool the planet in a significant way, and to make sure we understand exactly what effect we’re having, there’s a lot that researchers still need to learn. 

First, there’s the problem of getting up into the atmosphere. Generally, the target for solar geoengineering efforts is the stratosphere, since the air there is drier and more stable, so particles deposited there would stay aloft and move around the planet, lowering temperatures over a wider area and for a longer time.

You can release the particles in balloons, but balloons may not go where you want them to. And at a large scale, you’d be leaving a lot of litter all over the planet. That leaves aircraft, but conventional planes aren’t suited to fly around in the stratosphere. (Commercial aircraft generally fly at around 12 kilometers above the Earth’s surface, while geoengineering would require reaching roughly 20 kilometers.) The air is thinner higher up, so aircraft with massive wings would probably fare better than more conventional designs.

One design, from a startup called Iris Aero, shows just how much rethinking of our current flight technologies might be needed—the plane is almost unsettling in its proportions. Its wings are so long, on a stubby little body. It reminds me of a water strider, those bugs that have super-long legs to scurry around on a pond’s surface.

And that’s just the beginning. There’s also the question of what, exactly, would be best to scatter up in the stratosphere. The idea behind geoengineering comes from volcanoes—after an eruption, sulfuric acid ends up floating around in the atmosphere, and it can temporarily cool the planet. But that chemical is sticky and would be heavy to carry, so scattering some sort of precursor to sulfuric acid would probably be better. Researchers, including some at the University of Chicago, one of the leading institutions in this field, are working to figure out the best formula. 

I’m struck by how complicated this turns out to be, and I’m also left with a big question: As research turns from modeling and simulations to the practical aspects of this incredibly controversial technology, what does it mean to be doing this work?

There are major concerns about what effects might come from large-scale attempts to cool the planet. The effects could be positive for some parts of the globe and negative for others. Established weather patterns, like the monsoon season in South Asia, could shift. There are major questions about what the governance for the use of geoengineering should look like, and who gets to decide whether to go ahead. 

Experts who champion research in geoengineering often draw a line between a desire to support learning more about the technology and a call to deploy it. Many would argue that we should understand it better, so we can make informed decisions.

But to me, there’s a clear difference between atmospheric modeling and detailed engineering work on an aircraft. If there’s public research that essentially amounts to a set of practical instructions, I can’t help but feel like it could enable any number of individual actors or nations to take geoengineering into their own hands. It also might normalize the idea of using the technology. 

Some experts shared concerns along these lines with James, arguing that the shift to practical engineering work requires more oversight. Some called research in this area dangerous.

One alternative perspective I found interesting came from Shuchi Talati, executive director of the nonprofit Alliance for Just Deliberation on Solar Geoengineering.

Rather than further practical research making a slippery slope slipperier, it could have the opposite effect, she told James. “The actual practice of R&D will be a sticky slope, because there will be more real-world problems that come up that we haven’t even thought of yet,” she says. Engineering research could challenge the “idealized notions” of how easy the technology would actually be, she adds.

It’s hard to argue against better understanding potential tools to address climate change. But if we draw a map towards a potential future, it might become difficult to control who follows 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’s a tale of two nuclear industries.

In China, large reactors are coming together at a stunning pace. The country has nearly doubled its nuclear fleet since 2016, reaching nearly 60 gigawatts of total power capacity. The new facilities are nearly all gigawatt-scale pressurized-water reactors.

Meanwhile, the US has built just two reactors in that time—Unit 3 and Unit 4 at Plant Vogtle in Georgia. Smaller reactors are attracting a lot of excitement and investment, though. A microreactor developer just saw its reactor reach criticality in a new Department of Energy pilot program.

The world is racing to meet rising electricity demand, and many countries are interested in energy sources, like nuclear power, that don’t come with greenhouse-gas emissions. The key question: Which of these strategies will really pay off in terms of getting electrons on the grid quickly?  

Today, the US and France are known as leaders in the nuclear industry. The US has the world’s largest fleet, with France coming in second. France is heavily dependent on nuclear for its grid—about two-thirds of the country’s power comes from nuclear reactors.

But they have hardly added any new reactors to their fleets in recent years. The US can point only to Vogtle, and France connected its latest reactor to the grid in December 2024—the first in over 20 years. 

It’s incredibly difficult to build the massive projects that dominate the nuclear industry today. Up-front investment can run well into the billions, so investors need to wait decades to break even. Designs are complex and can often change during the regulatory process, tacking on cost and time. 

Many are hoping that the key to turning things around in these countries could be smaller reactors.

The idea is that shrinking the footprint of a reactor cuts down the initial investment needed to prove out the new technology. The reactors could even be put together in a factory rather than being built on-site, allowing for a lower price over time.

These smaller reactors are the target of tons of interest and investment in the US, including a new Department of Energy pilot program. The department set a goal last year of having three test reactors reach criticality by July 4, 2026, the nation’s 250th anniversary. (Criticality is the point at which a reactor achieves a self-sustaining chain reaction that can release energy.)

Last week, California-based Antares hit the milestone with its Mark-0 reactor. 

The company plans to eventually build microreactors, designed to produce between 100 kilowatts and 1 megawatt of electricity (large reactors on the grid today are at least 1,000 times that size). The core design is a sodium-cooled reactor, and it uses TRISO fuel, self-contained graphite-coated spheres of a more concentrated fuel than what most reactors use today. 

But there is still a long way to go before it can actually produce power—the Mark-0 doesn’t have any power conversion or heat removal systems. The company plans to produce electricity in late 2027 and deploy in the field by 2028, CEO Jordan Bramble told the Associated Press.

The private sector is interested—and invested—too. Big Tech companies are throwing money at new reactors they hope can help power data centers. 

But look to the other side of the globe, and others are sticking with the established blueprint: China is absolutely churning out large nuclear reactors. Construction started on six new reactors there in 2025, and two more got underway in the first five months of 2026. The country is on course to overtake both the US and the European Union in installed nuclear capacity by 2030.

The speed here is staggering. As of 2024, the average time to build a new reactor in China came in at between five and seven years. The global average is about nine years, and the two most recent reactors in the US took about 15 years.

One key to this speed is standardization: China has set up a uniform project management system to design, license, and build new reactors. They’re built in batches of six or more to take advantage of economies of scale.

It’s one of the ideas meant to give the edge to smaller reactors, but China is working to realize the same benefits for larger projects. A huge amount of government investment is certainly helping.

Larger reactors generally provide more electricity to the grid for a lower price, a key consideration in view of China’s steeply increasing electricity demand. While smaller reactors require less up-front investment than larger ones because of their size, they’ll actually be more expensive per unit of electricity produced. 

That’s not to say China is exclusively focused on big reactors: the country is also expected to see its first operational small modular reactor, the Linglong-1, start sending power to the grid this year.

But looking ahead, it’ll be interesting to see if smaller reactors can help the West keep building new nuclear power. At the moment, with China’s quick progress, it’s looking as if bigger might just be better. 

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

Would you take a payment to ramp down your electricity use? Would it change anything if you were doing so to help power a local data center?

Google just signed a new deal to help pay for a virtual power plant (VPP) in the largest power grid in the US. The agreement is with Voltus, a leading VPP and distributed energy resources platform.

Voltus will set up the virtual power plant, grouping together devices like electric vehicles and smart thermostats. It’ll pay customers to participate, and the company will dial back power or use the stored energy during times when the grid is stressed. Google will foot the bill for setting it up, and the extra capacity generated by the project will help run its data centers in the region.

This is one of the most concrete examples so far of a tech giant using a VPP to help meet energy demand for data centers. But there are still some lingering questions about just how far this sort of program can go, and what the limits are.

Last year, it felt as if everyone was talking about data center flexibility. A high-profile study from Duke University found that if data centers agreed to decrease their energy demand for roughly 40 hours per year, a whole bunch of them (about 100 gigawatts’ worth) could come online without making new power plants or transmission equipment necessary.

The underlying reason is that our power grid is designed not for our average energy use, but for the absolute maximum: the brutally hot July evening when everyone is blasting their air conditioners, watching Love Island, and microwaving popcorn. If a data center is willing to refrain from pulling so much power during those high-stress times, the grid can happily support it the rest of the year.

One lingering question here is about incentives: How would you get data centers to agree to this? After all, they might not have a very flexible load, especially now that AI use is more widespread—training a model can easily be delayed or shifted, but customer demand is more immediate. Giving up computing capacity could mean losing revenue.

Regulation is one approach that could work here. One proposal in the US would allow new data centers to come online years sooner if they agree to lower demand when the grid is nearing its max.  And a new Texas law requires large users to switch to backup power or curtail their demand in emergency situations.

Another approach is for data center operators to pay for other people to be flexible.

Voltus announced a new program in September that allows data centers to finance flexibility on their local grid. The company calls it “Bring your own capacity.” Google is now the first named customer taking advantage of this program.

In the new agreement, Voltus will pay people who agree to participate in the virtual power plant. The plant will be part of PJM, the grid that covers much of the US East Coast. The company says it will be able to aggregate up to 100 megawatts of distributed energy resources each year. The plant should be operational in 2027, according to Voltus.

This isn’t Google’s first foray into flexibility; the company has agreements with utilities across the US to limit or shift its own energy demand, which can help free up grid capacity. As the company pointed out in a blog post earlier this year, though, there are limits on how flexible a data center can be, and not every facility will be able to ramp down its power demand.

“There is no one solution for expanding grid capacity and we’re continuing to explore all options, including the many avenues for load flexibility,” said Michael Terrell, Google’s global head of advanced energy, in an emailed statement in response to written questions.

Once again, I’m wondering about incentives here. These companies are asking homes and businesses to be flexible. Will they agree?

A recent study in California looked at local people’s willingness to participate in managed electric-vehicle charging. Essentially, the program pays people to give up control of when they charge their EVs. This is another way to help smooth out electricity demand and ease the burden on the grid.

The problem? Not many people signed up. With no economic incentive, only 1% of EV owners enrolled in managed charging. At $40 per month (about 15% of their power bill), only 4.6% did.

This is a different situation and a different region from the one in which Google is working with Voltus. (It’s worth noting that the companies aren’t sharing how much they plan to pay the participants, which will obviously be a big determinant in participation for this kind of project.) 

But this study shows that even with money on the table, people may not always jump at the chance to cede control of their electricity demand. And it certainly feels relevant that about 70% of Americans oppose AI data centers in their area, according to recent Gallup polling. 

Being flexible sounds like a great idea in theory, and these financed VPPs could provide an immediate route to meeting energy demand. But as we move from idea to implementation, it’ll be interesting to see whether trial runs work as intended.  

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Researchers say they’ve found a new way to extract lithium, a crucial metal used in the lithium-ion batteries that power electric vehicles and energy storage arrays. This new technique could be more environmentally friendly and cheaper than existing ones. 

The research was published today in Science, and a startup called Rock Zero is working to commercialize the process.

“At scale, we believe this will be the lowest-cost way of sourcing lithium in the world,” says Yet-Ming Chiang, one of the study authors, who is an MIT professor and a serial entrepreneur behind climate tech companies including Form Energy and Addis Energy.

The most economical way to get lithium currently is to extract it from brine, salty water that’s pulled the metal out of rock over the course of millennia. But this technique is geographically limited and currently requires vast tracts of land for massive evaporation pools. The more common tactic is hard-rock mining, where large bodies of ore are blasted apart, cooked at high temperatures, and processed using dangerous chemicals.

The researchers’ new method uses a weak acid to dissolve typically nonreactive silicate minerals. That frees not only the lithium but also other useful materials, including alumina and silica.

The origin story for this research, and the resulting company, came from another startup founded by Chiang, Sublime Systems, which makes cement using electrochemistry.

The team was trying to find a source of highly reactive silica in order to form stronger cement. One way to make reactive materials, which can bond easily with other materials, is to take a nonreactive material, dissolve it, and then allow it to become solid in a more reactive form. It’s not impossible to dissolve silicates, but the best-known way is to use hydrofluoric acid, an extremely dangerous chemical. Other fluorine-containing chemicals are candidates too, but some will produce hydrofluoric acid as a side product during reactions. 

Chiang drew inspiration from a previous home renovation project involving glass, which is made of silica. “I was remodeling a shower in Framingham, Massachusetts, about 25 years ago,” he says. “So when we started this project, I remembered that glass etching cream and thought, ‘What’s in that?’” 

The glass etching cream he remembered, which can be found on shelves at any craft or home improvement store, uses ammonium fluoride, a weak acid. And the MIT researchers discovered that in the right conditions, it can effectively dissolve silicate minerals without producing hydrofluoric acid in the process.

This chemistry could be useful for any silicate minerals—and there are a lot of them. But spodumene, the mineral that’s often mined for lithium, became a prime first target. (Chiang says a suggestion from Doug Wicks, one of the company’s advisors and a former ARPA-E official, pointed the team in spodumene’s direction.)

Today, a key step in processing spodumene ore is to roast it in a kiln at super-high temperatures. This causes a phase transformation, essentially puffing up the material and making the lithium more accessible.

By avoiding the need to reach these temperatures, you could save on energy costs and potentially reduce carbon emissions as well, says Camden Hunt, one of the authors of the study and the CEO and cofounder of Rock Zero.

Avoiding the kiln could also unlock the ability to use some ores that can’t be roasted properly, Hunt adds. Ore that contains too much iron won’t go through the phase change correctly, instead melting and turning into a glassy material.

The new process relies on simple stirred plastic tanks and takes place at temperatures up to about 95 °C (200 °F). The ammonium fluoride dissolves the silicates, which in earlier experiments allowed nearly all of the lithium inside the spodumene ore to be extracted within a couple of days. The researchers have since cut this time to under 12 hours, says Benjamin Mowbray, first author of the study and the CTO and cofounder of Rock Zero.  

The products (after some additional steps to clean them up) are lithium carbonate, which can be used to make batteries; alumina, which can go into a smelter to make aluminum; and cementitious silica, which can be added into concrete. And the acid can be reused in the same loop.

Chiang calls this “nose-to-tail” mining—using every part of the ore provided, like eating every part of a butchered animal.

The researchers are currently working to scale and optimize the process. The tanks in the lab in Cambridge, Massachusetts can handle three kilograms of spodumene concentrate in each batch. 

They have also estimated the cost of this process once fully scaled up. Assuming that the ammonium fluoride can be recycled at a high level, they should be able to extract lithium for less than $6,000 per metric ton. (They’ve identified a potential cheap industrial source of the acid as well, as an alternative to recycling it.) 

The total cost is projected to be lower than that of other processes used to extract lithium from hard-rock ore today, and it could be competitive with brine.

The team has designed a pilot plant and is looking for space to build it. The plan is to have construction done by the end of 2026 and start operating the facility in 2027. Talks are underway with potential partners in the mining industry.

One difficulty for new players in lithium extraction is the volatility of the market: Prices have seen huge swings in recent years, from a peak in 2022 to lows in late 2024 and a slow climb starting in early 2026. 

Rising prices might benefit new players like Rock Zero, but there are many projects that could come online if prices continue to rise, and that could bring the market right back down, says Simon Jowitt, chair of exploration geology at the University of Nevada, Reno. “People are waiting to see what happens with the lithium price,” he says. “It’s a crowded market, and there’s some big players out there.”

And even though batteries are driving up demand for lithium, the market is still relatively small, Jowitt adds: “That means it’s going to be volatile.” New lithium extraction technologies like Rock Zero’s will have to compete with methods used by existing giants, and there’s also the potential that technological alternatives, like sodium-ion batteries that don’t need lithium, could make the market more difficult to navigate, Jowitt says. He also thinks some of the company’s economic estimates could be optimistic.

For its part, Rock Zero’s team hopes not only to scale this technology for lithium, but to use it for other minerals in the future. As Mowbray says, “The Earth’s crust is made of silicates.”

This year, there’s been a wave of notable energy companies going public via IPO in the US.

The solar and battery company Solv Energy went public in February, to the tune of $6 billion. X-energy, which is building small modular nuclear reactors, did the same in April, and its stocks surged on its first day of trading to hit a $11.5 billion market cap. Most recently, the geothermal company Fervo Energy went public in mid-May, and its market cap is now about $12.4 billion.

Those are all success stories in the IPO world. And it certainly doesn’t feel like a coincidence that all these companies are racing to provide electricity in an era of rising demand (partly due to data centers). Let’s take a look at how these firms are doing, what this moment says about the grid, and what’s coming next. 

Let’s start with Fervo Energy, a company we’ve covered a lot over the years that’s working to develop enhanced geothermal energy. (We included it on our 2025 list of Climate Tech Companies to Watch.) While conventional geothermal requires finding specific spots with hot rock, water, and fractures to support a power plant, Fervo essentially uses fracking techniques to create the necessary conditions.

The company was founded in 2017, and it raised about $1.5 billion from investors over the years before its IPO.

Fervo’s first commercial project, Cape Station in Utah, is expected to have a capacity of about 500 megawatts. The first unit is set to start generating power for customers by October and the next two units by January 2027.

The new funding from the IPO could help the company scale. Fervo currently has over 600 megawatts’ worth of binding power purchase agreements. And it has leases for land that could together generate more than 40 gigawatts of electricity. (As of 2024, the entire US geothermal fleet had a capacity of just 4 gigawatts.)

The company also has an eye on cutting construction and drilling costs—its Cape Station plant is expected to cost about $7 per kilowatt, which is cheaper than new nuclear power plants but over twice the expense of building a new natural-gas plant in the US. 

X-energy also aims to provide reliable clean power: it’s part of the wave of next-generation nuclear companies working on small modular reactors. The company is building high-temperature gas-cooled reactors, which flow helium over self-contained pebbles of nuclear fuel. These reactors will each generate 80 megawatts of electricity, less than one-tenth the output of larger ones like Unit 4 at Plant Vogtle in Georgia, the most recent addition to the commercial nuclear fleet in the US.  

X-energy also saw its IPO go well, and prices surged in trading after the initial offering. One interesting tidbit here—the company had previously planned to go public in 2023 but decided against it because of difficult market conditions.

The company is still years away from demonstrating its technology in a commercial project. 

You may recall a story I wrote last year about its effort to build nuclear reactors at the site of a Dow Chemical plant in Texas. The company recently received a key environmental approval for that project, though it’s still waiting for the final green light from the Nuclear Regulatory Commission to start construction.

Finally, Solv Energy builds solar and energy storage projects, mostly for utilities and independent power producers. Solar and batteries are some of the cheapest and easiest technologies to add to the grid, so this one could get a lot of capacity online, quickly. The company already has 21 gigawatts’ worth of projects operational across 35 states.

Many companies in the energy sector are pinning their hopes on the rapid growth in data center construction and operation. The AI boom has transformed the energy landscape, pushing electricity demand higher in a country where it’s been relatively flat for the last decade or so. Solv Energy mentioned data centers over a dozen times in documents filed with the Securities and Exchange Commission before its IPO. 

And Fervo and X-energy are particularly connected to the tech giants driving AI. Google has been a longtime investor in Fervo and also pioneered what it calls its clean transition tariff with the company. Amazon is a client of X-energy as well as an investor; it reportedly owns close to 20% of the company.

Fervo and X-energy are also in industries that occupy a political sweet spot. President Trump and his administration have gone after wind power and other renewables, cutting off existing support and slowing approvals for new projects. Meanwhile, geothermal and particularly nuclear power have kept favor with the federal government and enjoyed continued tax credits and grant funding.

If a few big leaders cash through these IPOs, it could help investors feel more confident about supporting the energy sector, even if that money is concentrated in later-stage ventures like these rather than earlier-stage companies. 

We could see other firms, particularly in nuclear and geothermal, attempt a similar route in the year ahead.

A key thing to watch here will be whether Fervo and X-energy in particular can succeed in scaling up and deploying their technology. If either of these companies stumbles or misses a timeline, it could have ripple effects for those hoping to follow in these very lucrative footsteps. 

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