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The climate-friendly appliances are becoming the norm among American home builders. Here are the factors driving the shift.
Heat pumps are a key way to get fossil fuels out of buildings — and the tech recently notched a win in the U.S. housing market.
2025 marked the first year that over half the apartment buildings constructed nationwide came equipped with the überefficient electric appliances, according to U.S. Census Bureau data. Buildings with heat pumps, which can both heat and cool indoor spaces, accounted for 53% of new apartment complexes, up from 46% in 2024.
New houses, including row houses and town houses, aren’t far behind: In 2025, 48% were built with heat pumps, up from 45% in 2024.
The stats are the latest evidence that heat pumps are taking over the U.S. residential heating market. For the past four years, these devices have outsold conventional gas-fueled furnaces, which belch pollution that endangers health and warms the planet. The tech’s growing popularity is a positive sign for decarbonization, since burning fossil fuels in buildings contributes nearly a tenth of the nation’s total greenhouse gas emissions.
The data reveals another piece of good news: The majority of all homes built last year — 78% of new apartment units and 56% of new houses — had electric heating in some form, either heat pumps or less-efficient electric-resistance systems.
This trend toward electric heating has persisted for over two decades now, across federal administrations, though it varies regionally. For example, in the South, with its milder winters, 96% of new apartments are electrically heated; in the Northeast, it’s just 52%.
Driving the shift to heat pumps is likely a combination of factors, according to Alan Durning, executive director of the Sightline Institute, a sustainability nonprofit in the Northwest. The two that stand out, he said, are improvements to the technology and the increased demand for air conditioning during climate change–fueled heat waves. While heat pumps are pricier up front than gas furnaces, they can be competitive with a gas furnace plus central AC.
A federal tax credit expanded under the 2022 Inflation Reduction Act could have also spurred heat-pump installations. That incentive offered developers up to $5,000 per energy-efficient housing unit. But even though the credit expired last month after being axed by President Donald Trump and Republicans in Congress, developers still stand to profit by ditching gas in new buildings.
All buildings require electrical infrastructure. But hooking up to a gas pipeline on top of that adds complexity, time, and expense. New Mexico land developer John Moscato says that by skipping gas-line construction, his company reduces costs by $3,000 per lot. That adds up fast.
“In our upcoming development of 4,500 lots, we expect the savings of being all-electric to be approximately $13.5 million,” Moscato said.
Some states, like California, Colorado, and Washington, have standards that encourage new construction to go fully electric. But “red states are never going to pass laws requiring a phaseout of gas in new buildings,” Durning said.
Still, he said, policies that simply boost new housing in such states can move the needle toward cleaner buildings, since developers are increasingly likely to opt for electric heating appliances. And unlike gas bans, these laws are politically palatable, he added, pointing to recent pro-housing zoning reforms passed in deep-red Montana and Idaho. “We are getting accidental electrification,” he said.
Some legislators may “say climate change is a hoax, but they want to free the market in their cities to build more housing,” Durning said. “In red states, building more apartments will move us closer to decarbonization.”
American solar manufacturers are navigating shifting federal policies on tariffs and tax credits, all while demand for their product continues to grow.
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Inside the vast Qcells factory in Cartersville, Georgia, workers — and a bevy of robots — move ultrathin slices of polysilicon through a lengthy series of machines and chemical baths to get what are known as cells.
“The $2.5 billion, the 3.5 million gallons of water, the 90 megawatts of power, the 60 tons of chemicals on-site, and all of the football fields’ worth of infrastructure you’ve seen is to arrive at this,” said Scott Bell of Qcells, holding up one of the paper-thin blue cells.
It’s the basic building block of a solar panel.
In June, the plant, about an hour northwest of Atlanta, began its expansion from assembling the major components of solar panels to bringing the whole production process under one roof. It’s a major milestone for the U.S. solar industry. China has dominated solar panel manufacturing since the 2010s, flooding the global market with far cheaper panels than anyone else could make. For a host of reasons — national security, labor practices, job creation — the U.S. is trying to bring back domestic production.
In its latest move, the Trump administration plans to levy new tariffs and impose minimum import prices on polysilicon, the key ingredient for solar cells. The new measures go into effect in December.
“Having the full supply chain is critical,” said solar manufacturing expert Ben Damiani, chief technology officer at Atlanta-based solar developer Cherry Street Energy. Moving that supply chain to the U.S., he said, hasn’t been a smooth road. “Probably the biggest hindrance has been the constant change of our own policies.”
The Biden administration took a carrot approach to attracting solar panel makers: The 2022 Inflation Reduction Act included tax credit bonuses for solar projects that used U.S.-made panels. Qcells, a South Korean firm, has said those incentives were a major reason they built their Cartersville plant.
The Trump administration, by contrast, is taking a stick approach. While last year’s One Big Beautiful Bill Act, or OBBBA, revoked most of the tax credits, it also made solar equipment from certain countries — including China — ineligible for the few tax credits that remain. That, along with the new tariffs, may help a U.S. manufacturer like Qcells compete with Chinese imports, which are now more expensive.
The two policy approaches have the same ultimate goal, according to researcher Coco Zhang of the banking and investment firm ING. But it’s been whiplash for companies.
Following Trump’s latest executive actions, Qcells is still likely able to find a way to be successful, Zhang said. But Qcells has already made a multibillion-dollar investment in its brand-new facility that took more than three years to come online. For other companies with less capital and poorer timing, the supply-side incentives for domestic production may not be enough — especially when the policies could completely change again.
As a part of the OBBBA, the Trump administration closed the IRA loophole that had left room for China-based solar companies to simply set up shop in the U.S., which, according to Zhang, may go further still toward rooting out Chinese competition. In the long run, she’s optimistic that the U.S. solar panel industry can complete its shift to domestic production. But because the rules discouraging foreign ownership cut deeper into the supply chain, those restrictions and the policy back-and-forth could make things harder to navigate in the short term, she said.
The short-term outlook is complicated for those buying solar panels, too. The phaseout of federal clean energy tax credits removed a major incentive to develop new solar projects, and the Trump administration has taken steps to cancel federal funding for clean energy projects and add new hurdles for solar and wind installations on federal land. The courts have blocked or reversed some of those actions, but the delays add costs and uncertainties even for projects that do ultimately move forward.
In the first quarter of this year, clean energy advocacy group E2 tracked nearly $13 billion in abandoned investments in solar, wind, and battery projects. But some $18 billion in new projects were announced as companies scrambled to meet the deadline of the expiring tax credits. While the new tariffs and price controls on polysilicon could help U.S. manufacturers compete to supply the solar developments that remain, they could also drive up costs for developers, Zhang said, and “limited U.S. supply means many will still depend on imports and face higher costs.”
But industry experts maintain that solar isn’t going anywhere. It’s still one of the cheapest sources of electricity at a time when energy demand is growing fast. Solar panels are also readily available, while gas turbines are backordered for years. Solar and storage made up 90% of new power added to the U.S. grid in the first quarter of the year, according to the Solar Energy Industries Association.
“We absolutely should make solar, right? Like it is the fastest deployed, lowest cost foreseeable,” said Damiani. “Solar will be, for the next hundred years, a good portion of our energy.”
The questions, experts agreed, aren’t whether solar development will keep happening, but how quickly, how much it will cost, and who — and where — will make the solar panels.
It’s only the third such project to hook up to the U.S. grid. It comes as surging electricity demand drives interest in the source of around-the-clock clean power.
Sage Geosystems has hit a big milestone out on a rugged tract near San Antonio: The startup is producing power from its first next-generation geothermal plant. The system is just the third of its kind to come online in the U.S. as the sector races to commercialize the source of on-demand clean electricity.
The novel geothermal facility in Texas has been running since April, Sage exclusively shared with Canary Media. The Houston-based firm said the 3-megawatt pilot plant has performed reliably and as predicted after more than 120 days of grid-connected operations.
Cindy Taff, Sage’s CEO, said the results will “directly inform and de-risk” an upcoming collaboration in Nevada with Ormat Technologies, a conventional geothermal leader that is increasingly dipping its toes into next-generation technology. The Nevada project is a necessary precursor to Sage’s deal with Meta to develop 150 MW of geothermal power.
Sage’s enhanced geothermal system is a type of nascent tech that involves drilling deep into hot rocks and fracturing them to create water pockets, then using the heat to generate power. It’s distinct from the decades-old traditional geothermal plants that rely on what Taff called “very unicorn geology” — the few places in the world where a combination of water, heat, and permeable rocks are easily accessible.
For all the buzz around the technology, just two other enhanced systems have connected to the U.S. grid so far.
In 2013, Reno-based Ormat completed a 1.7-MW demonstration project at its conventional Desert Peak facility in western Nevada, before returning its focus to old-school geothermal for a time. That demo is no longer producing power, Ormat confirmed.
A decade later, Fervo Energy began operating a 3.5-MW geothermal plant in northern Nevada in partnership with Google. Building off that project, Fervo is now constructing a 500-MW facility in Utah, which is set to come partially online in October.
Sage likewise expects its early success in Texas to fuel its commercial-scale ambitions.
The startup has been developing the pilot since 2024, when it reached a deal with San Miguel Electric Cooperative to use land near a coal-fired power plant in the town of Christine. Sage built its own substation there and intermittently sells power to the Texas grid.
Taff said that one of the most promising outcomes has been the relatively limited water loss from the underground system. Sage’s approach involves creating a network of fractures, into which it pumps and stores large volumes of water. As hot water pushes up against the rocks around it, mechanical pressure builds, which is released when the crew opens a valve at the top. This is different from other enhanced projects, which use fractures to flow water between two wells without pressure.
In both cases, water can migrate into surrounding rock formations as it moves through the fractures. The more water a project loses along the way, the less efficient it becomes at producing energy.
Sage lost less than 10% of the water that it cycled through the Texas system on multiple occasions, which Taff said bodes well not just for the company but also for the larger universe of enhanced geothermal, if it adopts similar methods.
“The net power output that you can produce from these technologies is going to go up, she said, noting that curbing water loss will enable enhanced systems to scale commercially at a competitive cost.
Initially, Sage planned to use similar geothermal techniques to develop a long-duration energy storage system near the coal plant. But in recent years, Texas has built one of the largest grid-battery fleets in the world, making the timing less ripe for rolling out a novel storage technology. So Sage is now primarily focused on meeting the nation’s growing demand for around-the-clock clean electricity.
To that end, Taff said Sage expects to begin drilling its first well at one of Ormat’s conventional geothermal plants in Nevada later this year. Sage will provide the hot water it produces to Ormat to generate electricity at the existing facility — allowing Sage to demonstrate its technology without going through the costly, lengthy steps of connecting to the grid or building a power plant.
Sage hasn’t yet specified how large this system will be, but does expect to start producing electricity in 2027 and reach full-scale production in 2028. Once that happens, Sage will begin working with Meta to start developing 150 MW of next-gen geothermal power somewhere east of the Rocky Mountains. All told, Sage has lined up about a gigawatt’s worth of projects on paper.
The Texas pilot enables Sage to “actually model and predict how the [reservoir] behavior is going to be going forward,” she said. “And that sets us up very nicely for scaling and building commercial facilities with our approach.”
An update was made on Aug. 19, 2026, to confirm that Ormat’s Desert Peak project is no longer generating power.
Trump officials touted the storage and EV plant as an example of “energy dominance,” underscoring increasing bipartisan acceptance of grid batteries.
LANSING, Mich. — The Trump administration has made clear its disdain for electric vehicles and clean energy. Yet at the grand opening of South Korea–based LG Energy Solution’s latest battery manufacturing facility, Interior Secretary Doug Burgum cheered the factory as a fulfillment of the president’s agenda.
“That’s the American energy dominance in action, which is more jobs, strong allies, secure supply chains — and right here, that’s happening,” Burgum said Tuesday during the Lansing factory’s opening ceremony.
LG executives have framed the plant’s opening in similar terms, echoing the administration’s focus on energy security and the importance of making the tech in the U.S., given that China produces most of the world’s batteries.
And like many of its peers in the industry, LG has adapted wide swaths of its Lansing site, originally meant only for EV batteries, to make what is proving to be a more politically palatable technology: energy storage systems for power grids.
“No matter which side of the aisle you’re on, there’s a desire to have energy independence and to meet load growth,” said Devon Wilson, vice president of sales and marketing for LG’s U.S. energy storage division.
LG invested more than $2 billion into building its new Lansing plant, which currently employs 900 people and plans to hire approximately 800 more.
Once at full capacity next year, the facility is expected to produce more than 35 gigawatt-hours of battery cells annually, according to Anthony O’Donovan, the plant’s operations director. That would make it one of the biggest domestic plants producing cells, which are the individual building blocks of battery systems, LG Energy Solution spokesperson Phil Lienert confirmed.
From Lansing, the cells will go to plants across the country — including both to clients and to one of LG’s own facilities in Holland, Michigan — to be connected together to form battery modules, which are then arranged into battery packs, Lienert said.
This domestic network of battery manufacturing is very new, and arriving just as battery energy storage systems themselves grow at a rapid clip. The U.S. didn’t make any of its own battery cells until 2025, when companies including LG added a total of 20 GWh of manufacturing capacity, according to the U.S. Energy Storage Coalition, an industry group.
By the end of this year, the coalition expects that figure to increase nearly fivefold, to 96 GWh of cell production capacity.
The Lansing facility was first announced in 2022 as part of Ultium Cells, a joint venture between LG and General Motors to source battery cells for the Michigan automaker’s EVs.
By 2024, however, consumer interest in EVs was lagging, and President Donald Trump vowed on the campaign trail to slash federal support for the vehicles. At the end of that year, GM sold its stake in the Lansing factory to LG, making the Korean company the site’s full owner.
The Trump administration has since eliminated the $7,500 tax credit for consumers who purchase EVs and canceled more than $700 million in federal funds for battery and EV manufacturing projects. (It did, however, preserve tax credits for clean energy manufacturing facilities and for the installation of stationary storage systems.)
By the end of 2025, dozens of battery and EV manufacturing projects were canceled nationwide, totaling more than $21 billion in lost investment, according to a report from E2, a clean energy advocacy group. Michigan, which had banked on exactly these types of projects to grow its economy, given its automotive prowess, was hit the hardest.
So, LG leaders decided to embrace a more promising sector: energy storage.
In the last few years, energy demand in the U.S. has surged in part because of the massive data centers being built for the artificial intelligence boom. Battery storage systems are well-positioned not only to swiftly meet tech companies’ demand for power, but also to absorb the sharp dips and spikes in energy usage inherent to AI data centers, Wilson said.
“It’s a great situation for us,” Wilson said. “We’ve seen an explosion in the size of the ESS [energy storage system] market, so we’ve really been able to grow our demand.”
In just four years, the amount of battery storage capacity in the U.S. has increased nearly tenfold, from 4.7 gigawatts in 2021 to 43.6 gigawatts at the end of 2025, according to the U.S. Energy Information Administration.
This year, developers have already built 8.2 gigawatts of battery storage nationwide, according to the EIA — a statistic that Michigan Gov. Gretchen Whitmer, a prominent Democrat, hailed as “amazing” at the opening of LG’s Lansing factory.
She also referenced Michigan’s “historic clean energy law” that requires 2.5 gigawatts of battery storage, which are often installed alongside solar farms to help stretch the carbon-free energy into other times of the day, by 2030.
“Michigan is poised to take advantage of this growth,” Whitmer said.
In line with market shifts, the Lansing plant has diversified so that it will produce roughly half EV battery cells and half energy storage cells, according to Bob Lee, the North American president of LG Energy Solution.
The EV battery cells will no longer go to GM, but to Toyota. And the plant will produce nickel-manganese-cobalt cells, which are more energy-dense, according to LG’s press release.
Meanwhile, the energy storage cells have been contracted by a variety of offtakers, including renewable-project developer Terra-Gen and Korean clean energy manufacturer Qcells, LG spokesperson Lienert said. These cells will be lithium-iron phosphate, which isn’t as energy-dense as other chemistries but has less of a fire risk.
Next year, as the Lansing facility ramps up, it is also expected to supply Tesla’s Megapack 3 factory in Houston, an agreement that Lienert confirmed but would not elaborate on.
First reported by Reuters last summer, the $4.3 billion LG-Tesla deal was officially announced in March — but by the Trump administration as part of its focus on energy security, not by the companies.
Now that it’s up and running, the Lansing facility joins LG’s growing portfolio of cell manufacturing sites. The Korean company still runs two Ultium EV battery plants with GM, one in Tennessee, another in Ohio.
Last year, LG expanded its flagship Michigan site in Holland, which in 2012 became the first in the U.S. to make EV batteries, to also produce energy storage battery cells and packs.
And this March, LG held a grand opening for its facility in Windsor, Ontario — the first commercial-scale battery manufacturing plant in Canada as well as the company’s largest North American plant, Lienert said.
“We’ve almost got a perfect latitudinal line now that extends from Holland through Lansing to Windsor,” Lienert said. “We think of this as being the belt of ESS battery manufacturing for North America.”
California’s Democratic candidate for governor, Xavier Becerra, is borrowing a page from Australia with a new plan to give state residents free electricity during certain parts of the day.
Last week, Becerra unveiled a proposal to offer up to two free hours of electricity per day, starting with low-income families. He estimates it could save households about $1,000 per year.
The idea could find traction with restive voters in the Golden State. Power prices in California have risen by 46% in the last decade, the largest increase in the nation. And energy affordability has become a top issue at the ballot box nationwide.
The program, which he calls “Power Hour,” aims to help Californians soak up more of the state’s copious solar energy.
“We produce so much solar energy … that oftentimes in the afternoon we can’t make use of all of it, and so it essentially goes to waste,” Becerra said at a Politico event last week. Solar power can become so abundant that wholesale electricity prices dip into the negative, meaning that producers will pay others to take the excess off their hands. The state throws away what it can’t consume or store for later with batteries.
Becerra’s plan could send a strong market signal to consumers to take full advantage of the state’s solar riches, he explained to his California audience. “The best way to get you to readapt, to recalibrate, is to tell you the best time for you to use electricity today,” he said, giving as an example a free-power period between 1 p.m. and 3 p.m.
Some energy retailers in Australia started offering free-power plans years ago to take advantage of the solar power flooding the grid.
Thanks to a push from the Aussie federal government, now millions more can access the scheme, known as Solar Sharer. As of last month, households with smart meters in three of the country’s six states can sign up for rate plans that offer free power in the middle of the day. For example, in New South Wales and Queensland, the energy bonanza is from 11 a.m. to 2 p.m.
The no-cost energy is capped at 24 kilowatt-hours per day — enough to cover the energy needs of a household of five, according to the Australian government. Anything beyond that the utility charges for.
While free power sounds like a great deal, it’s important to note that these plans don’t automatically guarantee lower electricity bills. Outside the free-power period, utilities can set higher-than-average rates to recoup costs — sometimes, much higher.
One of the largest retail providers in Australia, AGL, which serves more than 4 million customers, has a free-power plan with a peak rate that’s almost twice what it charges under its standard plan. The federal government provides an online tool to help consumers figure out whether switching to a plan with free power will actually save them money.
People who can shift a lot of their energy demand to the free period or cache the zero-cost power for later will benefit most. The Australian government is making that easier to do by providing a 30% discount on home batteries. (The U.S. had a similar incentive, a federal tax credit, until the Republican-held Congress and President Donald Trump axed it last year.)
More than half a million home batteries have been installed under the Aussie program. And thanks to cheap, high-tech electric vehicles out of China, households increasingly have battery behemoths in their driveways. EVs now make up a quarter of new car sales on the continent.
Existing California programs could give Becerra’s plan a big boost. Qualified households could get a generous home-battery incentive of up to $1,100 per kilowatt-hour. And the state is rolling out a $3,500 EV rebate for first-time buyers.
Some experts doubt a free-power program can be as effective in California as it is shaping up to be in Australia.
“I applaud the intent here to change human behavior,” said Saul Griffith, CEO of Otherlab and founder of electrification advocacy nonprofits Rewiring America, Rewiring Australia, and Rewiring New Zealand. “But unless this [plan] really goes along with more comprehensive electricity market and pricing reform, it may not mean that much.”
Electricity could be far more affordable if Americans unleashed clean, cheap, distributed power, Griffith contends. But to do that, “you have to break the single-utility monopoly model,” he said.
Severin Borenstein, faculty director of the Energy Institute at the University of California, Berkeley’s Haas School of Business, also had a mixed reaction to Becerra’s plan.
“I do think this would be a step in the right direction, making electricity prices more accurately convey the cost of supplying the electricity in a given hour,” Borenstein said in an email. “But it would require making up the revenue shortfall somehow, which I fear would be done by raising prices in other hours.”
The vast majority of what utilities charge customers for is not the electricity itself but fixed system costs, according to Borenstein. “Those costs would still need to be covered,” he noted.
If elected, Becerra can’t implement his plan by fiat. He said he would work with the public utility commission, utilities, and other stakeholders to realize his plan within his first year in office.
Despite the uncertainties, Michael Rochmes, policy and advocacy manager at the nonprofit U.S. Green Building Council California, is excited to see Becerra’s Power Hour take shape.
The prevailing narrative has been that electricity is expensive, and costs are ballooning faster than inflation, he said. But that story leaves out how renewables and battery storage can deliver “long-term energy abundance,” Rochmes noted. “If this idea can break through and get people who aren’t in the energy space to start to understand the benefits of electrification, load shifting, battery storage, and renewable energy, I think this is a huge win.”
Next-generation geothermal projects are underway in the U.S. West, but states will need more targeted policies for the industry to scale, a new report argues.
Next-generation geothermal energy has massive potential in the western United States, but it won’t be realized unless developers can overcome the big economic barriers these novel systems face.
Unlike traditional geothermal plants, next-gen projects use innovative underground techniques to produce power wherever rocks are sufficiently hot, making it possible to harness heat in more locations. The energy source could provide hundreds of gigawatts of clean electricity around the clock, up from just 4 GW nationwide today.
Amid ballooning energy demand from data centers and electrification, western states are increasing their support for the industry, using tools like direct investment and permitting reform. These state-level efforts are supporting a wave of pilot projects and first-of-a-kind systems across the region, where heat is accessible at relatively shallow depths.
Still, states will need to adopt more sweeping and coordinated policies to help companies secure the kind of large-scale financing necessary to scale up next-gen geothermal, said Ann Garth, policy manager for superhot rock geothermal at the nonprofit Clean Air Task Force.
Garth is the lead author of a new report, shared first with Canary Media, that describes how states can “de-risk” geothermal for infrastructure investors, who typically pick up where venture-capital funds and federal research programs leave off.
Geothermal’s high upfront drilling costs, the slow trickle of investment returns, and the uncertainty around project development — like how long permitting will take or how profitable the resource will be — are major stumbling blocks for project financiers. Whereas some investors can stomach any two of the factors, “the three in combination will make financing very difficult,” Garth said.
Many western states have made some policy changes to address these challenges, though none have put all the pieces together yet. In its new report, Clean Air Task Force outlines what the states should focus on and highlights which steps they’re already taking.
Perhaps the most meaningful move that states can make is to create demand for utility-scale geothermal.
Take California, as an example. In 2021, the California Public Utilities Commission adopted a procurement order calling on utilities to add at least 1 GW of “clean firm resources,” such as geothermal, to meet the state’s long-term climate goals and grid reliability requirements. The mandate is largely responsible for the rise in power purchase agreements for next-generation projects — including Fervo Energy’s Cape Station in Utah. Southern California Edison has agreed to buy 320 megawatts of power from the 500-MW project, which is set to come partially online this fall.
“That has been an incredibly important driver of the growth in the geothermal industry,” Garth said. “Seeing those PPAs come in has given a lot of confidence [to investors].”
California itself has installed almost 2.9 gigawatts of conventional geothermal capacity, making it the nation’s leader. Colorado, by contrast, is working to land its first geothermal power plants of any kind.
In June, Colorado’s legislature passed a bipartisan bill that requires investor-owned utilities to solicit proposals for the development of large geothermal projects greater than 25 MW, as well as smaller systems. The state also awarded $494,000 to Fervo to evaluate the potential for developing geothermal power projects in two regions of the state.
New Mexico, meanwhile, is backing the commercial deployment of a novel geothermal system through its $75 billion sovereign wealth fund that draws on oil and gas royalties. Through the fund’s venture-capital investments, the state is supporting the startup XGS Energy as it develops a 150-MW closed-loop system in New Mexico along with Meta.
However, before developers get to the point of proposing projects, they need to scour geologic data to understand what rock formations are like, and how hot they are at certain depths. Many states already have this information from earlier oil and gas development, but the files aren’t easy to access.
Some states are working to make geological records more readily available. North Dakota has scanned and digitized the bulk of its historic data, which it provides to academics for free and to companies for a fee. Earlier this year, Arizona invested $1 million in the state’s geological survey to integrate historic subsurface data with new information, gathered using airborne and laser-based imaging, to bring geothermal development to Arizona.
Washington state, which also doesn’t produce geothermal power, passed a bipartisan law in 2024 that directs the state’s geological survey to compile a public database of subsurface information. It also creates grant programs for companies to do deep exploratory drilling in areas with high geothermal potential.
State permitting agencies, meanwhile, are still wrapping their heads around next-gen geothermal.
As a result, permitting can be a slow and unpredictable process — and a source of anxiety for investors. “The longer you have to wait before you can actually start generating revenue, the more expensive it gets,” Garth said.
Nevada devised a solution to this problem in 2008 to support its conventional geothermal sector. The state’s environmental protection and minerals divisions entered a cooperative agreement to clarify which agency has jurisdiction over certain aspects of drilling and operating geothermal wells, avoiding confusion and delays. Nevada has installed 892 MW of conventional geothermal capacity, making it second to California, and Fervo is developing a 115-MW “enhanced geothermal system” with Google in the state.
Texas, which is home to several test projects but no commercial geothermal, resolved a bureaucratic conundrum that had slowed next-gen development. In 2023, lawmakers passed a law to clarify who owned the geothermal resources on a given property: the surface landowner, not the owner of subsurface oil, gas, and minerals.
Another major barrier to scaling next-generation geothermal is access to transmission lines. This plagues every energy source in the U.S., and it can’t necessarily be tackled by individual states.
Connecting rural geothermal plants over long distances to pockets of demand requires coordinated, long-term efforts within regions, and that work has hardly begun in the West, according to Clean Air Task Force.
The group also recommends creating innovation test beds as a way for states to reduce project risks in specific areas. For example, the federally funded Utah Forge is an underground field laboratory in Beaver County, Utah, that has developed and refined enhanced geothermal using oil and gas techniques. Fervo said it built Cape Station next door so the company could collaborate with researchers who have extensively explored the area’s geology.
So far, states have adopted “an interesting hodgepodge of efforts” to attract geothermal investment, Dan West, senior Western regional policy manager at Clean Air Task Force, said by phone.
But “no state has checked all the boxes and pulled all the policy levers yet,” he said.
As the legislative session nears an end, lawmakers push ahead bills that aim to stop AI centers from raising utility costs and spur builders to opt for clean energy.
California, with its sky-high electricity prices, isn’t facing the same influx of data centers that many other states are. But the massive facilities are still being built and proposed in California — and legislators are racing to stop them from pushing up utility rates and pollution.
Two major data center bills passed a key committee last week as California’s legislative session nears its close at the end of this month. Senate Bill 886 aims to prevent data centers from raising utility costs for other consumers, while SB 887 would incentivize developers to invest in clean energy and nearby communities.
Data centers have lawmakers nationwide walking a fine line. Voters are increasingly worried about the facilities’ impacts on energy affordability and the environment, but the industry also promises jobs and economic benefits. State Sen. Steve Padilla, the Democrat who penned both California bills, says his proposals would rein in the sector without stifling it completely.
“People are asserting that it’s a binary choice” on data centers — “you can either ban them all, which is some communities’ reaction, or you can have zero regulation,” said Padilla, whose bills were inspired by a high-profile conflict between a data center developer and residents in a county he represents.
“I think we can walk and chew gum at the same time,” he said. “We can protect consumers and communities, and support infrastructure that supports tech companies and jobs.”
SB 886 takes on the first part of that equation. It would require the California Public Utilities Commission to set rules for data centers of at least 25 megawatts to fully cover the costs they impose on customers of the state’s three major utilities. Data centers would pay for the new power generation and grid upgrades they need, along with a “reasonable share” of the fees utilities collect for wildfire mitigation, environmental programs, and other social initiatives.
This is not a new approach, with many states already enacting similar “large load tariffs.” Along with these requirements, SB 886 would create a mandatory demand-response program that forces data centers to stop pulling power from the grid during supply-demand emergencies. Similar mandates are under consideration in places like Texas and the 13-state region served by grid operator PJM Interconnection.
SB 887, meanwhile, would offer expedited state environmental review for data centers “if they commit to high standards and serving communities,” Padilla said. Data centers seeking this special treatment must get 100% of their hourly electricity consumption from carbon-free resources within five years, 75% of it newly built. And they’ll need to draw from zero-carbon backup power — most likely batteries — when the grid is under stress, rather than using diesel generators, which are installed by almost all data centers. Developers would also have to pay for grid interconnection costs in advance and commit to a community benefits plan.
Although California has yet to see the massive, gigawatt-scale data centers being built in some states, several larger-scale projects are in the works near Silicon Valley. Those include Microsoft’s 48-megawatt data center in San Jose, developer Stack Infrastructure’s 77-megawatt data center in Hayward, and, most recently, Google’s 250-megawatt research and development center in San Jose.
More data centers are coming. Northern California utility Pacific Gas & Electric has 10 gigawatts of demand from data centers in its pipeline over the next 10 years, equivalent to what’s needed to power roughly 7.5 million homes. PG&E says that load growth will create billions of dollars in tax revenue and — more important to its customers — lower electric bills by 10% or more “by spreading fixed costs across more energy usage.”
Environmental and consumer groups are skeptical. The Union of Concerned Scientists warned in a May report that the state “currently has too few protections to ensure data center costs are not passed along to ratepayers.”
“The data center developers don’t really care about costs,” said Matthew Freedman, senior staff attorney with The Utility Reform Network, a consumer advocacy group that supports SB 886 and SB 887. “They’re focused entirely on speed of development, and on proximity to Silicon Valley.” Meanwhile, PG&E and the state’s other investor-owned utilities earn guaranteed profits based on how much money they invest in capital infrastructure, giving them little incentive to control those costs, he said.
Although SB 886 has won the support of utility worker unions, PG&E opposes it. In an email to Canary Media, company spokesperson Paul Moreno said the bill would “introduce rigid, duplicative requirements that conflict with existing regulatory processes, risk higher costs for customers, and delay critical infrastructure needed to serve the state’s growing energy demand. We continue to work with lawmakers to improve the bill, so it better supports affordability, reliability and equitable cost allocation for all customers.” PG&E has taken no position on SB 887.
Both bills face pushback from the Data Center Coalition, a trade group representing major data center developers, natural gas generator company ERock, and business organizations. The groups wrote in a March letter that data centers shouldn’t be “singled out” for different treatment from other big power-using customers. They also fear that SB 886’s demand-response mandate could force them to curtail computing operations relied on for critical health care and government services.
Meanwhile, the coalition argues that SB 887’s clean power requirements are virtually impossible for data centers to meet. “We don’t see it as a streamlining mechanism, because those standards are not attainable,” said Khara Boender, Western government affairs director for the group.
It’s unclear how Gov. Gavin Newsom (D) will respond to bills opposed by politically powerful utilities and tech companies. Last year, Newsom vetoed a bill that would have required data centers to report their water usage. And Padilla said his 2025 proposal to create a new rate class for data centers was watered down to a “study” bill requiring the utility commission to examine and report on their energy cost impacts.
But the politics are shifting. A recent poll commissioned by Net-Zero California, a Sacramento-based environmental policy group that supports SB 886 and SB 887, found that 70% of voters in the state oppose data centers in their communities, and that 74% want to see requirements for data centers to cover their costs and use clean energy. Newsom recently told reporters that “it’s absolutely essential and appropriate that these hyperscalers pay their fair share,” citing Google and Microsoft specifically.
Padilla said he expects SB 886 and SB 887 will pass in the state Senate and Assembly before the end of the legislative session this month. Newsom has until the end of September to sign bills into law.
While solar and EV sales cratered after the Republican Congress eliminated federal tax credits, batteries bucked the trend. Here’s why.
Last fall, as generous federal incentives for consumer cleantech were set to expire, people raced to lock in good deals on EVs and rooftop solar. Then, this year, sales cratered.
But home batteries bucked the trend. Federal tax credits for residential storage expired at the end of last year, prompting record sales in Q4 of 2025 — and then sales climbed even higher in the first quarter of 2026, per a BloombergNEF analysis of U.S. Energy Information Administration data. Homeowners installed a total of 673 megawatts of battery storage in Q1 of this year.
A few factors explain the market’s resilience. There’s the zeitgeisty reason: Across the nation, utility bills are high and rising, and batteries, typically paired with rooftop solar, offer people the ability to radically reduce their reliance on the centralized grid. There’s also the wonky explanation: State policies meant to spur home battery adoption are now doing just that.
Adoption is highest in the states where these factors — high electricity costs and supportive policy — coincide. California has since 2023 incentivized households to pair storage with solar, and in both 2024 and 2025 the state accounted for around three-quarters of home battery installations nationwide. Meanwhile, Hawaii, which has the highest electric bills in the country, created a new storage incentive program last year that resulted in a surge of installations in Q1 of this year, per BNEF.
The rising adoption comes even as the rooftop solar market struggles. Last year’s Republican tax and spending bill, the One Big Beautiful Bill Act, eliminated long-standing tax credits that knocked 30% off the price of both rooftop solar and storage systems. As a result, BNEF expects that this year residential solar installations will fall to their lowest level since 2020.
The stubborn growth of residential energy storage is another reminder that batteries are fast becoming a critical part of the U.S. electricity story. Large-scale batteries, for which Republicans actually preserved tax credits in last year’s law, are being built at a blistering pace. Expect home battery adoption to keep climbing, too.
Swapping your gas car for an electric vehicle is a climate win in almost all cases, says a new study, which even “tipped the scales” against EVs.
A few years ago, environmental scientist Elliot Campbell went around asking people why they would, or would not, switch to an electric vehicle. A surprising number of them asked him a question in return: Because building an EV generates emissions, isn’t it better for the planet just to keep my gas car running for as long as possible?
Campbell, a professor at the University of California, Santa Cruz, didn’t know the answer, so he set out to find it. Turns out the old adage that the greenest car is the one in your driveway is a myth. In fact, his study, published today in the journal Science, finds that swapping even a two-year-old gas car for an EV leads to a lifetime emissions savings of roughly 50 percent.
Not everyone can afford to ditch a nearly new car, of course. It’s simply the most extreme example of the broader point his study revealed: The emissions saved by driving an EV very quickly compensate for the planet-warming gases generated by building it. Campbell said that finding consistently surprises his students, and goes against his own instincts.
“I like to repair things and keep them going,” he said. But, “we found there is a big advantage to retiring the gas vehicles early.”
Campbell designed the study to give internal combustion vehicles every possible advantage. “We really tipped the scales in favor of the gas vehicle,” he said. Most notably, it ignored the emissions that went into making the gas car, treating them instead as a sunk cost. The EV still came out ahead, which suggests that climate-conscious drivers should make the switch as soon as it’s feasible.
“You’re just delaying the benefits longer and longer,” he said, noting that sidelining gas guzzlers off the road can improve air quality as well. This is especially true for cars that were built to less stringent standards, added David Reichmuth, a transportation sustainability expert at the Union of Concerned Scientists. “The magnitude of the benefits for getting an older gasoline vehicle,” he said, “can be much higher in terms of the air pollution.”
Reichmuth was not involved with Campbell’s study, but said it aligns with his own work on the issue. His analysis found that EVs reach an emissions break-even point at around 18,000 miles, which the average driver travels in about 18 months. That, however, depends on where a person lives and the source of their electricity.
The benefit is greatest where the grid is greenest. In upstate New York, which generates a lot of hydroelectric power, getting around in an EV is like driving a gas car that gets 219 mpg. But even in the Rockies, where coal and natural gas are the norm, an EV is better than anything getting less than 68 mpg.
Campbell’s study identified few exceptions to the conclusion that replacing a gas car with an electric one significantly reduces greenhouse gas emissions. Even moving away from high-efficiency vehicles and hybrids, like the Toyota Prius, is a climate win in the long-run. One case where it wouldn’t make sense, Campbell and his co-author found, is with plug-in hybrid electric vehicles, which have larger batteries and travel farther on electric power before switching to an internal combustion engine. Another is low-mileage situations, such as with a second car that doesn’t get used that often.
“To me, this is the biggest factor,” said Moaz Uddin, senior electric vehicle policy specialist at the think tank Great Plains Institute, about mileage. He gave the example of a retiree who only drives their Prius a few thousand miles a year. “It’s good that the study considers that.”
The new research finds that in order to repay the carbon debt of making a new EV, it must be driven 4,400 miles if it’s a car and 6,700 miles each year if it’s a truck. That’s already well below the 12,500 miles the average driver travels in a year, and the benefits to making the switch are likely to grow.
As the United States increasingly relies on renewables, for example, charging an EV becomes even more environmentally appealing. Campbell and his co-author also point to improvements in battery recycling as a way of reducing the emissions involved with making an electric car.
One hole in this latest study is that it doesn’t consider the cost of going electric. While previous research has shown that EVs come with higher upfront costs but lower operating expenses, it’s a thread that Campbell hopes economists pull on. He would also like to see someone better account for the emissions generated while extracting oil and getting gasoline to the pump, rather than simply the burning. But, for now, he believes the study sends a clear message.
“We’re trying to show that there’s not an environmental motivation for extending the lifetime of a gas vehicle,” he said. “Electric vehicles are a very clear winner.”
The most direct policy interpretation of the study would be to give people money to scrap gas cars. There have been some efforts to do this, such as the 2009 federal Car Allowance Rebate System, also known as “cash for clunkers.” That gave people $3,500 to $4,500 if they upgraded to more efficient vehicles, and blew through its $3 billion budget in only a month. Reichmuth, though, says that the issue could be tackled earlier in the process.
“The obvious policy implication is don’t sell the gasoline car to begin with,” he said, with the corollary being that EVs need to be as attractive an alternative as possible. “Make sure there are more options, more support, for people to make that initial choice.”
Firms that enlist homes to reduce energy demand — and costs — have long complained that utility data rules prevent them from helping in PJM. FERC agrees.
A recent ruling from federal regulators will let virtual power plants help meet surging energy demand in the county’s biggest energy market.
Late last month, the Federal Energy Regulatory Commission ordered PJM Interconnection to accept statistical sampling as a valid method for measuring the reliability of programs tapping into demand-response and virtual-power-plant programs, which pay customers to turn down energy use as needed. The decision requires the grid operator to reconsider strict data rules that had prevented providers of this carbon-free resource from participating in PJM’s constrained energy-capacity market.
In its decision, FERC ruled in favor of Voltus, which runs demand-response and virtual-power-plant programs, and the Mission:data Coalition, a nonprofit advocacy group, and against PJM’s desire to preserve its status quo.
FERC agreed with Voltus and Mission:data that, under its current rules, PJM is losing out on at least 4.9 gigawatts of capacity — the equivalent of several large power plants — “at a time when PJM is experiencing unprecedented load growth driven in part by hyperscale data center development, threatening reliability.”
Booming power demand from data centers and bottlenecks in power plant construction are not just threatening reliability in PJM but also driving up energy costs for the 67 million people it serves across 13 states. FERC found it would be “unjust and unreasonable” to allow the current rules to stand.
Last month’s ruling caps a yearslong fight from providers of demand-response and virtual-power-plant services.
“This is a huge win, and we’re really optimistic that it will unlock hundreds of megawatts of residential load over the next several years,” said Marissa Galizia, Voltus’ senior director of partnerships. FERC’s order makes clear that “PJM has the power to change the rules even while utilities aren’t providing the data,” she said.
At issue was PJM’s concern about relying on third-party demand-response aggregators to reduce household electricity demand when needed. PJM insisted that Voltus and other demand-response firms must furnish detailed evidence that participating households actually cut power when prompted to do so. Specifically, PJM required smart-meter data, which is collected in the service territories of most utilities PJM covers.
If firms could not produce that data, PJM would not count on — or pay for — that demand-response capacity to show up during times of peak demand.
But for the most part, demand-response firms could not get their hands on that data. That’s because, as Voltus and Mission:data argued to FERC, most of the major utilities in PJM territory have failed to make that data from their digital smart meters readily available.
It’s a catch-22. And as a result, PJM has missed out on gigawatts of demand-response capacity that could have helped alleviate the reliability and cost crunch it faces — and aggregator firms have been essentially locked out of the lucrative capacity market.
Utilities blame states’ data privacy regulations for their conservative management of smart-meter data. FERC doesn’t get to tell states how to manage those data privacy and data access rules, but it can compel PJM, which it has jurisdiction over, to accept alternative forms of data.
That’s what FERC did in the July decision.
Given the “significant barriers to obtaining interval meter data,” FERC told PJM to allow aggregators to use a statistical sampling method that the grid operator had relied on before smart meters existed. PJM also still allows this method for customers that don’t have smart meters. In light of those facts, FERC found that “statistical sampling is a valid method to approximate load reductions when interval meter data is not reasonably available.”
Both PJM staff and Monitoring Analytics, its independent market monitor, protested that letting demand-response companies use statistical methods could undermine reliability.
Monitoring Analytics argued that allowing statistical sampling would “degrade PJM’s ability to maintain resource adequacy and to correctly determine efficient capacity market prices through supply and demand.”
FERC disagreed, citing evidence presented by Mission:data and Voltus showing that statistical sampling can be as or more accurate than methods that use metered data when applied to large numbers of homes, as opposed to single large customers like factories.
The order won’t take effect immediately. FERC directed PJM to launch a proceeding to work with stakeholders to find a method that parties could agree on, with initial plans due within 45 days of FERC’s order.
“We’re going to be working with our partners to submit answers to the questions and propose what we’d like to see,” Voltus’ Galizia said. “Generally, we’d like to make it as easy as we can while guaranteeing that that process is as accurate as possible.”
FERC’s ruling comes at a tense time for PJM. Over the past year, the Trump administration and state governors have attacked the grid operator for failing to mitigate the huge increase in capacity market prices that are driving up utility rates and driving public anger against utilities and data center developers.
“I hope the decision sends a message to PJM and its stakeholders,” said Ken Schisler, chief legal and regulatory officer at CPower, a demand-response company that brought a similar complaint that FERC rejected in 2024 for lack of evidence. “The message is to stop the nonsense and to remove barriers that are keeping demand response from growing in the market.”
Michael Murray, president of Mission:data, hopes the ruling will also add fuel to his decade-long effort to make utilities and state regulators unblock smart-meter data that technically belongs to customers.
FERC’s order doesn’t address the underlying state-by-state data-access barriers that Mission:data is working on — the agency doesn’t have the jurisdiction to do so even if it wanted to.
Still, Murray hopes it will push state regulators to revisit their data-access policies, since “states may not like the remedies that FERC comes up with in this case or in other cases.”
And more broadly, he said, it’s the first time the agency has acknowledged just how critical this issue is.
“FERC has finally recognized that what I’ll call data blocking is not just an artifact of state privacy laws, and it’s not something to just ignore and say, ‘Oh this is just a state matter,’” he said. “They definitely said that it rises to a Federal Power Act matter.”
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