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China is accelerating its efforts to clean up heavy industry, allocating money for the first time last year to help hard-to-decarbonize sectors increase the use of fuels such as green hydrogen. The push comes as the country continues building more solar panels, wind turbines, and nuclear reactors and expanding its grid faster than anywhere else in the world.
Those two trends are converging to spur the greening of aluminum in particular — a commodity that requires so much power to manufacture that it’s nicknamed “congealed electricity.”
Aluminum production hit a record high last year in China as demand for the alloy, which is used in virtually every kind of electrical application, soared in tandem with the country’s data center boom, according to numbers the National Bureau of Statistics released in January. Prices of the globally traded commodity have spiked by nearly 35% in the past year, meaning that aluminum produced with clean electricity, which comes with a green premium, is more competitive.
At the same time, Beijing’s latest policies to steer its world-leading aluminum smelters away from coal are just taking effect. While the most recent national statistics showed steel production at a seven-year low — a result of the shift away from housing construction — analysts say the surging demand for aluminum could speed up the pace of that industry’s transformation.
“I do expect green aluminum production to pick up, even as other commodities retrench,” said Xinyi Shen, the head of the China team at the Centre for Research on Energy and Clean Air, a Finnish nonprofit that tracks Chinese heavy industry. “In China, aluminum decarbonization is progressing … showing stronger policy momentum than steel at the moment.”
There are limits to how quickly the shift can take place. China has for the past decade maintained a cap on aluminum production to prevent smelters from oversupplying and destabilizing the power grid. New production to meet surging demand is quickly approaching that limit, according to a December analysis from the bank ING. But already, the industry is starting to reorient production toward decarbonization.
One way China’s aluminum industry is going green is through recycling. Producing secondary aluminum requires only about 5% of the energy needed to produce primary aluminum, meaning that carbon emissions are typically up to at least 80% lower. Between 2015 and 2024, China’s recycled aluminum output grew by about 6.25% per year, reaching nearly 11 million metric tons in 2024. In March 2025, Beijing set a target of more than 15 million tons of recycled aluminum by 2027.
“This pathway is already cost-competitive and relatively insulated from power-price volatility, so it’s likely to keep expanding even in a softer macro environment,” Shen said.
The other way is by transitioning existing smelters to using clean power. Since nearly 70% of primary aluminum production relies on coal-fired or natural-gas-fired power plants, the sector produces about 2% of global greenhouse gas emissions. The rest is largely powered from hydroelectric dams, next to which older smelters were traditionally sited.
The power-intensive smelting process involves blasting a molten bath of cryolite with an electrical current that separates out dissolved aluminum and yields a molten metal that can be cast into ingots, billets, or bars. In China, where most of the world’s aluminum is produced, the vast majority of that electricity has historically come from coal. Under its new regulations, Beijing wants most of the power that smelters consume to come from renewables.
Last year, aluminum became the first energy-intensive industrial sector subject to a new renewable power mandate requiring green electricity to supply 70% of smelters’ electrons, up from just over 25%.
“Compliance is expected to be met increasingly through green power contracts and renewable-energy certificates, partly in response to both China’s domestic climate goals and emerging international green trade standards,” Shen said.
China has begun shifting its smelting capacity to provinces with excess hydropower or room for wind and solar arrays to offset coal- and gas-fired production.
Even before Beijing mandated that aluminum producers use more renewable power, smelters were already “looking at moving to hydro-rich regions” such as Yunnan province, David Fishman, a Shanghai-based analyst who tracks the Chinese electrical industry at the Lantau Group consultancy, wrote in a thread on X last month.
Wind and solar trailed behind hydropower, nuclear, and coal in the list of the lowest retail power prices in China, Fishman wrote. But he said that buying renewable energy credits was just as valid a solution if those certificates come from vetted, reputable sources in places with expanding production, such as Inner Mongolia or Xinjiang. Still, he noted, relocating to renewables-rich regions “isn’t just about cheap power.”
“It’s also about reducing uncertainty around long-term compliance with rising clean power quotas, which is becoming a C-suite level strategic variable,” Fishman wrote. “This is as true [if] you’re moving the smelter to Yunnan (for all its hydropower) or Xinjiang (where you’re going to have to pursue a wind/solar solution).”
A big open question is whether Chinese companies will start operating new smelters in other countries, and whether those facilities will be powered with renewable electricity, said Seaver Wang, the director of the climate and energy team at the Breakthrough Institute, a research nonprofit in California.
“The next big story in global aluminum is whether Chinese firms start developing overseas, particularly in Indonesia and Vietnam,” Wang said, noting that Indonesian advocates he’d spoken to feared that the facilities would use coal. “With aluminum capacity in China capped, where is the industry spilling over into?”
Rising demand globally for lower-carbon products is spurring on Chinese industry. That’s particularly true now that the European Union’s carbon tariff — the first in the world — took effect in January. Brussels is considering establishing a way to selectively exempt industries from the levies. But the bloc has so far vowed to keep requiring importers to buy carbon certificates to offset the emissions produced during manufacturing.
The China Nonferrous Metals Industry Association rolled out updated rules last year for the certification and trading of “green electricity aluminum,” in a move Shen said was “intended to ensure that low-carbon aluminum carries recognized commercial value in the market, rather than being merely a reporting label.”
Last summer, a Chinese steelmaker scheduled its debut shipment of green steel to a buyer in Italy, carving out the start of a supply chain that would comply with the EU’s carbon tariff. In November, top steel trade associations in Europe and China agreed to work together to create uniform standards for what qualifies as green.
If China’s experience with solar panels and batteries — in which its efforts to meet domestic demand led to a flood of cheap exports — is any indicator, the global market could soon have an influx of green aluminum.
When rockets blast off Earth, they rely on tiny metal powders to help propel them into space. Now, an emerging group of startups and scientists is hoping to harness these particles for something more terrestrial: producing carbon-free energy for factories.
Powdered iron can be combusted in industrial boilers to supply the hot water and steam needed to produce everything from beer and baby formula to paper and plastic resins — without directly emitting carbon dioxide. The concept is about a decade old, but companies are just starting to make serious inroads to put the technology into practice.
Last week, the Dutch startup Renewable Iron Fuel Technology, or Rift, said it raised almost 114 million euros ($131 million) in private financing and public grants to develop its first commercial project, making it a front-runner in the space. Rift already operates two pilot units in the Netherlands. With the new investment, the firm plans to build a fuel-production plant and deploy its boilers in about 10 industrial facilities in Europe, the first of which is set to fire up in 2029.
“This represents a concrete step toward decarbonizing industrial heat at scale,” said Mark Verhagen, CEO of the Eindhoven-based Rift.
Around the world, most factories burn fossil fuels to get the heat they need for industrial processes, which is why the sector accounts for more than one-third of energy-related CO2 pollution globally. Rift estimates that its current system can reduce emissions by almost 80%, on a life-cycle basis, when compared with those of a fossil-gas-fired boiler.
The startup is seeking to scale at a pressing time in the European Union, where manufacturers are facing tighter restrictions on emissions and new policies aimed at shifting factories toward cleaner heat sources. The region is also grappling with ballooning gas prices caused by Russia’s 2022 invasion of Ukraine — and now the U.S. and Israel’s war on Iran.
Rift’s approach replaces gas with iron, a highly energy-dense and abundant element that is ground down to resemble sand.
The startup begins by putting iron powder in a specialized boiler, then injecting air and making a little spark that yields a big flame. As the iron burns, it produces heat that can be used directly for manufacturing or district-heating networks. To start, Rift is focused on supplying medium-temperature heat, of around 250 degrees Celsius (482 degrees Fahrenheit).
“The only product that remains are the ashes,” Verhagen said.
Rift will initially use a small amount of virgin iron powder, sourced from industrial suppliers. But the goal is to continually recycle the ashes — which are pure iron oxide — to make new fuel. When combined with low-carbon hydrogen, iron oxide splits into water and iron powder, the latter of which will be returned to the boiler.
As a technology, iron fuel has plenty of hurdles to overcome before it can replace gas in factories. Researchers are still improving the iron-combustion process and the techniques for collecting iron oxide. Companies need to build up supply chains for sourcing and recycling iron powder. And using green hydrogen — the kind made with renewable energy — for fuel production remains challenging, given that supplies are limited and costly.
Developers also need to bring down their production costs in order to compete with the incumbent fossil fuels. Rift, for its part, is working to improve its economic performance with the buildout of its first commercial project, Verhagen noted. The company says it can currently deliver iron fuel for a price of 140 euros per metric ton.
The investment round announced on March 3 includes more than 83 million euros in Series B funding, led by the Dutch pension fund PGGM, as well as a grant of nearly 31 million euros from the EU’s Innovation Fund. Rift had previously raised 11 million euros from investors in 2024, which enabled it to conduct durability tests at its two pilot projects.
“We have closely followed Rift’s development and see strong potential for tangible industrial impact,” Tim van den Brule, investment director at PGGM Infrastructure, said in a press release. “Many industrial innovations stall in the transition from demonstration to realization,” he added, which is why the firm is providing Rift with capital “through to execution.”
Rift is not alone in this fledgling field. Other players include the Dutch startup Iron+ and the Canadian firms Altiro Energy, FeX Energy, and GH Power, along with Ferron Energy in Australia and Fenix Energy in France.
The companies can all trace their roots to early research efforts led by Philip de Goey from Eindhoven University of Technology and Jeff Bergthorson from Montreal’s McGill University. The professors were inspired to pursue metal fuels for energy purposes after observing how powders burned at the European Space Research and Technology Centre in the Netherlands. In particular, they saw iron powder as an appealing alternative to gaseous hydrogen fuel — which has been held up as a more direct replacement for fossil gas but is difficult to store and transport.
In 2020, Eindhoven researchers and students, including Verhagen, built their first 100-kilowatt iron fuel boiler at a nearby brewery. That year, Rift spun out of the student team, with support from the Bill Gates–led Breakthrough Energy Fellows program. The startup later launched a 1-megawatt system that provides heating to some 500 homes in the Dutch city of Helmond; it operates another pilot unit at a cleantech park in Arnhem.
In 2025, Rift signed its first customer contract with the Dutch firm Kingspan Unidek, which makes building insulation and plans to install an iron-fueled boiler at one of its plants.
Verhagen said that, as well as with slotting into existing operations like Kingspan’s, the technology could also work alongside other types of clean-heat solutions that are gaining momentum globally, such as thermal batteries, which store electricity to provide on-demand heat, and highly efficient industrial heat pumps.
Iron fuel could serve as the “baseload” source that supplements electrified technologies, or that kicks in when electricity prices are high or otherwise constrained. “We see that there’s a unique fit” for Rift’s system, he said.
Green-steel startup Boston Metal has suffered a major setback following an industrial accident at its facility in Brazil.
The Massachusetts-based company announced it will lay off 71 people in the U.S. after the incident at its Brazilian plant last month thwarted a key funding deal, Boston Business Journal first reported. The turn of events was “sudden, dramatic, and unexpected,” company sources told the news outlet.
Boston Metal is among the handful of well-funded startups advancing newer and cleaner ways of making steel — a process that traditionally relies on polluting, coal-fueled furnaces. Since spinning out of MIT in 2013, the company has raised over $400 million from a range of investors, including global steel giant ArcelorMittal, the venture-capital arm of oil giant Saudi Aramco, and Microsoft’s Climate Innovation Fund.
On Jan. 30, Boston Metal experienced an “unforeseen critical equipment failure” in its manufacturing facility in Brazil, the company told Canary Media in a statement on Monday. Although the incident was “fully contained, with no injuries or environmental impact,” the equipment damage prevented Boston Metal from hitting an operational milestone that was tied to a pending financing transaction.
“As a result, we lost access to committed capital essential to supporting our operations in both Brazil and the U.S.,” the company said, forcing the need to reduce its American workforce. Before the accident, Boston Metal employed over 300 professionals in the United States and Brazil.
Globally, steel production accounts for between 7% and 9% of human-caused greenhouse gas emissions. The bulk of that pollution comes from heating coal to transform iron ore into iron, which is turned into higher-strength steel in a separate furnace. While companies like Stegra and SSAB, both in Sweden, are looking to replace coal with green hydrogen in the ironmaking stage, Boston Metal is attempting to reinvent this process entirely.
The startup is developing a novel approach called “molten oxide electrolysis,” which involves using electric current to heat iron ore to around 1,600 degrees Celsius to drive chemical reactions, without emitting any carbon dioxide. The resulting material then cools into blocks of steel.
Last March, Boston Metal said it had moved one step closer to commercializing its technology after successfully producing steel from its industrial-size system in the Boston suburb of Woburn. The accomplishment “de-risks our technology and validates scalability to achieve commercial production,” the company said in a press release.
Yet as Boston Metal works to refine its green-steel system, it has also been pursuing projects in Brazil that it hopes could become a reliable source of revenue in the nearer term.
Boston Metal’s same molten oxide electrolysis process can be used to extract high-value metals such as niobium, chromium, and manganese from mine-waste tailings. That could reduce the need for other companies to pull those materials directly from the earth.
Adam Rauwerdink, Boston Metal’s senior vice president of business development, told Canary Media last June that the company was initially focusing on extracting and selling niobium — a valuable alloying element used in steel production — to start bringing in money. At the time, niobium sold for about $82 per kilogram (about $74,000 per ton), while steel went for roughly $900 per ton.
Prior to last month’s accident, Boston Metal said it had already restructured its business to concentrate on advancing its operations in critical metals. “There is strong near-term demand for critical metals, while the cost and complexity of developing molten oxide electrolysis [for steel] have outpaced what our current revenue and available capital can support,” the company said in this week’s statement.
Boston Metal’s Brazilian subsidiary, Boston Metal do Brasil, built and began operating a pilot facility in the state of Minas Gerais in 2023. Last year, it completed construction on an industrial critical-metals plant, and the subsidiary was set to start “generating revenue with industrial-scale production” this year, according to a company fact sheet.
Though Boston Metal says it will press ahead with its high-value metals strategy, it’s unclear how the industrial accident in Brazil will affect that production timeline or impact Boston Metal’s broader expansion plans in the United States. The announcement of layoffs in Massachusetts comes shortly after the office of Democratic Gov. Maura Healey awarded Boston Metal over $950,000 in capital grants to upgrade its Woburn operations — public backing that was reportedly expected to lead to local job growth.
“In the coming months, our priority will be restoring operations in Brazil and scaling the critical metals business in Brazil, the U.S., and internationally,” the company said.
Form Energy invented a novel iron-air battery to store clean energy for much longer timeframes than conventional lithium-ion batteries can. The startup is still constructing its first commercial project, in Minnesota, but today revealed it has clinched a potentially game-changing follow-up in the same state to support a Google data center.
The utility Xcel Energy will install 300 megawatts of Form’s batteries in Pine Island, Minnesota. It’s a big battery installation for the Midwest, but developers have built several grid storage plants elsewhere with more megawatt capacity. What shoots this project into the energy-storage stratosphere is that it will dispatch energy for up to 100 hours straight — enough to pump clean energy through multiday weather patterns that would limit renewable production. That unique capability means the Pine Island Form plant, fully charged, will hold 30 gigawatt-hours of energy, an astonishing amount for the grid as we know it.
The deal is also notable in that it proves Form has found commercial traction even before its first installation for a utility customer is complete. That outcome was possible because Xcel has seen Form develop its technology for years, said Form CEO Mateo Jaramillo, who co-founded the firm in 2017.
“Xcel in particular has been with us through every step of the journey — when the chemistry was in a very small bucket, essentially, to complete deployed systems,” Jaramillo said. “They saw the challenging things that we worked through. They saw us solve hard problems. They saw us come out the other side.”
The arrangement also offers one of the clearest examples yet of how tech giants could power their data centers with clean energy without raising costs for regular customers, if those companies care to try.
Under the agreement, Google will pay Xcel to build 1.4 gigawatts of wind and 200 megawatts of solar. Those resources make cheap, clean power, but they can’t match a data center’s 24/7 operating profile. That’s where the Form batteries come in: They can charge up whenever renewable production exceeds momentary demand and then deliver on-demand power for more than four days.
For anyone still concerned about climate change, that’s an enticing vision at a time when the titans of AI seem happy to toss clean energy out the window. Amazon and Meta have readily endorsed major fossil-gas-plant construction to power their AI sites. Just this week, SoftBank subsidiary SB Energy, which has been an avid clean energy developer, teamed up with the Trump White House to propose the biggest fossil-gas power plant in the world to help fuel the AI computing build-out. Other companies have turned to less efficient, smaller-scale fossil-fueled generators to hack together enough power for their data center plans, as chronicled by analyst Michael Thomas.
Xcel, which provides electricity to nearly 4 million people across eight states, also took great care in its statement to describe the data center not as serving the general AI arms race, but as one that “will support core services — including Workspace, Search, YouTube and Maps — that people, communities and businesses use every day.”
The companies also took steps to protect Xcel’s other customers from price impacts to serve the data center: “Google will cover any new grid infrastructure costs associated with the project and has planned carefully with Xcel Energy to ensure electricity in the area remains reliable and affordable for all of Xcel Energy’s customers,” the utility noted.
This arrangement lets Xcel pitch the data center as something that actually helps the broader Minnesota community: It will bring investment, construction jobs, and higher clean-energy generation — all without increasing electricity bills at a time when they’re rising fast in much of the country.
Potentially transformative new battery technologies tend to get trapped in yearslong cycles of small-scale pilots and demonstrations, before utilities feel comfortable spending their customers’ dollars on the new thing. Some caution is warranted, as far more novel battery startups have gone bankrupt than have built at multi-megawatt scale. And again, even Form has yet to finish its first commercial installation.
In this case, however, Google is picking up the (still undisclosed) bill. If the batteries don’t work as advertised, that could frustrate Google’s carbon accounting, but Xcel customers would not be on the hook.
Form demonstrated its capabilities with internal installations that Xcel could examine, Jaramillo noted. The startup has also been honing its production quality at its factory in the former steel town of Weirton, West Virginia — a process that required making 60 miles of electrode materials, he noted.
“They don’t treat us like mom and give us cookies when we feel bad — they hold us to a very high standard,” Jaramillo said of Xcel. “And we want them to feel good about the product, that it’s safe, that it’s reliable, that it scales.”
Form expects to start delivering batteries to the utility in 2028. That year, the Weirton factory is supposed to reach 500 megawatts of annual production capacity, so the Pine Island project will represent a major share of Form’s manufacturing operations. Xcel expects the clean energy installations to come online in phases from 2028 to 2031.
Meanwhile, its initial project in Minnesota — which was supposed to come online in 2023 — is now set to finish installation this year.
The nascent long-duration storage sector has needed eager patrons to give the technology a shot. Form clinched its first, much smaller contracts with vertically integrated utilities that could take a more holistic long-term planning view than the fast-paced competitive power markets allow for. Now, the data center build-out brings potential customers with mountains of cash and a burning desire to move quickly — an ideal pairing for Form, which has a factory and a need to prove its worth
An update was made on Feb. 25, 2026: New information about Xcel Energy’s timeline for building the clean energy projects was added.
With utility bills rising fast, an increasing number of states are looking to virtual power plants as a potential solution.
As of last year, 34 states have programs that call on utilities to use smart thermostats and water heaters, batteries and EV chargers, and energy management systems at businesses and factories to combat rising electricity rates.
A dozen states are considering legislation this year that could launch or expand VPPs, including Michigan, Minnesota, New Jersey, and Pennsylvania. Similar bills passed in Illinois and Virginia in 2025 and in Maryland and Colorado in 2024.
The thesis behind these policy pushes is straightforward. Utilities can’t build new power plants or expand and upgrade their grids quickly enough to meet fast-growing electricity demand. Building out that infrastructure is one of the biggest drivers of rising utility rates, though not the only one.
Paying customers to lower their power use or share electrons they’re generating or storing could be a faster and cheaper solution. That approach could reduce the need to build and run expensive peaker power plants — or help avoid or defer costly grid upgrades to serve those peaks — and curb rate increases for all customers, not just those being reimbursed to supply it.
“People think about their neighbor who put solar on their roof to save on their own electricity bills,” said Mary Rafferty, executive director of Common Charge, a coalition that promotes VPPs. “But if we can collectively aggregate all the sources of power from homes and businesses, everybody gets the benefits of building out a more affordable grid.”
And they’re already working. Collections of these customer-based resources currently provide hundreds of megawatts of capacity in California, Texas, New England, and Puerto Rico, matching the scale of large power plants, if not the full spectrum of roles they provide.
The trick is establishing programs that can deliver those widespread benefits in a way that makes utilities and regulators comfortable.
Right now, most of the country’s VPP capacity is concentrated in old-school “demand response” programs that pay big power users to reduce their electricity use during grid emergencies. This tried-and-true approach has seen success, but it also faces limits in combating the broader cost pressures driving up utility bills.
There is far more potential in tapping the distributed energy resources, or DERs, that people are buying anyway. The U.S. Department of Energy has calculated that the country could achieve 80 to 160 gigawatts of VPP capacity by 2030, roughly three to five times what’s out there today, from these “demand side” resources. That could save utility customers about $10 billion in annual grid costs.
Jigar Shah, the longtime clean-energy entrepreneur who led the Biden-era DOE office that produced that analysis, has since made VPPs a focus of his advocacy work at groups like Deploy Action and the VPP Convergence Project, and in his relentless podcasting and social media messaging. In Shah’s telling, the argument for more VPPs can be summed up in a basic equation: the volume of electricity sales across utility grids divided by the cost of keeping that grid going.
Simply put, utilities must recover enough money from customers to pay off the costs of delivering power. That means “utility rates are determined by how much investments [utilities] make, which is the numerator, and how many kilowatt-hours they sell, which is the denominator,” he told Canary Media. “You want the numerator to be smaller, and you want the denominator to be bigger.”
Virtual power plants can rebalance that equation in customers’ favor, by bringing new energy users online at lower cost than what utilities would otherwise spend. “If you can reduce the numerator some — you can’t get rid of all of it — and you can increase the denominator by bringing load online faster, you lower rates.”
Along with the high cost of building new power plants and expanding and maintaining poles, wires, transformers, and substations, utilities face additional costs and bottlenecks in getting additional sources of electricity online. Gas turbine manufacturers are backlogged through the end of this decade, and the cost of gas power plants has grown significantly over the past few years. Meanwhile, solar and wind are constrained by both a too-small transmission grid and Trump administration policies.
In short: It’s hard for utilities to get the power they want right now at any cost, and VPPs can help.
In fact, the need to connect more customers to the grid is the most immediate pressure driving utilities to revisit VPPs, Shah said.
The artificial intelligence boom has put the limitations of the existing grid into sharp focus. Prospective data centers are being told there’s not enough gigawatts to serve them, even as the cost of expanding future capacity to meet their demands is pushing up rates in data center hot spots. But the fundamental issues are not new. The same constraints have made it hard for EV charging depots and other power-hungry customers to get connected in other parts of the country, he noted.
“Utilities are responsible for economic development in their regions. And they’ve been failing to support economic development, because interconnection timelines have been a lot longer than they want them to be,” Shah said.
Utilities have long been uneasy about relying on customer devices they don’t directly control. The biggest VPPs in the country remain tied to providing emergency grid relief, rather than being included in long-term plans that would allow them to serve as an alternative to building new power plants or updating the grid. Most of the regulatory and legislative directives pushing utilities to use VPPs are taking an incremental approach — launching pilot projects, testing their capabilities, and then scaling up over time.
But as Shah pointed out, utilities have had more than a decade of experience with DERs to build on. “All that piloting we’ve done since 2012 is ready for prime time.”
Residential VPP capacity tends to start with smart thermostats and controllable air conditioning and electric heating that can be modulated to reduce peak-power stresses. This may leave people feeling hotter or colder than they’d like. But energy-efficiency improvements and smart precooling or preheating strategies can minimize those impacts — and appropriate payments can make the discomfort worth it. Meanwhile, some appliances, like water heaters, can be turned off without people noticing, as long as they’re not turned off for too long.
Solar systems, batteries, and EVs bring something more to the table: the potential to generate and store power that can go back to the grid. Solar-battery VPPs from companies like Tesla and Sunrun, or “bring-your-own battery” programs managed by utilities, are providing big boosts to grids in Puerto Rico and states including California and Vermont. And “managed charging” programs for EVs are a key tool for utilities to turn a potential grid stress into a grid asset — or even to tap EV batteries in “vehicle-to-grid” programs.
Traditionally, utilities have managed these technologies separately and slowly scaled them up. It’s also important to remember that investor-owned utilities earn guaranteed profits for investments in power plants and grids, which disincentivizes them from pushing hard on alternatives that might erode those profits — including VPPs.
But with energy affordability now driving big political pushback in Virginia, New Jersey, and other states, VPP advocates argue that it’s time to move fast — and that state lawmakers can set the terms for making that happen.
“We’re looking at legislation as an opportunity to ensure that the virtual power plants are robust,” said Chloe Holden, a senior principal at Advanced Energy United, a clean energy trade group. “For us, that means they have multiple DER types, they leverage traditional demand response, they often have goals attached to them in terms of scale and timelines that we think are achievable but ambitious — and that they are set up to compensate DERs for a number of different grid services, and that those grid services expand over time.”
To be clear, utility cost pressures have been building for decades, and VPPs won’t offer immediate — or complete — relief, she said. But the traditional approach of adding more poles, wires, and power plants is what’s causing costs to rise in the first place.
“This is really the first opportunity that legislators and utility regulators have had to make us build in a more affordable way,” she said. “It used to be true that all utility infrastructure was seen as necessary to control peak load, and that peak load was something we didn’t have any control over. That’s no longer the case.”
Lauren Phillips’ balcony just became a power plant. A very small, carbon-free one.
A few weeks ago, the attorney set up what may be the first plug-and-play solar panel in the Bronx. The 220-watt installation, which is secured to the balcony railing with zip ties, has been a boon for the co-op apartment owner and mother of two.
“I have an enormous childcare bill every month. My electricity bills never go anything but up,” Phillips said. “Everywhere you turn, things are only getting more expensive.”
Plug-in solar nonprofit Bright Saver, which provided the roughly $400 panel to Phillips at no cost, estimated that it will produce about 15% to 20% of the electricity her family uses and save her about $100 per year. Every time Phillips gazes at the device, she said, she’s amazed that “this is just a thing that I plugged in, and I’m generating my own power.”
Phillips is one of the few intrepid Americans installing DIY solar without the permission of their utilities, taking advantage of a regulatory gray area. Only deep-red Utah has a law, passed in March 2025, that explicitly allows residents to plug in these devices. A few thousand households there have installed systems so far, Bright Saver said.
But other states, including New York, could soon follow Utah’s lead and unleash much broader adoption of solar panels that plug into a standard 120-volt wall outlet. As of Wednesday, Democratic and Republican lawmakers in 28 states and Washington, D.C., have announced their own legislation to make these systems permissible, according to Bright Saver and other sources.
As utility bills climb and contribute to broader cost-of-living challenges across the United States, legislators see the portable tech as an affordability tool. It literally empowers people, said New York Assemblymember Emily Gallagher, a Democrat who in September introduced a bill to pave the way for small-scale solar.
“People are extremely enthusiastic about it,” noted Gallagher, a renter who longs for a plug-in system of her own.
An 800-watt unit that costs $1,099 is capable of powering a fridge or a few small appliances for a sunny fraction of the day. That’s enough power to reduce bills for a New York household by $279 per year on average, Gallagher said. Assuming utility costs continue to rise, those savings could increase to $327 per year by 2035.
Plug-in solar is already booming in Europe. As many as 4 million households in Germany have installed the systems, which people can order through Ikea.
But in the U.S., outside of Utah, the tech is stuck in regulatory limbo. While the systems aren’t illegal, utilities often require users to sign an interconnection agreement before plugging in solar — just as they would for a large rooftop array. And those agreements can require fees and take weeks to months to get.
Utah did away with that interconnection requirement, so long as a nationally recognized testing laboratory certifies the solar device is safe to use. All the other legislation introduced since would do the same.
“The technology has evolved, and the law hasn’t caught up yet,” Phillips said. Putting up her own system might be “an act of solar civil disobedience,” she mused.
UL Solutions launched an initial testing protocol in January, which a panel of experts will refine in the coming months, according to Bernadette Del Chiaro, senior vice president for California of the nonprofit Environmental Working Group and former executive director of trade group California Solar and Storage Association.
There’s a real hunger for plug-in solar, said Cora Stryker, co-founder of Bright Saver. Momentum for these devices is growing faster than she expected.
Some zealous legislators announced bills out of the blue, Stryker noted. A few chambers even saw multiple lawmakers introduce plug-in solar bills independently of each other.
Missouri state Rep. Mark Matthiesen, a Republican, sponsored a DIY solar bill in December. Electricity rates are climbing fast in his state; families who get a system could save $30 to $40 per month and break even in as little as 25 months, he said.
“Then, everything beyond that is money back in your pocket,” said Matthiesen, who got rooftop solar panels in 2024. “If people can buy something to invest in themselves, to save them money down the road, then we as a government just need to let people do that.”
Matthiesen heard about plug-in systems last year from fellow legislators when they met up at the site formerly known as the National Renewable Energy Laboratory in Golden, Colorado. As for South Carolina state Rep. Mike Burns, another Republican who recently introduced a balcony solar bill, it was a passionate constituent who tipped him off.
A few proposals, including those in Missouri, Washington state, and Wyoming, have stalled. Some utilities have opposed legislation for permissionless systems, saying there are safety risks, including from energy being fed back to the grid and potentially overwhelming its capacity.
Advocates, however, say that this argument ignores the physics of electricity. Because these are modest systems, which proposals generally cap at a size of 1,200 watts (that’s up to a sixth the size of the typical rooftop array), a home’s appliances will quickly gobble up the power they produce, according to Del Chiaro. Very little, if any, energy will flow back onto the distribution grid.
Balcony solar bills in New Hampshire, Vermont, New Jersey, and Illinois look on track to pass, according to Stryker. A proposal in California — a potentially massive market as the state with the second-highest electricity prices and largest state economy in the nation — is in committee. Stryker anticipates that still more lawmakers will announce legislation for the up-and-coming tech this year.
For Phillips, balcony solar is more than a means to save money; it’s a step toward a healthier future. She’s a third-generation native of the Bronx, an area disproportionately burdened by noxious pollutants.
“I was actually hospitalized with an asthma attack last year,” Phillips said. “For me, anything that we can do to green our power grid, to reduce pollution, is a matter of justice — especially for people who live where I live.”
Phillips has been talking to friends and family about her mini power plant. “Everybody wants one,” she said. States simply need to pass their portable solar bills to open the floodgates, Phillips noted.
“I can’t wait to see solar panels peeking out of everyone’s balcony.”
A correction was made on Feb. 26, 2026: This story originally misstated that Lauren Phillips is a renter. She has a co-op apartment. An update was also made on Feb. 26 to include legislation in Georgia, increasing the number of states from 27 to 28.
One of the world’s largest steelmakers has deployed a novel heat battery at its plant in India to curb emissions from its dirty, energy-intensive operations.
Tata Steel is using the 20-megawatt-hour thermal-storage system, developed by the German startup Kraftblock, at a massive steel mill in Jamshedpur, in the eastern state of Jharkhand. The technology captures waste heat that’s generated during an early stage of the steelmaking process, then repurposes that heat to replace fossil gas used within the plant.
On Friday, the companies announced the project for the first time and shared the initial results. Kraftblock has been operating the heat battery since last May as part of a one-year test run with Tata Steel.
Based on how well the system has performed so far, the cleantech firm expects its thermal-storage technology will reduce the site’s carbon dioxide emissions by 22,000 metric tons per year — about the same as taking 5,100 gas-fueled cars off the road — and will eliminate about 110 gigawatt-hours of fossil-gas use per year.
“It’s performing better than we calculated,” Martin Schichtel, Kraftblock’s CEO and co-founder, told Canary Media.
The project is likely the first of its kind within the steel industry, experts say. But manufacturers in other industrial sectors are increasingly testing out thermal-storage technology as they look for cleaner ways to produce the scorching heat they need to make ceramics, chemicals, dairy products, and processed food and drinks.
Some of these systems draw electricity from the grid to generate and store heat in specialized bricks, rocks, or salt. They then supply that heat to industrial furnaces and boilers whenever companies need it. Kraftblock, which launched in 2014, operates a system like this at a PepsiCo factory in the Netherlands, where heat batteries are used instead of fossil gas to deliver steam and hot oil for frying potato chips. The company has developed a “stonelike” storage material from byproducts such as steel slag and copper-mine waste, Schichtel said.
Kraftblock’s system in India charges up using the excess heat from industrial processes, not electricity. Schichtel said that hard-to-decarbonize sectors like steelmaking have a “huge” potential to harness more of their waste heat, which is typically just lost to the air.
At the Tata Steel site, two Kraftblock units are connected to the “sinter” plant by a maze of thick silver pipes. Sintering is a highly energy-intensive process in which iron ore, limestone, and other materials are heated together to make lumps that are fed into blast furnaces — the hulking coal-fueled facilities that produce iron, the main ingredient in steel.
Tata Steel primarily uses fossil gas to generate heat to make the sinter, and later runs the finished product through large circular equipment to cool it back down. Kraftblock’s technology gathers the thermal energy that the cooled-off sinter releases and stores it in the batteries — at up to 500 degrees Celsius (932 degrees Fahrenheit). Tata Steel can then tap those batteries to warm the water needed for the sintering process.
Kraftblock’s system “enables us to significantly reduce our fossil energy consumption and emissions while improving process efficiency,” Subodh Pandey, Tata Steel’s vice president of technology, R&D, new materials business, and graphene, said in a statement to Canary Media. “This project is a significant step towards a greener, more energy and cost-efficient steel industry.”
Kraftblock declined to say how much its 20-MWh system cost to build or operate. But Schichtel said the project was developed without any subsidies, a fact that reflects the growing regulatory pressure facing Indian steelmakers. India is set to launch a carbon-credit trading scheme this year, and the European Union recently enacted a carbon-border tariff on polluting imports, which applies to metal from India.
Such policies are “definitely supportive” of clean technologies like Kraftblock’s, Schichtel said.
Globally, steelmaking accounts for between 7% and 9% of human-caused greenhouse gas emissions. Most of that pollution comes from heating coal in blast furnaces — a chemical process that can’t be directly replaced with thermal-storage systems. Steelmakers are pursuing other low-carbon methods instead, including producing iron using green hydrogen or with novel electrochemical processes.
Tata Steel, for its part, recently announced plans to invest $1.2 billion in advanced technologies at its Jamshedpur plant that are designed to reduce coal use in the ironmaking process and will capture carbon emissions from the steel mill.
Still, heat batteries like Kraftblock’s could provide a key way for steelmakers to start cleaning up their existing facilities today, even as they work to solve the much harder, longer-term challenge of fully decarbonizing, said Kaitlyn Ramirez, a senior associate in the Climate-Aligned Industries Program at RMI, a clean energy think tank.
Curbing steelmakers’ energy use is especially crucial, given how much renewable power cleaner steel mills are expected to need for steps like producing green hydrogen and operating electricity-driven furnaces and reactors. “Every amount of energy that we can reduce or make more efficient … makes the ultimate transition to near-zero [steel] production easier and much more feasible in the near term,” Ramirez said.
Kraftblock is part of the climatetech accelerator Third Derivative, run by RMI. The startup joined last year’s “industrial innovation cohort,” along with other industrial-heat-focused companies such as Advanced Thermovoltaic Systems, HyperHeat, and Noc Energy.
Nick Yavorsky, a senior associate at RMI who works with Third Derivative cohorts, said his team thought that Kraftblock was “on a very successful commercial pathway.” The startup had already raised 20 million euros ($23.6 million) in Series B financing when it joined the accelerator, and it had already deployed its thermal-storage technology at the Netherlands PepsiCo plant and at a ceramic manufacturing facility in Germany.
The Tata Steel project is “kind of a beacon” for thermal-storage startups looking to break into the steel sector, Yavorsky said. He added that he sees significant potential for scaling Kraftblock’s technology. Beyond the carbon-intensive blast furnace, steelmaking involves over a dozen upstream and downstream processes that require lots of energy and generate plenty of heat.
Worldwide, steelmakers operate over 480 integrated iron- and steelmaking facilities, according to Global Energy Monitor. India’s steel sector is growing particularly fast, and much of that new capacity is still expected to rely heavily on coal, underscoring the need to slash steel-related emissions wherever possible.
Schichtel said that Kraftblock and Tata Steel could consider expanding the heat-battery project after the full year of operations. He noted that the startup’s technology can store and manage heat up to 1,300 degrees Celsius (2,372 degrees Fahrenheit) — much higher than the sinter plant requires — which enables its technology to harness waste heat from a wide range of industrial processes.
“Not all steel mills will convert to hydrogen [ironmaking] within the next five or 10 years, right?” he said. “So each step you can do to minimize emissions, to increase energy efficiency for existing systems, is highly value-added.”
A correction was made on March 2, 2026: This story originally said that Third Derivative was run by RMI and New Energy Nexus. While New Energy Nexus co-founded Third Derivative, it is now run solely by RMI.
Hi everyone and welcome. My name is Matias Sundine. I am the editor-in-chief of Warp News and the founder of Warp Institute, a foundation I started a few years ago. Warp Institute is part of Project Energy Society, and the goal there is to use the logic from how the internet is built and apply that to the energy system, the energy grid. This means you will end up with an abundance of energy, and not just any energy, but clean green energy. We think that will really shift the mindset of humanity because we are, of course, super dependent on energy. We have always been and we still are, because it is expensive or damaging to the planet. But that is changing now with technology.
If you put these things together and, as I said, borrow the logic from the internet, we think we can get to an abundance of energy. When you have an abundance of energy, when you do not have to think about the last drop of energy and how we are going to use it, that would shift how we think about things and the things we do. We will do many new things that we thought would be unimaginable today. The leader of this project is Yunas Spirishon and he and his team in Lund have been working on this. I heard this idea from Yunas three years ago and immediately understood this was really something, because when you have dropping costs on solar and batteries and all that, you see the components are already there but everything is getting less expensive. I immediately understood this was a really good idea and a really good theory, but so far it had been a theory. A good one, but still a theory. Now it is not a theory anymore. Recently in Lund, Yunas, you pushed a button and something happened.
Yes, exactly. Matias, thank you for having this call and thank you for supporting us over the last three years. We believe that Energy Society is really the next paradigm shift. This last Saturday we took a really important step because we now have the world’s first operational energy net, as we call it, between two different buildings. We have a freedom cable between them. They are two separate buildings owned by two different real estate companies. There is an office, some apartments, a gym, a lot of mobility spaces like parking spaces, and also a grocery store. They are connected with an independent parallel electrical grid, or as we call it, the freedom cable. There is an energy router in each building. There is solar and there are batteries on both sides, and they can now exchange electricity without paying for distribution, which today is the largest cost component of the Swedish electrical system and is planned to increase dramatically due to large investments in the traditional grid. Apart from the cable and the routers, we now also have the energy router operating system, or OS, because sharing energy is sharing love. It talks to the network management system, which then talks to the BSS OSS system. My company, via ROPA, is thrilled to become the world’s first Energyet operator, helping the real estate companies that make these investments not only with the project but also with running it daily, managing the system and the interactions between these local nodes and the traditional electrical grid. All the key components are here and we have verified them. Everything works and we are ready to start scaling this. One key aspect is exactly what you talked about, Matias: hyperscale. Everything we use is commercial off-the-shelf components. The critical thing that made this practical and financially viable is that the power electronics in the routers are the same components used in electric vehicles. These are the components that transfer energy from a charger to a car battery. They are price-effective and commercially available. By comparison, upgrading a transformer in the traditional Swedish grid can take five to seven years. If we are in a pinch and pay extra for transport, we can get these power electronic components in five to seven hours. The cost difference is about a thousand to one in distribution.
One story from the development team shows exactly what Warp News is about, the exponential development of hyperscale components. We started in the low-voltage space, which in the EU means one thousand volts and below, operating at 800 DC volts because that was the maximum of the components. During the process, a new generation of power electronics from chargers became available. Apparently, humans do not like to wait, so we now have 1500 volt DC components we can use. Even before serial production, the amount of energy we can transfer on the same freedom cable has basically doubled because we are on the right technical trajectory and price performance curve. As vehicles, chargers, buildings, neighborhoods, and cities adopt this, volumes increase and prices drop further. It is surprising that many people miss this. Battery costs have dropped 90 percent in ten years and will continue to drop as production increases.
If you compare this to the internet, we are at a stage similar to ARPANET. Instead of four university nodes, we have these two connected real estate nodes, but it is a full technology stack. The energy protocol is published, open, and free, just like IP. Anyone can build a compatible energy router. We believe hundreds or thousands of people should produce their own routers and let the best win. What is best varies. We can have diversity of vendors, local production, and independent energy systems that can still share resources with neighbors and larger networks without distribution cost if desired. In Sweden, which already has one of the best and cheapest grids in Europe, it is profitable to build this parallel architecture. If it works here, it should work in many places worldwide. In the US, more than 11,000 projects are waiting to connect to the traditional grid, which would double production, and 90 percent are wind, batteries, and solar because they are cheaper and easier. Energy net can also be built super robust. The traditional grid is too sensitive. With internet architecture applied to energy, there is no single point of failure. It becomes super resilient.
This has changed my thinking. At first, I saw abundance and positive effects. Today, with Russia’s war against Ukraine and geopolitical uncertainty, this project has become very important for security. Thousands of small networks are far more resilient than a centralized grid. Even if cut off, you still have some electricity, which makes a huge difference in crisis or war. It is important for Europe’s security and competitiveness.
Now that we are live with real deployments, the next step is to scale. Just as Sweden pioneered modern broadband and digital telephony by combining innovation with new infrastructure, we can break the gridlock in the traditional grid. Filling suitable Swedish roofs with solar could generate over 50 terawatt hours per year, while Sweden consumes about 150 terawatt hours annually. This clean, cheap, resilient local energy is market-paid, not subsidized. It frees capacity in the traditional grid for industrial and transportation transition. It is the cheapest, fastest, and most secure way to accelerate the green transition. If it works in Sweden, it can work even better in many other European grids and eventually worldwide with policy adaptations. Who does not love clean green energy that you can run independently in your backyard together with your neighbors?
If you want to follow developments in the Energy Society, we report on them regularly at Warp News. Sign up for our free newsletter at warpnews.org to receive updates once a week. Thank you very much, and thank you Yonas for chatting with us. Remember, Energy Society will be built by all of us together. Energyet is an open free standard and you can start building your own energy independence right now.
Factories that make essential materials like steel and cement need scorching-hot air and steam to transform raw ingredients into finished products. Traditionally, they get that heat by burning fossil fuels. But the startup Electrified Thermal Solutions is pursuing a far cleaner approach: tapping piles of bricks.
The Boston-based company has developed a thermal battery system that uses electricity to heat metal-oxide firebricks for hours at a time. The goal is to soak up wind and solar power from the grid during cheaper off-peak periods, then deliver the stored heat to industrial furnaces, boilers, and kilns whenever manufacturers need it.
Now, Electrified Thermal is putting its technology to the test. Last week, the MIT spin-off unveiled its first commercial-scale thermal battery at the Southwest Research Institute in San Antonio. Its Joule Hive system can store 20 megawatt-hours of heat at temperatures of up to 1,800 degrees Celsius (3,270 degrees Fahrenheit).
“That is hot enough to do the job of fossil fuels in virtually any application,” said Daniel Stack, Electrified Thermal’s CEO and co-founder. “We’re talking about making cement, steel, chemicals, and glass, but also things like potato chips, which need steam generation for food processing.”
From the outside, the Joule Hive heat battery resembles a truncated shipping container connected to pipes and wires. Its insulated steel walls enclose stacks of firebricks, which are charged up by running clean electricity directly through them. The thermal energy is then discharged by running air through the brick stacks that can be piped as hot gas directly into factories.
The unit in San Antonio will allow manufacturers to “kick the tires” to see how the system works, including for on-site testing of minerals drying and other materials processing, Stack said. Electrified Thermal is poised to start delivering its first units to customers’ facilities at the end of this year or in early 2027, he added.
The startup is also partnering with ArcelorMittal to test the thermal-storage technology at the steelmaker’s R&D facility in Spain, and the two are considering piloting the system at a steel plant, where it could potentially replace the fossil-gas heat that is used to shape and strengthen the metal. ArcelorMittal and other global industrial giants, including cement-maker Holcim and iron-ore producer Vale, have invested in the firm.
“Industry has taken notice, and they’ve been very engaged in adopting electrified heating into their processes to try and reduce [energy] costs and cut emissions,” Stack said.
Electrified Thermal is one of more than two dozen startups that are attempting to clean up heavy industries by harnessing thermal storage, using not just specialized bricks but also materials such as crushed rock, molten salt, and sand. By banking low-cost renewable power from the grid, the firms aim to deliver heat that’s even cheaper than fossil gas — a formidable challenge for projects in U.S. regions where gas is abundant and inexpensive.
Thermal storage “has rapidly become one of the fastest-growing areas of interest within emerging storage technologies,” said Yiyi Zhou, a clean energy specialist at BloombergNEF, who added that the approach “offers its strongest potential in long-duration, heat-linked applications,” like the ones that Electrified Thermal has focused on.
Startups in this fledgling sector raised about $200 million in venture capital in 2025 from about a dozen disclosed deals, according to the consultancy Cleantech Group. In 2024, the sector raised close to $300 million — a total that includes a $150 million investment in Antora Energy, a California-based company that uses graphite blocks to generate intense beams of heat.
Electrified Thermal, for its part, says it has raised over $23 million in private capital since launching in 2021.
“It’s an exciting space, just given the overall need for electrified solutions in the sectors that thermal-energy storage companies are working in,” said Zainab Gilani, a research associate focused on energy and power at Cleantech Group. “The problem is definitely immense.”
Industrial heat accounts for about one-fifth of the world’s energy consumption and contributes a significant share of planet-warming pollution globally. In the United States, direct heat use in factories is responsible for roughly 13% of the country’s energy-related carbon emissions.
About three-quarters of those U.S. thermal emissions are the result of low- and medium-temperature processes that produce everyday goods like milk, beer, toilet paper, and bleach. In many cases, electric versions of boilers, ovens, and dryers can already replace the fossil-fueled heating systems in those factories.
But higher temperatures are harder to achieve using electrified equipment, since the extreme conditions can quickly destroy their metallic wires and heating rods, Stack said. For startups like Electrified Thermal, the idea is to design systems that can provide “flame temperature” heat for decades before they need replacing, he added.
Only a handful of industrial-scale thermal storage systems have actually been installed to date worldwide, and many additional projects are needed to build up manufacturers’ confidence in this approach, Gilani said.
Rondo Energy, for example, began operating its first 100-megawatt-hour heat battery last October in a rather counterintuitive place: the oil fields of Kern County, California. The battery’s heat generates steam that is injected into oil wells to increase production, a job previously done by a gas-fired boiler. According to Rondo, the project is a necessary step that allows the startup to secure a paying customer as it scales the technology to decarbonize other industries.
Finding cost-effective projects in the U.S. is especially key now that the Trump administration has canceled hundreds of millions of dollars in Department of Energy awards for industrial decarbonization efforts. The defunded projects included ones that planned to use Rondo heat batteries: a plastics-recycling facility in Texas and beverage-production sites in Kentucky and Illinois.
Electrified Thermal, meanwhile, was set to supply its technology to the ISP Chemicals plant in Calvert City, Kentucky. In 2024, the manufacturer was selected for up to $35.2 million in federal grants to replace gas boilers with the thermal battery. But ISP Chemicals later withdrew from award negotiations, according to the DOE’s website, and Stack confirmed that the project is “halted at this time.”
Still, he said, Electrified Thermal remains focused on deploying its first large-scale projects this year and next, and aims to install 2 gigawatts of thermal power capacity by 2030.
The success of thermal storage projects will largely hinge on their ability to deliver heat that’s cheaper than fossil gas — and for that, they’ll need wider access to wholesale energy markets. In certain places, the price of wind and solar power can drop to zero or even be negative when supplies exceed electricity demand for hours at a time. But most industrial customers buy their power from utilities at retail rates, which excludes them from tapping that cheap clean electricity.
In Texas and Europe, however, companies can more readily access those ultralow rates, and tech providers are pushing utilities and regulators in more U.S. states to similarly open their wholesale markets to industrial users.
“Thermal batteries as an asset class are very new, and so the rules were not written with their existence in mind,” Stack said. “We would benefit from opening that market in more geographical areas of the United States.” This includes California, where renewables are so abundant that a large portion of that supply is curtailed when there’s not enough demand.
Stack called the deployment of that first unit in San Antonio a “pivotal moment” for the company. “We’ve turned on a system now that meets industry where they are, and can electrify them while saving them money on their heating bill,” he said. “And I don’t see anything that stops us from mass deployments.”
Tesla is rededicating itself to rooftop solar, a decade after it bought the then-leading company in that sector, SolarCity.
The pioneering electric car maker has continued to sell rooftop solar through its energy division since the SolarCity acquisition. But the Solar Roof product — essentially roof tiles that generate energy and which was touted in 2016 as a reason for investors to approve the acquisition — never achieved the pacesetting status that Tesla’s Powerwall did for home storage or its Megapack did for large grid batteries.
On Thursday, a day after reporting year-end earnings for 2025, Tesla unveiled its newest energy product during an event at the company’s retrofuturist Tesla Diner in Los Angeles. And the buzzy new item is, in fact, a rooftop solar panel, launched at a tumultuous moment for both Tesla and the residential solar market.
“This is the first time that we’ve actually fully designed and manufactured our own solar panel, aside from everything that we’ve been doing on the Solar Roof,” said Colby Hastings, who runs the residential energy business at Tesla Energy. “This is available now. This is very real-world.”
Tesla has already begun manufacturing the new panel at its factory in Buffalo, New York, where it built a line capable of more than 300 megawatts of annual production, with room to grow, Hastings said. Tesla also assembles the Solar Roof at that location.
The new design offers “superior aesthetics,” Hastings said, thanks to its low-profile, all-black appearance, with no visible bus ribbon needed to conduct electricity from the cells. Tesla also leaned on its dataset of 500,000 solar installations performed by its in-house teams, Hastings said, to streamline the parts needed to secure the modules to a roof. For instance, the new panel cuts out the rail architecture typically used to fasten panels.
“We’re always looking for ways to eliminate unnecessary pieces and improve time,” Hastings said.
On Wednesday, Tesla reported a drop in revenue (its first full-year revenue drop), vehicle deliveries, and gross profit for the full year 2025. Perhaps the company’s most surprising announcement, though, was that it plans to scrap production of its Model S and Model X cars and instead use those factories to manufacture bipedal automatons. (The solar panels, however, will still be “proudly made on Earth by humans,” per company materials.)
While Tesla’s core business suffered last year, its energy division shone brightly — as automotive revenues fell by 10% for the year, “energy generation and storage revenue” grew by 27%, though the division still makes far less money than its core business. The company deployed an immense 46.7 gigawatt-hours of storage in 2025, more than 10 times the rate just four years prior. But while Tesla freely discloses battery capacity delivered by its generation and storage business, it does not share solar capacity deployed, making it hard to gauge the significance of solar relative to energy storage.
As with Tesla’s vehicle sales, the rooftop solar market is experiencing a downturn. First California, the biggest residential market by far, overhauled the rules for solar compensation in a way that crushed sales. Then the Republican-backed budget law ended the federal tax credit for households that buy their own rooftop solar systems. However, that law kept a tax credit for systems leased by third parties.
Tesla launched a lease offer last year to monetize those remaining tax credits; customers can choose to buy out their systems after five years. As a U.S.-based domestic manufacturer, the company also should be able to claim the advanced manufacturing production credit (45X) for its production in Buffalo.
So in spite of the market turbulence, Tesla can still avail itself of supportive federal policies even though the budget law passed — over the protestations of CEO Elon Musk. But Tesla is far from alone in making solar panels in America these days: It will be competing against the likes of Qcells, the most prolific manufacturer of residential panels in the U.S., which operates more than 8 gigawatts of module capacity, compared with Tesla’s 300 megawatts.
Scale matters in this industry. Lacking that, Tesla does have an advantage: its connected ecosystem of home energy products.
“To my knowledge, we’re the only manufacturer out there that’s directly producing electric vehicles, charging, storage, mounting hardware, solar panels, all of the controls that you can use to integrate these devices and make them work together for your home, and one app to have that full experience in,” Hastings said.
That could be enough to carve out a profitable niche in what’s left of the U.S. rooftop solar market in the second Trump administration.
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