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Breaker boxes can be a hidden stumbling block for households looking to go electric. Many of these devices are too small to support the electrical needs of a home plus the addition of an EV charger, a heat pump, and other power-hungry appliances. But upgrading them can take lots of time and money.
Smart electrical panels — smartphone-controllable versions of the electromechanical devices found in most homes — could help solve this problem. While more expensive up front than the old-school gear they’re replacing, smart panels don’t require complicated utility upgrades — and they may be able to save homes and businesses money in the long run.
Leading smart-panel startup Span and major electrical-equipment manufacturer Eaton just announced a strategic partnership to try to boost adoption of the devices. Eaton will also make a $75 million investment in the San Francisco–based startup, which has now raised a total of nearly half a billion, including a $176 million Series C last month.
Eaton, which reported $27.4 billion in revenue last year, will tap its extensive distributor and installer networks to promote Span’s devices. These range from sleek, iPhone-shaped electrical panels aimed at high-end homes with complex electrical-management needs to devices designed for smaller homes, multifamily buildings, and small commercial properties.
Eaton also makes its own version of smart controls in the form of digital circuit breakers, which are the individual devices that plug into slots in standard electrical panels to prevent household circuits from overloading. Those AbleEdge devices are used in control systems from home battery vendors including Tesla and Lunar Energy, and are a core building block of Eaton’s “home as a grid” business strategy, Paul Ryan, vice president and general manager of the company’s energy transition business, told Canary Media.
“Homes are becoming more electrified. EV adoption continues to increase. That all puts a stress on the home and on the grid,” he said. “We have to manage our power more effectively.”
Homeowners who want to electrify may need to upgrade their electrical panels or pay for even more expensive utility-grid upgrades. Instead, smart panels and circuit breakers can actively shift and throttle appliances — like EV chargers and clothes dryers — to keep loads within safe limits, saving tens of thousands of dollars per home, Ryan said.
The smart panels can also generate savings if they’re used to manage the flow of power from rooftop solar panels, batteries, and backup generators on household circuits, he said. Currently, that job is performed using complicated combinations of traditional electrical gear.
These potential benefits have driven a wave of companies to invest in the sector. Along with Eaton and fellow electrical-equipment manufacturers Schneider Electric and Leviton, these include startups like Lumin and vendors of solar energy systems, batteries, and backup generators like FranklinWH, Generac, and Savant.
Span’s smart electrical panel was one of the first to hit the market in 2019, and the first to earn certification under the UL 3141 power control systems standard offered by Underwriters Laboratories, the premier standards-setting body for electrical equipment. Before Eaton, the company had also picked up partners including leading U.S. residential solar and battery installer Sunrun, utility smart meter and communications giant Landis+Gyr, and major U.S. homebuilder PulteGroup.
Span CEO Arch Rao told Canary Media that the startup will continue to operate independently while co-branding its smart panels under the Eaton label.
“They’ve come onboard not just as an investor but as a key partner for scaling our products in the market, particularly in the residential ecosystem,” Rao said. “We’re able to support electrification of all types of existing homes with main-panel replacement, subpanels, load controls, EV charging, and heat pump integration.”
Just as important, Ryan said, Eaton has “expansive manufacturing capabilities and a very strong supply chain. We’ll be collaborating together to help drive down the cost of these solutions and make it more affordable.”
That last point addresses the big question mark for smart panels and circuit breakers: cost. Span’s marquee smart panel retails for about $3,500, well above the $1,000 to $2,500 all-in cost of installing a traditional electrical panel.
In general, digitally enabled panels and circuit breakers cost roughly twice as much as old-fashioned electromechanical equipment does. The price differential has been a barrier to more widespread adoption of these kinds of products, which have already seen one major contender exit the market. Schneider Electric, the French electrical-equipment giant that competes with Eaton in global markets, recently discontinued its Schneider Pulse smart panel.
Other technologies could well offer a cheaper route to doing what smart electrical panels do, according to Ben Hertz-Shargel, global head of grid edge at research firm Wood Mackenzie. In a 2024 opinion piece, he highlighted options ranging from next-generation utility smart meters to controls embedded in EV chargers, batteries, and electric appliances themselves.
“Low-cost smart meters with plenty of compute [capacity] are being deployed at scale today,” Hertz-Shargel told Canary Media in an interview this month. “The question is, do we need more dedicated energy hardware in the home? The lowest-cost solution will always rely on software. It seems a smart meter and an EV charger, or a battery, are the only devices you need.”
Rao pushed back on that proposition. While individual devices can throttle their power use, smart panels offer a more holistic way to oversee and control a home’s overall power demands, he said.
And utility smart meters are “not purpose-built for avoiding a service upgrade, or for adding new electrical loads to your home, most of which require not just sensing, but real-time controls,” Rao added.
Span has been working with a number of utilities, including Pacific Gas & Electric in California, that are interested in using its technology in concert with smart meters and grid control platforms for the additional home device-management flexibility it offers, he noted.
Span and Eaton also plan to launch “joint solutions” that combine both companies’ technologies in the second half of this year. “There are obviously a lot of interesting opportunities for technology partnerships,” Rao said, though he declined to provide details.
Lots of Americans are electrifying their cars and homes, enticed by the prospect of lower bills, cleaner air, and less planet-warming pollution. But all that new electric equipment creates a serious challenge: It requires bigger, better infrastructure to manage the increased flow of electrons, from the electrical panels in individual buildings to the transformers and power lines that make up the grid at large.
Pacific Gas & Electric, California’s largest utility, is testing a one-two punch of technologies that could let it and customers sidestep those expensive upgrades. The first are devices from smart-electrical-panel startup Span, which plug into utility meters and control when and how a home uses power, avoiding the need for higher-capacity panels. The second are the latest digital controls from smart-meter vendor Itron, which can ensure that the collective power demands of multiple customers don’t push local grid transformers beyond their limits.
Working in concert, these technologies could help individual customers avoid thousands of dollars of upgrade costs to electrify their homes, said Quinn Nakayama, PG&E’s senior director of grid research innovation and development. And if deployed at scale, they could allow the utility to delay billions of dollars in grid upgrades, which should help reduce rates for all its customers, he said.
To be clear, PG&E isn’t promising those results right away. The pilot with Span will start by installing the company’s meter-connected devices at PG&E employees’ homes in the coming months, with a larger rollout to volunteer customers envisioned for 2027, Nakayama said. And PG&E will upgrade existing smart meters with Itron’s technology at about 1,000 homes this year; if they’re cost-effective, the utility may seek to incorporate the capability in hundreds of thousands of customers’ meters through 2030.
“Our service planners, when they interconnect new loads, always have to imagine the worst-case scenario,” Nakayama said. “This enables us to give them the tools and the assurances that those worst-case scenarios will never occur.”
PG&E isn’t the only utility looking for ways to meet growing electricity demand without blowing out its grid budget. Utility rates are on the rise across the U.S., in large part because of the increasing cost of maintaining and upgrading the poles, wires, and substations that deliver power to customers. But PG&E is under particular scrutiny from lawmakers, given its steep electricity rate hikes over the past decade.
Utilities also want to sell more power across their wires. The more they can expand capacity for EVs, heat pumps, and other power-using devices, the more money they can bring in to cover the cost of new infrastructure. This, in turn, eases upward rate pressure for customers at large.
One way utilities could sell more power over existing wires is by tapping the capacity of virtual power plants — collections of rooftop solar and battery systems, EV chargers, appliances, and thermostats that can be controlled collaboratively to reduce grid strain. In recent years, PG&E has run multiple VPP pilots with EV chargers, and it launched a project with Span, Sunrun, and other vendors in 2025 to test how smart electrical panels and solar-charged batteries that customers have already installed could relieve local grid constraints.
However, utilities are loath to rely on novel technologies to replace tried-and-true grid upgrades. If a VPP doesn’t work, for example, local transformers or neighborhood substations can overheat and break down under increased stress. That’s why PG&E’s latest experiment is covering its bases with devices that can control excess power use both at the home and on the grid.
To moderate home energy use, PG&E is using Span’s latest smart-electrical-panel device, which is designed to plug directly into utility meters. The Span device can actively monitor and control household circuits powering air conditioners, refrigerators, and clothes dryers, as well as EV chargers, heat pumps, and other more advanced energy systems.
Adding a major new power draw to a home, like an EV charger, often requires an electrical panel upgrade, which can cost thousands of dollars and add weeks to months to an installation. It can also trigger an upgrade to the local grid, which can take months to complete and cost anywhere from several thousand dollars for replacing a transformer on an overhead power line to around $50,000 for digging up and replacing underground service transformers and power lines.
“Nobody wants to pay that,” Nakayama said.
But those upgrades are predicated on the assumption that the new EV chargers will be drawing maximum power at the same time that all the other homes in the neighborhood are maxing out their electricity use, stressing their shared grid infrastructure. That’s usually during hot summer afternoons and evenings when air conditioners are running full tilt.
Span’s tech allows PG&E to offer those customers an alternative, Nakayama said: Let the smart device curb grid stress by reducing charging speeds during those peak hours. Most EVs require only several hours to recharge their batteries, giving them time to ease off on charging for a while yet still fill up overnight.
“I think most people are OK if their car charges a little bit slower, as long as it charges by 6 in the morning,” he said. That’s called managed charging, a concept that utilities across the country are exploring as they prepare to handle millions of new EVs coming online over the ensuing decades.
Span’s software also lets customers set other parameters to keep their total household electricity use below those limits, like delaying clothes dryers until later at night or easing off on air conditioning, Nakayama said. These kinds of technological solutions are going to be important for the more than 600,000 of PG&E’s roughly 5.5 million customers that the utility expects to need some kind of electrical service upgrade in the next 10 years to meet state electrification goals.
Span CEO Arch Rao said the company is working with other utilities interested in using its equipment for similar purposes. “A lot of the technical validation work has already been completed,” he said. “It’s now about customer recruitment and enrollment.”
So that takes care of individual homes. But how can PG&E ensure those controls are actually relieving local grid stress? That’s where Itron’s smart meter technology comes in, Nakayama said — or more specifically, Itron’s latest chipsets, which can be plugged into the smart meters that PG&E has already installed.
Like traditional utility meters, smart meters track a home’s electricity usage. But they use onboard computers and wireless networks to upload those readings to utilities, rather than requiring employees to come by to check the readings once a month. U.S. utilities have deployed nearly 120 million of these smart meters over the past two decades.
In utility parlance, smart meters are known as “advanced metering infrastructure,” or AMI. Older “AMI 1.0” technology can do some advanced tasks, like detect power outages and communicate via wireless networks with other meters and the utility. But it lacks the computing power and real-time capabilities to do more complex things, like actively communicate with and control devices in homes and businesses.
Enter Itron’s latest “AMI 2.0” technology. If AMI 1.0 is like a flip phone, AMI 2.0 is more like a modern smartphone, capable of uploading applications that can undertake the novel tasks that PG&E is now exploring.
In other words, “the meter is no longer just a meter — it’s a controller,” said Nick Tumilowicz, head of Itron’s distributed energy management solutions business. The company’s AMI 2.0 technology has already been controlling Level 2 EV chargers at hundreds of PG&E customers’ homes through a pilot project launched in late 2024, he said. Itron has used the same technology to manage school bus charging in New York City and Tesla Powerwall batteries for Colorado utility Xcel Energy.
Smart meters can also do something that in-home devices can’t, Nakayama said: communicate with all the other meters in the neighborhood to check how their shared electrical loads are impacting the transformers they’re connected to.
All those meters are linked in a wireless network and “speak the same language,” he said. Once an AMI 2.0 meter is connected, “it has the ability to say to its surrounding AMI 1.0 meters, ‘We’re all on the same service transformer,’” he said. “And it can do simple math, and figure out what that service transformer limit is,” as well as determine much demand the transformer faces from homes.
The tech then feeds that data back to the EV chargers and electrical panels that are linked to the AMI 2.0 meter, he said. For instance, if other nearby homes are using more power than usual and stressing the local transformer, PG&E could direct those smart panels and EV chargers to throttle power.
Finding ways for neighborhoods to electrify without crushing the grid will require a lot more solutions like these, said Ben Hertz-Shargel, global head of grid edge at research firm Wood Mackenzie.
“There is so much risk — and so much opportunity — on the distribution system. If electrification happens in an unmanaged way, it will be extremely expensive,” he said.
On the other hand, utilities have to make sure the technologies they’re deploying don’t add more costs than the benefits they deliver, Hertz-Shargel said. For example, PG&E’s new pilots are funded through state grants, and the utility will need to prove their cost-effectiveness before asking regulators to let it charge customers at large to deploy them more broadly as part of a rate case.
That evidence is particularly challenging to come up with when trying to avoid upgrades to the low-voltage network that brings power directly to houses, since most utilities don’t have solid details on that part of the grid.
“The problem is that utilities don’t have good data on these assets below the substation,” Hertz-Shargel said. “These devices need to not only solve the thermal overload problem but provide the ground-truth data to prove that they’re solving the problem — such as that the transformer stayed well below its power rating.” If that evidence is lacking, these technologies will be a harder sell to planning teams, he said.
“It’s smart for PG&E to try these different solutions,” Hertz-Shargel said. “I think the ones that survive will be the ones that are most cost-effective.”
Base Power, the Texas-based home-battery juggernaut, just revealed how it’s spending some of the $1 billion it raised in October. The startup’s plan is to build one of the nation’s largest fleets of home batteries, for a cooperative utility outside Dallas–Fort Worth.
Cleantech startups and advocates alike keep promising that small-scale energy devices such as residential batteries and thermostats can be coordinated and operated like traditional power plants. But in practice, it’s been harder for companies to build enough aggregated capacity, with high enough reliability, to truly match the performance that utilities are used to at their large-scale gas power plants. The new Base Power project tackles this challenge head-on.
Base Power will work to install 100 megawatts of home battery capacity in the territory of member-owned utility Denton County Electric Cooperative, known as CoServ, over the next two years. Crucially, that scale equates to the output of a natural-gas-fired peaker plant, a class of smaller conventional power plants that fire up when demand is highest. While building a new gas peaker could take around five years of permitting and construction, Base Power can deliver the capacity in two years by striking deals with homeowners and installing each system in a day, said Tim Pianta, the company’s head of utility partnerships.
“The whole business is oriented around, How do we get dispatchable megawatts on the grid really quickly to drive down grid and power supply costs? And I think this is a really good application of that,” he said.
In partnership with CoServ, Base Power will pitch the utility’s customer-owners on whole-home backup power for an installation fee starting at $695 and a monthly $19 subscription. That’s a slim fraction of the cost to buy a big enough battery on the open market, which could easily run to $15,000 or $20,000. Base Power can afford to offer that bargain because it retains ownership of the batteries and will call on them to fulfill a grid capacity contract for the utility.
On the utility side, this contract should offer the fastest path to adding capacity affordably, Pianta said. While CoServ could purchase power from the wholesale market managed by the Electric Reliability Council of Texas or build its own peaker plants, the battery fleet gives the utility the option to buy power when it is cheap and deliver it when prices are high. Lowering the amount of power CoServ has to ship in during peak times also reduces the utility’s transmission costs, he added.
In short, this deal is an affordability play for CoServ — the third-largest electric coop in the U.S., serving 330,000 electric meters — at a time when average U.S. electricity costs are rising faster than inflation (and gasoline and natural gas prices have also spiked, at least temporarily, following the U.S. attacks on Iran).
“That’s a core value proposition for them: driving down costs of their power supply. And then, in tandem with that,” Pianta said, is “the ability to offer members dramatically more affordable resiliency than they would otherwise be able to get.”
Base Power launched in 2023 with a similar offering in parts of Texas where customers can choose their retail electricity provider; the startup sells cheap backup power and a cheap electricity subscription, then dispatches the batteries in ERCOT to recoup the cost of installation. The company then launched a parallel business packaging this concept for utilities in parts of Texas where customers have just one local retailer to pick from. The CoServ collaboration marks the fifth of these deals, and the largest — all five total 180 megawatts.
First, though, Base Power must deliver on this ambitious promise. For the CoServ deal, Base Power sales associates will have to convince some 5,000 homeowners to pay for backup power. Even with a low price, that entails a significant ground game, and will depend on the level of customer interest in battery backup.
Pianta noted that CoServ “already has a very reliable system, so they have very few outages.” That compliment may be constructive for maintaining a strong partnership with the utility, but it runs against the usual marketing playbook for home backup — evoking the risk of being left in the dark by utility failures. This tension is playing out around the country in places where battery vendors have opted to sell their wares in partnership with utilities, instead of running insurgent marketing against them.
This being Texas, memories of the deadly Winter Storm Uri in 2021, which precipitated a systemwide collapse of natural gas and electricity supply, could motivate residents to sign up. The small investment and monthly fee could be an enticing insurance policy for Texans who harbor a healthy skepticism of politicians’ efforts to fortify the state energy system in the wake of that disaster (and the often-politicized response has left plenty of room for skepticism).
Pianta said Base Power will hit the 100-megawatt deployment target by leaning on its vertically integrated business model, in which the company designs, builds, sells, installs, and maintains its batteries, rather than outsourcing those functions.
“Base has been building up for a long time now, both the supply capacity to deliver that type of resource and the deployments engine to develop that local capacity really quickly,” Pianta said. The company is ramping up manufacturing in the former Austin American-Statesman building, and it has reached an installation pace of more than 60 customers per day, for a total of 300 megawatt-hours in operation.
The contract also protects CoServ customers, stipulating that the utility pays only for the capacity that Base Power actually delivers, Pianta said. This aligns incentives between the utility and the startup, giving the latter good reason to move swiftly on installing its batteries.
Longer term, the project will serve as a large-scale test case for decentralized batteries as an effective competitor to traditional fossil-fueled power plants. CoServ leadership thought this would be a good deal for serving its customers’ electricity demand, but the price point for that 100 megawatts matters only if the batteries work en masse. That’s why Base Power retains control and ownership of the batteries: It doesn’t have to worry about homeowners using the batteries in ways that undermine their availability when the utility wants them to discharge.
Beyond the efficacy of the battery network, Base Power must prove its overarching business case: Does paying all the money to build an in-house battery empire pay off in the end? Can the home battery market support a corporate newcomer with a $4 billion valuation and major investment from Silicon Valley royalty like Andreessen Horowitz? The only way to settle those questions is to install a lot more batteries.
One of the most promising low-carbon cement startups, Sublime Systems, has hit a major roadblock in its efforts to scale up production.
The startup said this week that it had laid off about two-thirds of its workforce, having already paused construction in December on its forthcoming commercial-scale facility in Holyoke, Massachusetts. The actions were in response to the Trump administration clawing back an $87 million award last year from the Department of Energy’s now mostly gutted Office of Clean Energy Demonstrations.
The grant, which was meant to help Sublime build the Holyoke manufacturing plant, was swept up in the administration’s broader rollback of billions of dollars in previously awarded funding for projects that curb carbon emissions from industrial facilities.
Ever since then, “the company has faced compounding challenges in assembling the capital stack required to scale our operations,” a Sublime spokesperson said on Thursday in an email to Canary Media. Sublime said its project had been expected to create hundreds of direct and indirect jobs in the region.
Sublime, an MIT spinout, has raised over $200 million in total funding, including the federal grant. The six-year-old company is part of a bigger global push to develop novel ways of making cement, without producing planet-warming pollution in the process.
Traditional cement — which is mixed with sand, gravel, and water to form concrete — is responsible for roughly 8% of global carbon dioxide emissions. Nearly all cement is made today by heating carbon-rich limestone in fossil-fuel-burning kilns as hot as molten lava.
Sublime’s approach is very different. It involves electrically charging a bath of chemicals and calcium silicate rocks. In March 2024, the Biden administration awarded Sublime and other producers a collective $1.5 billion to slash the carbon impact of cement, as part of a larger $6 billion investment in industrial decarbonization projects.
Before this week’s layoffs, Sublime employed as many as 90 people, and it was making progress around proving its technology and securing key customers, including Microsoft.
Last summer, Sublime completed a “pilot pour” of its low-carbon cement at a data center campus in northern Virginia owned by Stack Infrastructure. And in May, Microsoft signed a binding deal to purchase up to 622,500 metric tons of Sublime’s cement products — enough to build roughly 30 professional football stadiums — from the startup’s forthcoming manufacturing facilities.
This week’s setback casts doubt on Sublime’s ability to supply Microsoft with that cement, as Bloomberg first reported. The tech giant declined to comment directly on how Sublime’s layoffs might affect Microsoft’s own goals to reduce carbon emissions from infrastructure projects.
However, Microsoft “remains committed to advancing low‑carbon building materials and continues to work with Sublime and a range of partners to support our long‑term sustainability goals,” a spokesperson said by email.
Microsoft has also invested in the clean-cement startup Fortera to support construction of that firm’s 400,000-ton-per-year facility. And it’s partnering with RMI and the Center for Green Market Activation to develop a system enabling companies to purchase “environmental attribute certificates” that represent the emissions reductions provided by cleaner cement and concrete — without actually buying the physical product.
Sublime said it continues to see “strong customer demand and industry backing” and is sticking to its goal of building the first electrochemical cement plants in the United States and Europe by 2030. The startup added that it remains in talks with the Department of Energy to try to restore its award and resume construction on its Holyoke facility.
“Sublime remains strong and well-positioned to continue to attract capital, commercialize its technology and meet market demand,” the company said.
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.
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