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Facing new regulations and stiff competition from China, Sweden and other EU countries are racing to decarbonize steel production. It all hinges on green hydrogen.
In 1872, while on a trip to Europe, Andrew Carnegie met with an engineer and inventor named Henry Bessemer. During the Crimean War, Bessemer had accidentally discovered an efficient (for the time) new method of making steel, which involved blowing air through molten iron to remove its impurities. He later developed it into a process that a few small steelworks had already adopted by the time of Carnegie’s visit. Carnegie had been following Bessemer’s invention from the U.S., but none of the steelworks employing it there had really taken off. The future titan of industry was nonetheless wowed by the older man’s presentation, and returned home convinced that steelmaking should be his next venture.
There was no doubt as to where to make such an investment. Manufacturing steel required huge volumes of iron ore and coal, and both were abundant around Pittsburgh. The city also enjoyed an advantageous location for transporting the heavy end product by barge. The Allegheny and Monongahela rivers merge there into the Ohio, down which one can navigate to the Mississippi and the Gulf of Mexico. Plus, Carnegie had a ready customer in the expanding railroad industry and political help in the form of a recently enacted steep tariff on imported rails. So, the Edgar Thomson Steel Works was erected in 1875, 10 miles outside Pittsburgh, in Braddock. (The thing is still running.)
One hundred fifty years later, a similar confluence of circumstances can be found nearly 100 kilometers (62 miles) south of the Arctic Circle, in Luleå, Sweden — one that could lead to the next big innovation in steelmaking. In 1872, no one knew, or cared, that Bessemer’s method was actually carbon manufacture with a side hustle in steel: Even in today’s furnaces, 1.8 metric tons of carbon dioxide are emitted for every ton of steel, give or take. But now, a new, cleaner method of steelmaking exists. It involves using hydrogen instead of coal to produce iron from iron ore in a process called direct reduction, then fashioning that iron into steel in an electric arc furnace.
When renewable electricity powers the hydrogen production and the electric arc furnace, the CO₂ per metric ton of steel in direct and indirect emissions can be reduced to 0.4 metric tons — about 80% less than from the most efficient methods developed since Bessemer’s time.
Hybrit Development, a joint venture of the Swedish companies LKAB (iron ore mining), SSAB (iron and steel production), and Vattenfall (energy), is developing an end-to-end process for steelmaking using hydrogen in Luleå. The group opened a pilot plant in 2020 and is working to build its first commercial-scale plant. Stegra, another Swedish startup, is aiming to do the same thing about 40 kilometers (25 miles) north, in Boden.
Much like the Pittsburgh area in the 1800s, northern Sweden enjoys certain geographical advantages: a surplus of hydropower, enormous iron ore mines 250 kilometers (155 miles) to the north, and a thriving seaport.
Sweden is also getting a nudge from the European Union, which aims to make Europe the first carbon-neutral continent by 2050. Starting this year, the steel industry across the 27 member states has to start paying for its emissions under the EU Emissions Trading System — the allowances initially granted to give it time to adjust are being phased out. The new regulations will sink its business model.
Germany, Norway, and other European countries are making similar efforts to decarbonize steel production, and as with many things concerning the energy transition, China is leaping ahead. The world’s largest ironmaking plant fueled by hydrogen started operating at full capacity late last year in Zhanjiang City, Guangdong. The U.S., meanwhile (as with many things concerning the energy transition), lags behind. The Biden administration sought to spur green hydrogen projects with tax credits and subsidies, but since January 2025, President Donald Trump has killed $12.5 billion in federal funding for clean energy projects — including some in green hydrogen — and threatened to scrap an additional $12.2 billion in existing grants. (SSAB was behind one of those projects, in Mississippi, but — perhaps seeing the writing on the wall — it quit the subsidy award process just before Trump took office and says it has no plans to try again in the U.S.)
With more than 300,000 jobs and 152 billion euros in economic activity tied to the EU’s steel industry, the stakes are high for Europe in the global race to decarbonize steel. And given the industry’s 5% contribution to overall bloc emissions, if it succeeds, the benefit to the climate will be enormous.
The hulking, rusting blast furnace that greets visitors just inside the gate of SSAB’s Luleå facility is a working remnant of traditional steelmaking. A short drive across the 265-hectare (1-square-mile) site follows the route of an elevated conveyor belt connecting the coking plant, where coal is cooked down, to the blast furnace. The road continues on to the building that houses Hybrit’s direct-reduced-iron demonstration plant. At 50 meters (164 feet) high, it’s about as tall as the blast furnace, but the similarities end there. The demonstration plant’s right angles and light-gray aluminum siding stand in stark contrast to the older structure’s tangle of rusted, ashen cylinders and beams.
General Manager Gunilla Hyllander met me in the parking lot that divides the demonstration plant from Hybrit’s administration building. Just inside the door to the offices, a loose pile of employees’ shoes dripped snow — though at minus 11 degrees Celsius (12°F), it was almost balmy for January in northern Sweden. We sat down in a large room with samples of iron made in the DRI plant laid out on tables. Though the facility wasn’t in operation that day, Hyllander could see the future starting to take shape.
“Hydrogen reduction in itself is not new,” she said. “People have been thinking about that for years. But in an efficient, safe, and productive manner? That has not been proven before. We think that all the processes from mine to steel could be converted to a fossil-free manner. We’re using all existing technologies and putting it together in a new value chain.”
Steel has been produced on this site since the 1940s, originally by Norrbottens Järnverk. In 1978, Sweden’s government decided to socialize the country’s steel industry by merging Norrbottens and two other struggling companies under state ownership, as Svenskt Stål AB (Swedish Steel Ltd.). SSAB reprivatized in 1992, though the government now owns a 16% share. A major investment in the Luleå operation came in 1998, when the company built the current blast furnace at a cost of 850 million kronor (around $150 million, inflation-adjusted). That timing is significant. A blast furnace requires major maintenance about every 15 years. After relining its facility once, SSAB realized that by 2030 at the latest, it would need to either make that investment again, which would mean producing 7% of the country’s carbon emissions even after the carbon allowances had expired, or figure out a way to do things differently. The company took the second path, banding together with LKAB and Vattenfall to form Hybrit — short for “hydrogen breakthrough ironmaking technology” — in 2016.
SSAB’s decarbonization challenge is a microcosm of the European steel industry’s. It’s going to be a heavy lift. The company’s gigantic share of Sweden’s carbon emissions is no outlier. Globally, the sector produces about 7% to 9% of anthropogenic CO₂ emissions, according to the World Steel Association — about the same as all the world’s passenger vehicles — and accounts for over a quarter of the EU’s industrial emissions. Demand for steel is projected to grow by nearly 20% by 2050, according to BloombergNEF.
The traditional steelmaking process that Carnegie helped popularize primarily emits carbon in two ways: First, coal is burned as fuel to heat blast furnaces to above 1,000°C (1,832°F). Second, a purified form of coal, called “coke,” is heated inside the furnace to induce a necessary chemical reaction that strips oxygen from iron ore (the “reduction”), producing iron and — the second emission — releasing CO₂.
Hydrogen-based direct reduction addresses both problems. Instead of carbon, hydrogen serves as the reducing agent for the iron, combining with oxygen to produce water vapor instead of CO₂. The process operates at lower temperatures than blast furnaces do, requiring less energy. When that energy comes from renewables and the hydrogen is produced from electrolyzers — machines that split hydrogen from water — powered by wind or solar, the result is near-zero emissions. “In the development program, we are close to zero CO₂ emissions per tonne of crude steel — 42 kilograms, instead of 1.6 tonnes,” Hyllander said.
Direct reduction with natural gas has been used in commercial operations for decades, particularly in the Middle East and India, where cheap gas has historically been abundant. What’s changing now is the fuel source. Hybrit started with natural gas to establish a baseline for emissions, but in 2021 it began producing hydrogen with two stacks of electrolyzers. Situated behind the DRI plant, the electrolyzers aren’t much to look at. With their cylindrical shape and multiple rubber tubes, they resemble sewage pipes on life support. But inside is a complex system of wires, tanks, valves, and gaskets that passes an electrical current through an alkaline solution between an anode and cathode, splitting the water into hydrogen on one end and oxygen on the other.
Over the past five years, Hybrit has operated its pilot plant for 61 weeks, producing 5,000 metric tons of fossil-free sponge iron pellets, each about the size of a chocolate-covered almond, which a microscope reveals to have a porous structure. The company has also conducted over 400 trial melts at the research institute Swerim, down the road, which operates its own electric arc furnace. At least one automaker is already using the end product in its vehicles, and Hybrit’s green steel has been incorporated into production lines for heavy machinery and consumer products. The process works. The question is whether it can scale economically.
Europe has positioned itself as the global leader in green steel, and major producers have set ambitious targets. SSAB and Thyssenkrupp aim for carbon neutrality by 2045; ArcelorMittal aims for 2050. Already, more than half the near-zero-emissions steel projects in the global Green Steel Tracker are in the EU. Among them are Hybrit’s neighbor and competitor, Stegra, with a goal of producing 5 million metric tons of green steel annually by 2030 at its Boden plant; and Finland’s Blastr, targeting 2.5 million metric tons by 2026. (In comparison, Edgar Thomson outside Pittsburgh, now part of the Mon Valley Works complex, produces 2.9 million tons annually.) Thyssenkrupp, ArcelorMittal, and Salzgitter have all announced hydrogen-based projects in Germany. The EU has approved nearly 9.3 billion euros in state aid for these ventures. The European Steel Association forecasts emissions reductions of 81.5 million metric tons of CO₂ equivalent per year by 2030 if current projects are completed on schedule.
But progress has stalled. As of August 2024, 80% of announced direct reduction capacity hadn’t moved forward. Only 3% had become operational. Recent setbacks have raised serious doubts about whether hydrogen-based steelmaking can scale up in time to meet the emissions-reductions targets.
Stegra, which, like Hybrit, aims to produce hydrogen on-site, has struggled through at least two seismic funding shortfalls. ArcelorMittal, meanwhile, has scrapped plans to convert two steel plants to green production in Germany because of the high electricity costs of running an electric arc furnace. And Thyssenkrupp announced in March 2025 that it might need to ditch a $3.3 billion conversion project, citing the lack of affordable green hydrogen needed to supply its steel mill.
Steel producers such as Thyssenkrupp that plan to outsource their hydrogen face a classic chicken-and-egg problem. They need confidence there will be a hydrogen supply before they’ll commit to building. But hydrogen producers need committed offtake before they’ll invest in production, and pipeline operators need both before they’ll convert networks to use H2. Nobody wants to move first.
“Companies are not going to invest if they don’t know the pipeline is going to be ready on time and that the offtake is there,” said Leif Christian Kröger, Thyssenkrupp’s head of public affairs.
In 2022, European leaders tried to address the lack of supply by setting an ambitious target of 10 million metric tons of domestic green hydrogen production and 10 million metric tons imported by 2030. Hydrogen conferences sprouted up in Rotterdam and Düsseldorf, replete with optimistic projections of when green hydrogen would meet price parity with “gray hydrogen” (produced using natural gas) and “blue hydrogen” (natural gas with carbon capture). But then the reality hit of how much renewable electricity would be required to meet the targets. With estimates running to the equivalent of almost twice the entire United Kingdom’s consumption in 2020 (a pandemic year), it’s not surprising that progress so far has been an underwhelming 1% of the goal. “They need to show a lot of progress in the next 12 to 18 months” to get there, Daniyal Sheikh, hydrogen market analyst at ICIS, a commodities research service in London, told me in October.
Nima Pegemanyfar is executive vice president of customer operations at Quest One in Hamburg, Germany. His company was making 1-megawatt electrolyzer stacks as far back as 1997 (as H-TEC Hydrogen Energy Systems) and in 2023 launched a 10-MW-to-100-MW modular plant. “Capacity was the restraint a few years ago, so we built that up as an industry,” he said. “Now, demand is what’s lagging.” This isn’t just the self-interested complaint of an electrolyzer manufacturer. Christine Falken-Großer, of Germany’s Ministry of Economic Affairs and Climate Action, agreed that “demand is the essential element right now to unlock growth” in green hydrogen production.
But the economics are punishing to buyers. Green hydrogen costs at least twice as much as its fossil-based alternative. Though natural gas prices have spiked with the closure of the Strait of Hormuz, futures contracts indicate the market believes this will be a temporary disruption that will be resolved before green hydrogen scales up enough to compete on price.
“Producer costs are higher than the price, and customers are not willing to pay the premium,” said Camilla Montemurro, a policy adviser at the trade association Eurogas. BloombergNEF doesn’t expect green hydrogen to reach price competitiveness before 2030, leaving scant time before the carbon allowances expire to achieve what it took Hybrit a decade to do.
Electricity costs in Germany — Europe’s leader in steel production — are a significant hurdle. “The green steel industry doesn’t want to decarbonize as fast as planned, because of the high cost of renewable electricity,” Pegemanyfar said. A million-metric-tons-per-year direct reduction plant running fully on hydrogen requires about 70,000 metric tons of hydrogen annually. That amounts to roughly 800 MW to 900 MW of electrolyzer capacity with around 1 gigawatt of electrical transformer capacity — a capital expenditure of 350 million euros to 700 million euros before you’ve bought any iron ore.
Infrastructure gaps compound the cost hurdle. Europe envisions several “hydrogen backbones” — networks of converted natural gas pipelines carrying hydrogen from ports or production sites to industrial (and perhaps commercial and residential) users. But the chicken-and-egg problem persists. “Pipeline operators won’t invest without offtake, and users won’t buy without infrastructure,” said Dirk Niemeier, director and Clean Hydrogen Solutions lead at PwC in Munich.
The backbone is only the half of it. Just as electricity requires tall transmission towers to move large volumes of power long distances and smaller wires to distribute it to users from central hubs, hydrogen requires both thick pipes (the backbone) and skinny pipes (for delivery to the end customers). Barbara Jinks, director of Ready4H2, an industry group that promotes using gas distribution grids to deliver hydrogen, described the scale of the undertaking: “More than half the gas won’t get to the end user with current infrastructure. Anything more than 3 kilometers [1.8 miles] from the backbone needs a distribution line.” The gas industry would rather sell capacity in the pipelines in which it has already invested billions to hydrogen producers than see this asset stranded as the world switches to running on electricity.
But “hydrogen has rather unique effects on materials, and many of them are not good,” noted P. Chris Pistorius, co-director of the Center for Iron and Steelmaking Research at Carnegie Mellon University in Pittsburgh. The pipeline networks can be converted, but that takes money and time.
Storage presents its own conundrum. Daniel Mercer, managing director of Storengy, a subsidiary of French energy giant Engie, hopes to provide “the hydrogen battery for all of Europe” by storing the gas in underground geologic formations near Hamburg, Germany. But funding is scarce. “We are the only part of the hydrogen system not supported by the government, yet we’re the part that takes the longest to develop,” he said. “Finding funding is the toughest part of my job right now. I need somebody to give me 1 billion euros and be OK with not making any money for eight years” while the underground H2 storage project is built out.
Importing hydrogen instead of producing it in Europe wouldn’t really help. Several European ports are developing terminals to import ammonia, which contains hydrogen molecules and is easier, cheaper, and safer to ship than pure H2. But converting hydrogen to ammonia and back again loses about half the energy contained in the original batch. So when the buyer collects a shipment “in Rotterdam or Hamburg, the price is suddenly double,” said Alexander Fleischanderl, chief technology officer of the London-based Primetals Technologies, which developed a proprietary technology called Hyfor for making green steel. “This is by far not competitive anymore.”
Like Hybrit, Primetals Technologies gets around problems with importing hydrogen by attaching production to its green-steel manufacturing process. It hopes to offer green steelmaking as a kind of service and secure contracts to build plants for companies shutting down their blast furnaces.
Amid these converging pressures, European policymakers and industry leaders must confront tricky questions about the continent’s industrial future. Can Europe keep steel production at today’s levels while ratcheting down emissions through the necessary conversion? Can the current political environment withstand losing jobs to countries where steel can be produced at lower cost?
“I would bet that at least some capacity will move away from Europe to more competitive regions,” Fleischanderl said. The logic is straightforward. With steelmaking, 80% of the energy and just 20% of the jobs are in converting iron ore to iron. Turning that iron into steel takes 20% of the energy and 80% of the jobs. “Why should we transport hydrogen if we could use the hydrogen locally” in producing iron? Fleischanderl asked. Most of the world’s iron ore is in places with ample opportunity for renewable energy — Australia, Brazil, Canada — and thus relatively cheap hydrogen. Decoupling the two processes geographically — producing the iron overseas and then shipping it to Europe, where it can be made into steel in an electric arc furnace running on renewable energy — would sacrifice relatively few jobs to gain a lot in savings on green hydrogen.
Pistorius also thinks that the less labor-intensive part of the steelmaking process could move overseas, where renewables are cheaper. “There’s a lot going for that argument,” he said. “Shipping iron is a relatively good way to [move] the energy around rather than trying to ship ammonia and regenerate it to hydrogen at the destination.”
But Germany’s 79,000 steel jobs hold an outsize place in the country’s identity. Next door in the Netherlands, farmers representing 1% of jobs and 1% of GDP almost brought down the government when it threatened to tighten pollution regulations. Germany’s ascendant populist forces, at least, are likely to resist sacrificing even 20% of steel jobs on the altar of green energy.
Either way, strategic considerations argue for maintaining at least some domestic production. Steel is essential for defense, infrastructure, and the energy transition itself — wind turbines and transmission towers are largely steel. The current energy crisis spurred by the war in Iran has driven home once again the risks of long supply chains, and the EU’s Carbon Border Adjustment Mechanism, which functions as a tariff on high-carbon imports, aims to protect European producers that invest in decarbonization.
Additional policy changes could further accelerate progress. The EU’s Renewable Energy Directive (RED 3) imposes strict requirements on what qualifies as green hydrogen — requirements that many argue are too stringent. “EU needs to relax RED 3,” Niemeier said. “That would bring down the cost.”
“You can’t have a free market at the beginning of this,” said Ad van Wijk, professor of future energy systems at Delft University of Technology in the Netherlands. “There will be buildup to a market, but you need some organization at the beginning. Are we able in the EU to organize all this, with all the politics that are behind the different fuels?”
Falken-Großer has learned from experience that “‘quickly’ is not a word that is known in Brussels.”
Julia Metz of Agora Industry, a clean industry research institution, suggests public procurement requirements and state-funded infrastructure projects to provide the nascent industry with guaranteed offtake. “Lead markets [created] through binding requirements in public procurement” would build “secure demand for green steel,” she said in an interview with Clean Energy Wire. The European Commission’s proposed Industrial Accelerator Act, part of the Clean Industrial Deal, aims to support domestic clean industries through public procurement.
Even without these nudges, 510 green hydrogen projects have reached final investment decisions, including 83 since May 2024, and customer commitments for green steel are emerging. BloombergNEF in 2025 tallied up almost 200 supply agreements for low-carbon steel. SSAB has announced deals with Volvo for green steel sourced from Hybrit; Mercedes also has an offtake agreement. The automotive industry — which accounts for significant steel demand — increasingly wants to claim carbon neutrality, said Martin Gidlund, SSAB’s transformation communication manager. “For 2040, they want to be able to say ‘made with green steel.’”
In Luleå, the scale of what’s being attempted becomes tangible. Within view of the current coking plant, SSAB broke ground in September 2025 on a building that is 1.5 kilometers (1 mile) long and about a half kilometer (quarter mile) wide and that will integrate two electric arc furnaces, continuous casting, hot rolling, and cold mill operations. The new plant will be able to run on either scrap steel or sponge iron from direct reduction using green hydrogen, or any mix of gas. Initially, the facility will use scrap, like SSAB’s existing U.S. electric arc furnace operations do in Montpelier, Iowa. At peak construction, up to 3,000 workers will be on-site. In a preview of Fleischanderl’s notion that ironmaking and steelmaking can be geographically separated, the iron ore will be reduced next to LKAB’s mining site and transported by rail to be turned into steel in Luleå. After some delays with the grid connection, startup is now targeted for late 2029. The environmental permit allows only two years of parallel production, so once the new facility starts, the blast furnace must shut down by 2032. Sweden’s single largest CO₂ emitter will be no more.
The business case rests on multiple factors. The existing blast furnace, built in 2000, will need relining soon — a significant investment. The coking plant, built in the 1970s and operating continuously since, is aging; renovation is not an option. “We cannot turn it off, because if we do, it will fall apart,” Gidlund said. The bricks inside the ovens will just shatter as they compress when the heat dies down.
Under the EU Emissions Trading System, continuing with coal-based production would cost SSAB more than 10 billion euros a year in carbon credits, the company has determined. “Either we invest a lot of money in old technology, or invest more money but in new technology,” Gidlund said. “We’re calculating that building the new one is using our capital more efficiently and also setting up for a system that will make us more competitive in the long run.”
It’s a dilemma that steelmakers worldwide need to face eventually — around 70% of blast furnaces need relining or other major maintenance by 2030. In the EU, over half will by 2035. If they’re relined — extending coal-based production — Europe will miss its climate targets and lock in 435 million metric tons of CO₂ over the next 20 years, according to industry estimates. China’s blast furnaces were installed more recently, so their owners can put off the decision for a few more years. But major steelworks in the U.S. are already investing in the past, opting for relining over going green. U.S. Steel is set to start relining its Gary Works blast furnace in Indiana this month; Cleveland-Cliffs plans to do the same at its Burns Harbor plant in Indiana next year.
Whether Europe’s bet on green steel succeeds depends less on technology than on coordination. Hybrit and Primetals Technologies have solved the technical issues. Quest One and other manufacturers can build electrolyzers at scale. Storengy understands how to bottle the hydrogen. Pipeline operators have the know-how to convert networks.
What’s missing is the choreography — getting all these pieces to develop simultaneously at the pace and scale required. “You have to build production and infrastructure and storage and the offtake side at the same time,” van Wijk said. “You have to replace blast furnaces with DRI, and that has to be done in the same volume by all kinds of different companies. If governments don’t have a certain commitment, it won’t happen.”
The pressure is building. The atmosphere doesn’t care who gets there first, but European steelmakers are facing overseas competition from China, which is curbing blast furnace approvals and scaling up hydrogen-fueled ironmaking output, and from the Middle East and North Africa, whose abundant cheap, renewable energy potential could position the regions as future suppliers of both green hydrogen and reduced iron (as long as, in the case of Qatar and United Arab Emirates, Iran keeps the Strait of Hormuz open). If European buyers who want green steel can’t get it in Europe, they will have other options.
“We’re in the lead on technology, and if we are too hesitant, China will drive by us,” warned Pegemanyfar at Quest One. “Already some German [electrolyzer] manufacturing is moving to China because there’s not enough demand here. If the price doesn’t come down, China will flood our market as it did with solar, and we’ll risk losing out on another key technology for the energy transition.”
Those that have opted to produce their own hydrogen, like Hybrit and Stegra, have a head start. Britain’s ITM Power sells a self-standing 50-MW hydrogen plant for the bargain price of 50 million euros. Thyssenkrupp, ArcelorMittal, and Salzgitter can turn to Primetals Technologies’ plants when its Hyfor tech is ready for market in 2028, but they may find that the hydrogen backbones and Ready4H2-promoted projects aren’t built up enough, or that the bottlenecks aren’t resolved soon enough, to prevent their drowning in red ink from the rapidly approaching carbon fees. “Very likely there will not be sufficient hydrogen in three years,” Fleischanderl said. “It takes plus or minus three years to build a hydrogen plant from commitment to production.”
Considering the widely distributed climate risks of business as usual, and the known health impacts to Europeans of burning coal, losing 20% of the continent’s jobs in steel — 300,000 total, or 0.1% of the jobs in Europe — would be a small price to pay for accelerating the transition to green steel. Germany already lost 115,000 jobs in photovoltaic manufacturing between 2011 and 2015 because of cheap imports from China and nobody blinked an eye. The question before Europe now is whether it will do what it takes to bring green steel to price parity with the dirty kind — either by subsidizing it or letting some production move overseas — or allow a tiny constituency to decide that no one must pay a few euros extra for a car and everyone will be forced to suffer the consequences of steel’s current 2.6 billion metric tons of annual emissions.
“Sometimes in Europe we can be too good,” Falken-Großer said.
Battery startup EnerVenue is planning an iconoclastic comeback. After failed plans to build a U.S. factory for its NASA-inspired tech, the firm announced $300 million in fresh funding to execute a manufacturing strategy that flies in the face of broader trends in the American battery market.
Battery startup EnerVenue is planning an iconoclastic comeback. After failed plans to build a U.S. factory for its NASA-inspired tech, the firm announced $300 million in fresh funding to execute a manufacturing strategy that flies in the face of broader trends in the American battery market.
A rendering shows how EnerVenue’s nickel-hydrogen batteries could be stacked in a warehouse, capitalizing on the chemistry’s safety, compared with lithium-ion’s. (EnerVenue)
EnerVenue seeks to commercialize a version of the pressurized nickel-hydrogen energy storage system that NASA used on the International Space Station and the Hubble Space Telescope. The original technology cost far too much to succeed in civilian power markets, but EnerVenue’s founders claimed to have swapped the platinum catalyst for a much cheaper material. The company says its battery can run 30,000 cycles with minimal degradation, maintaining its usefulness far beyond the typical lithium-ion battery’s shelf life, and with much better fire safety.
The Silicon Valley–based startup raised a $12 million seed round in 2020 and a $100 million Series A in 2021 from the likes of Saudi Aramco Energy Ventures and Schlumberger New Energy. In 2023, EnerVenue told Canary Media it would invest $264 million to open a factory in Kentucky and produce batteries by the end of the year.
Battery factories have been opening across the U.S. to meet skyrocketing demand for grid storage. Federal incentives reward factories for manufacturing batteries domestically and storage developers for installing batteries, as long as they don’t depend too much on “foreign entities of concern,” which in practical terms restricts corporate and supply chain exposure to China. This onshoring effort has moved so swiftly that the U.S. may well become self-sufficient in both battery cells and finished battery enclosures for grid storage by the end of this year.
EnerVenue opted not to contribute to this achievement, at least not anytime soon. The company pulled out of its Kentucky deal in 2024. The $300 million it unveiled March 31 (technically an extension of a $308 million Series B from 2024) will instead fund a factory buildout in Changzhou, China, which the company’s press release hailed as “the world’s epicenter of battery manufacturing expertise.” EnerVenue also promised to “expand its commercial operations across Asia, the Middle East, and Europe.”
“We see ourselves still as an American company,” Henning Rath, who took over as CEO in March, told Canary Media. But, he continued, “We’re going to become a global player.”
Why would this startup choose to zig to China when the rest of its peers are zagging to the U.S.?
For starters, once work began on the Kentucky factory, the company realized that its second-generation battery design wasn’t ready for mass production, and that it would be particularly capital-intensive to build a first-of-its-kind battery factory at the site, Rath said.
From the outside, it might seem sensible to design a viable product before starting to build a factory to mass-produce it. The venture-backed cleantech industry, however, boasts a long history of constructing factories for inventions that failed to function in either practical or commercial terms. Chalk it up to undue optimism, or the pressure to show venture investors a quicker path to mass production and revenue.
In any case, EnerVenue pulled the rip cord, and then-CEO Jorg Heinemann left in November 2024, spending 10 months as a “Cyclist, surf coach & c-suite advisor,” according to his LinkedIn, before becoming president and chief operating officer of a startup selling clean, dispatchable power to data centers. “As the company decided on shifting gears and we evaluated the technology and manufacturing setup, I think that both parties agreed to look into different options” Rath said of Heinemann’s departure. Rath didn’t formally step in as CEO until March; he previously ran supply chains for German residential solar startup Enpal — a task that involved sourcing Chinese solar products for installation back in Europe.
After the reset, EnerVenue delved back into engineering and spent nearly two more years honing a fourth generation of its tech, Rath said. Then the company made the choice to assemble the factory process in China, to take advantage of the mature battery manufacturing sector there.
EnerVenue now has a small R&D manufacturing line operating in Changzhou and is working to finish a 250-megawatt-hour-per-year line by the early fourth quarter of this year. The plan is to grow the factory to 1 gigawatt-hour in 2027 — a level of production that unlocks competitive unit economics, Rath said, at which point EnerVenue could “copy-paste it to different markets.” EnerVenue may have an easier time doing this than conventional battery upstarts, since the ingredients to make its nickel-hydrogen battery are more readily available around the world than the carefully refined cathode and anode materials in lithium-ion batteries.
“We have to showcase scale first, in a very capital-efficient way,” Rath said. “That is the reason why we chose China to build the first scale-up.”
That low-cost manufacturing environment comes with trade-offs, however.
The need to distance America’s energy system from China has become a rare point of agreement across the U.S. political divide. The Biden administration pursued this with tax incentives for companies that build batteries in the U.S. and those that install domestically produced batteries. The Trump administration kept those policies but added the more punitive “foreign entities of concern” test to withhold credits from companies subject to corporate control from China and from projects that use too much equipment from China.
Chinese companies that built factories in America have had to divest from those enterprises to preserve tax credit eligibility for the products made within. EnerVenue poses a different accounting challenge: Can an ostensibly American company move production to China and still sell batteries to the U.S. market that let project developers qualify for the tax credits? Will that ability persist after EnerVenue’s latest fundraise welcomed significant equity investment from the Hong Kong Investment Corp. (wholly owned by the government of Hong Kong) and the Hong Kong–based family office of real estate tycoon Peter Lee?
On maintaining tax credit eligibility for the China-built batteries, Rath said, “We haven’t had a clear conclusion on this yet, but I think within the next probably two months or so, we will have certainty and execute against it.”
Geopolitical intrigue is just one of the challenges EnerVenue faces in commercializing a novel battery. Also on the list: Convincing buyers to bet on a little known chemistry for large-scale grid projects, and to embrace the whole new style of power plant unlocked by a battery with a vastly different operating profile than ubiquitous lithium-ion systems.
Typically, the startups vying to replace lithium bill their inventions as long-duration storage, capable of cheaply shifting clean energy production for many more hours than the four or five that lithium-ion batteries currently muster. Companies like Form Energy and Noon Energy are attempting to push the boundaries to 100 hours. EnerVenue does not stake such claims, and to the extent that the company touts duration, it’s in the different context of the batteries’ overall operating life. Rath said customers have asked for different configurations — from a 2-hour duration up to a 25-hour duration — but didn’t highlight a particular level as indicative of what the technology can do.
Instead, EnerVenue hopes to attract customers with its batteries’ ability to discharge three times a day for 30 years without eroding efficiency or catching fire, and operating parameters from minus 4 to 140 degrees Fahrenheit. (Lithium-ion grid batteries typically discharge once or twice a day and can tolerate a much narrower band of temperatures.) That could make EnerVenue’s system ideal for utilities in rugged environments or petrochemical complexes worried about battery safety. The many cycles a day, meanwhile, could help developers in volatile energy markets who want to take advantage of alternating periods of super-low and super-high pricing.
The trade-off of this impressive cycle life is that the battery needs to cycle a lot to justify its up-front costs. Doing so would require a very different sort of battery business model than what’s in practice today. After EnerVenue shows it can manufacture a working battery, it’ll have to prove that customers are actually willing to pay that premium.
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
Cache Energy installed its thermal battery at the University of Minnesota, Morris, where it stores energy from the campus’ two wind turbines and releases it to heat a carpentry workshop. (University of Minnesota, Morris)
Twenty-one years ago, the University of Minnesota, Morris, became the first U.S. public university to draw power from an on-site, industrial-scale wind turbine. It added a second one in 2011. Today, the pair — affectionately known as Bert and Ernie — produce more power each year than the semirural campus consumes.
“It’s windy year-round here in western Minnesota,” said Troy Goodnough, the school’s sustainability director.
Together, Bert and Ernie crank out 10 million kilowatt-hours of electricity annually. According to Goodnough, UMN Morris consumes about half the output and sells the rest to the Otter Tail Power Co., the local investor-owned utility. Now, a first-of-its-kind thermal battery pilot is underway that, if scaled up, could help the campus use more of that juice while reducing the environmental impact of the sprawling methane-powered steam-heat loops that keep it cozy through Minnesota’s bitter winters.
Late last month, technicians from Illinois-based Cache Energy arrived on campus to install the battery unit, which transforms electricity into intense heat. Its outlet temperature can reach 1,000 degrees Fahrenheit — more than hot enough to efficiently run a steam heating system.
It took two hours to position the shipping container that houses the unit next to the school’s carpentry shop, and then another few hours to connect the unit to the building’s electrical and duct systems. It powered up on March 24 and hasn’t stopped providing heat since, Goodnough said. Its task is not small, he added: The “warehouse-like” shop has high ceilings and several thousand square feet of floor space.
“The cool thing is it’s doing what it’s supposed to be doing,” he said. “It’s working great.”
The battery unit contains limestone-derived pellets coated in a proprietary binder that keeps them intact throughout their 30-plus-year operating life, according to Cache. When exposed to a stream of moist air, the pellets get so hot they “can be used to make hot air or even vaporize water to make steam,” Goodnough wrote last month. To recharge, the system uses electricity to dry out (and cool down) the pellets.
Ideally, that electricity is cheap, clean, and otherwise at risk of curtailment, said Sydnie Lieb, an assistant commissioner for regulatory analysis with the Minnesota Department of Commerce. Lieb’s agency helps fund Minnesota Energy Alley, a public-private partnership that supports the Cache project and other cleantech demonstrations in the North Star State.
“The most cost-effective place for thermal batteries is going to be where you have a lot of excess energy being produced where you don’t have a lot of transmission or [customer] load,” Lieb said.
Western Minnesota certainly fits the bill. The wind farms that dot the open, rolling landscape here and in neighboring North and South Dakota routinely produce more energy than the grid can handle. The Midcontinent Independent System Operator, the nonprofit that manages Minnesota’s grid, throttled hourly wind generation by an average of 508 megawatts in 2023, according to the U.S. Energy Information Administration. That’s the equivalent of what’s produced by about 160 newish onshore wind turbines. The Southwest Power Pool, which manages the grid for the wind-rich region stretching from North Dakota to the Texas Panhandle, curtailed wind output by an average of 1,097 MW that same year.
Arpit Dwivedi, Cache’s founder and CEO, said low-cost electricity helps make the economic case for customers to invest in thermal batteries rather than stick with equipment that runs on natural gas, which is also plentiful in the United States’ midsection.
“We know gas is cheap,” he said, and that’s a problem for tech developers looking to electrify heat.
Another issue for big energy users, like UMN Morris, is that switching from gas to electric heat means replacing massive, long-lived boilers — likely fully paid for — with new equipment that needs to be leased or financed.
That shift is necessary if the university is going to meet its aggressive climate goals of reducing greenhouse gas emissions by 87% by 2035 and reaching carbon neutrality by 2050, but it could incur a considerable balance-sheet burden. So from the outset, Dwivedi and his team were intent on reducing Cache units’ upfront cost, he noted.
“We knew that if we did not have a low-capex system, we would not have an economic advantage,” he said.
Like other emerging thermal battery designs, Cache’s uses low-cost — if heavy — materials that are widely available in the United States. The primary inputs are steel, lime, and water, all of which Cache sources domestically, Dwivedi said. The proprietary binder that keeps the lime granules stable is by far the most expensive input, so the company focused on keeping that cost in check. Its secret ingredients are available domestically, too, Dwivedi added.
Cache offers its battery as a lease product that it says bundles the battery unit, delivery, installation, maintenance, guaranteed uptime, and takedown “without capital burden.” Just as an automaker leases a passenger vehicle, Cache retains ownership of the battery unit during the lease term, after which the customer has the option to buy it or send it back.
Cache launched in 2022. For its first few years, space heating was a sideshow. Dwivedi and his team were more focused on the technology’s potential to electrify low- and medium-temperature process heat for food, chemicals, and other types of industrial production. To that end, Cache recently conducted a pilot at a Duke Energy testing facility in North Carolina that “[hosts] several interested industrial companies,” the company said last month in a news release.
Cache still works on industrial heat, but it’s also leaning into relationships with large space heating customers, particularly those with existing hot-water or steam infrastructure such as UMN Morris. That includes the U.S. Army, which is interested in the thermal battery’s ability to provide reliable backup for military installations at risk of extended power outages.
Cache was one of nine finalists in a demonstration cohort fielded last year by Grid Catalyst, a Minnesota-based clean energy accelerator that also supports Minnesota Energy Alley.
“Decarbonizing our heating in Minnesota stood out as a value proposition,” said Nina Axelson, Grid Catalyst’s president and founder. Cache’s technology, she noted, “is simple, less costly, and really effective on thermal storage and dispatch.”
Axelson said Grid Catalyst acted as a sort of “energy matchmaker” on the UMN Morris project, connecting university leadership with the Cache team. Front-end engineering and feasibility work required some time, she said, but once the university decided to move forward, it only took a couple of weeks to get the project up and running.
“It’s about as plug-and-plug as you get for thermal storage,” she said.
Dwivedi said that while the Morris system has been charging and discharging five or six times a day, the underlying technology can actually cost-effectively store energy for months on end. That’s a big selling point for customers serious about electrifying space and process heat.
Cache is fresh off a demonstration at an Alaskan industrial site, owned by oil and gas services firm Halliburton, that validated its batteries’ ability to hold heat for a long time in temperatures as cold as minus 40 degrees, Dwivedi said. That’s a critical proof point because the price of electricity — particularly on grids rich in renewables — tends to fluctuate throughout the year, he said. A Cache system could, for example, charge up on cheap power during a sunny, windy period in October, then wait to fully discharge until a dark, still spell in December, when local power prices are likely to be higher.
With a capacity of “several hundred kilowatts,” according to Dwivedi, the unit at UMN Morris is smaller than the industrial-scale ones that Cache hopes to sell at volume in the years ahead. The startup makes units as large as 5 MW and could deliver one to Minnesota in a few months if the university decides to expand the pilot, he added.
“We see this university project as a demonstration of one of the applications of this technology, and we can scale from there,” Dwivedi said.
A scaled-up, multiunit configuration could serve dozens of campus structures with a variety of uses. Some buildings have labs, swimming pools, and dehumidification systems that require heat even in the warm months, Axelson said.
In theory, Cache units could replace gas boilers on the campus steam system and complement a future hot-water loop powered by ground-source heat pumps — an increasingly popular cold-climate heating technology that Grid Catalyst is familiar with through Flow Environmental Systems, another 2025 cohort member that produces commercial-grade systems using low-impact refrigerant. A hybrid system could more efficiently distribute thermal energy between buildings and optimize campus heating in the depths of winter, “when you need all the heat you can get,” Axelson said.
“We are looking at using this as a showcase project so that our utility, industrial, and campus partners can see it in operation,” she said. “It’s hard for folks to be first, but when you do take that first project, you really open the gates.”
As UMN Morris undertakes a comprehensive review of its energy usage, Cache’s thermal batteries are among several technologies that could factor into a “Swiss Army knife solution” for sustainable heating, cooling, and power, Goodnough said.
On paper, it looks daunting to fully decarbonize a campus whose gas-fueled heat network uses three to four times more energy than all its electrical equipment put together, Goodnough said. But the university has steadily added on-site renewable capacity, including a 500-kW solar array that “we think is the largest agrivoltaic field in the Upper Midwest,” he said.
In the not-too-distant future, it could have far more homegrown electricity to play with.
“It’s not inconceivable that Bert” — the older windmill — “could be replaced by a 5-MW turbine,” Goodnough said. If Ernie meets the same fate, UMN Morris would roughly triple its on-site wind capacity. Goodnough believes that would be a tremendous opportunity not only for the university but also for rural communities nearby.
“Out here in rural Minnesota, you see storage everywhere: grain elevators, propane tanks, fertilizer bins,” he said. “The energy transition will demand lots of different kinds of storage. It’s a natural fit for us.”
Stegra has secured the financing needed to complete its flagship green-steel mill in northern Sweden.
The company, formerly H2 Green Steel, said it landed 1.4 billion euros ($1.65 billion) in capital from a group of new and existing investors led by Sweden’s prominent Wallenberg family. The funding will enable Stegra to finish building and commissioning its novel facility in Boden, just south of the Arctic Circle.
The project is a cornerstone of Europe’s broader ambitions to decarbonize its industrial sector and lead the world on lower-emissions technology. Conventional steel mills rely heavily on coal to produce the ubiquitous metal, making them a major source of planet-warming emissions and harmful air pollution.
Stegra’s first-of-a-kind project will instead rely on green hydrogen, which could slash carbon emissions from steelmaking by up to 95%, compared with traditional coal-based furnaces.
The sprawling facility will use giant electrolyzers, powered by the region’s ample hydro and wind energy supplies, to split water molecules and produce the clean fuel. That hydrogen will then turn raw iron ore into lumps of iron, which will be melted and made into steel in electric arc furnaces, also powered by renewables.
Stegra said it expects to initially produce 2.5 million metric tons of steel annually and eventually double its production of the metal.
The ambitious undertaking has hit some serious snags since construction began in 2022. Stegra previously raised some 6.5 billion euros ($7.64 billion) in loans and equity. But in recent months, faced with rising project costs and delays, the firm had been urgently seeking additional financing to address a growing cash crunch.
In October, the French hydrogen investor Hy24 swooped in to help fund Stegra for an undisclosed amount. That still wasn’t enough to stave off financial troubles for the steelmaker, which has batted away frequent rumors that the company and its marquee steel mill were close to collapsing.
With the new investment from the Wallenberg-led consortium, Stegra says it will now ramp up construction activities following several slower months during its fundraising period. As of last fall, the plant was 60% complete.
The company says the project’s timeline is now “under review,” though Stegra CEO Henrik Henriksson said it will take about 18 to 24 months to start producing steel once the facility is finished, the Sweden Herald reported.
Before its financial woes began last fall, Stegra was planning to complete the steel mill by late 2026.
“As an industrialist, you get a little sad if you come up to Boden now, because there is a half-finished steel mill that is running at perhaps a quarter of the speed it should be running,” Leif Johansson, an adviser to the investor consortium, said at a press event this week. The funding lifeline should change that.
The news comes four months after the European Union’s world-first carbon border tax went into effect. The policy makes it more expensive for European companies to import steel from countries that don’t have carbon-pricing systems, like the EU does, all of which should benefit domestic low-emissions steel producers like Stegra.
“We are convinced of the competitiveness of Stegra and the commercial attractiveness of green steel in addition to the climate benefits, while remaining clear-eyed about the challenges that lie ahead,” Johansson said in a separate statement. “We also consider the project to be of great importance to Sweden’s position as an industrial nation.”
Green steel proponents applauded the news of Stegra’s financing round, which is expected to formally close in June after undergoing credit and regulatory approvals.
“Stegra securing the future of its Boden green steel plant is a welcome development that signals the change towards truly clean steelmaking at scale is happening,” Caroline Ashley, executive director of the nonprofit SteelWatch, said in an emailed statement.
Xcel Energy in Minnesota is poised to become the first utility in the nation to build and operate its own virtual power plant.
For the past six months, fans and foes have debated the novel plan, which will see Xcel deploy hundreds of megawatts of small-scale batteries at customer sites across its territory. The Minnesota Public Utilities Commission ultimately approved a version of Xcel’s plan last week.
Under the new program, known as Capacity*Connect, Xcel will spend up to $430 million to deploy up to 200 megawatts of batteries, in 1-megawatt to 3-megawatt increments, over the next two years. It’s a rare arrangement: Almost every other virtual power plant program in the U.S. is organized around third-party companies, like solar and battery vendors or specialized “aggregators,” that tap into energy resources installed and owned by customers.
VPPs, which aggregate distributed energy resources to mimic the output of a traditional power plant, are seen as a key way to get more energy onto the existing grid. By using customer-owned energy resources or small-scale batteries, VPPs can help utilities reduce the need to build or dispatch expensive power plants.
But utilities have been slow to embrace VPPs. In particular, they’ve struggled to use VPPs to avoid grid investments, which have become a key driver of rising electricity costs. Utilities are leery of relying on technologies in customers’ homes instead of equipment they control. And utilities earn guaranteed profits for investments in their grids, giving them an incentive to resist examining cheaper alternatives.
Supporters of Xcel’s VPP program say it could finally provide a durable model for utilities to use distributed energy resources to defer costly grid investments and to more fully utilize the existing grid.
For one, the structure gives Xcel an economic incentive to recoup its investment. But more important, it requires Xcel to establish a metric to assess the value that distributed energy resources bring to the grid — something utilities have historically struggled to measure. If Xcel can create a template, then it will have removed a major stumbling block for broad adoption of VPPs.
“Putting a value on DERs of different types and capabilities to avoid or defer distribution upgrades is a real opportunity — and it’s really hard,” said Will Kenworthy, Midwest regulatory director for the nonprofit Vote Solar. “Xcel has said, ‘We need to put a value on this.’ And the way this program is set up, they have an interest in getting that right in a way they never have before.”
That’s not to say supporters think Xcel’s Capacity*Connect program should be the only VPP option in Minnesota. Many, including Vote Solar, have pushed for the utility to allow third-party companies to participate in the program. Some have expressed disappointment that the commission failed to do so, and there’s still no way for solar installers, battery vendors, and demand-response aggregators to enlist their own customers to help the grid in Xcel’s Minnesota territory.
And plenty of industry groups were outright opposed to the commission’s decision last week. The Minnesota Solar Energy Industries Association, Solar Energy Industries Association, and Coalition for Community Solar Access all criticized the plan and the lack of a third-party program.
As Andrew Linhares, Midwest director of state affairs at the Solar Energy Industries Association, said in a statement, “Competitive markets for energy storage deployment ensure that ratepayers get the best, most affordable deal possible. The Capacity*Connect program takes the exact opposite approach.”
The genesis of Xcel’s Capacity*Connect program is a bit unusual.
It didn’t originate in a broader policy push for VPPs but instead came out of Xcel’s integrated distribution planning. Minnesota’s Public Utilities Commission created that regulatory structure in 2018 with the goal of getting investor-owned utilities to “maintain and enhance the safety, security, reliability, and resilience of the electricity grid, at fair and reasonable costs.” Integrating DERs into the grid is one way to do just that.
But integrating DERs into utility planning processes is a whole new territory. Utilities, Xcel included, have not factored these technologies into how they plan out and spend money on their power grids. This means VPPs can’t yet specifically help offset distribution grid investments.
Instead, almost all existing VPPs target reducing peak electricity demand across utilities’ or grid operators’ entire service territories, as “bulk system” assets, Kenworthy said. That can — and does — save money by replacing the energy that would otherwise come from costly “peaker” power plants. That’s helpful, but it’s solving a different problem than distribution grid costs.
Using batteries and other DERs to relieve local grid constraints is a lot more technically challenging than relying on them to shave power demand during peaks. Utilities need to know exactly what stresses are happening at individual substations and distribution grid circuits from minute to minute. And they need far more confidence that the DERs will respond reliably and consistently to relieve those constraints in order to prevent overloads or blackouts.
Beyond a handful of pilot projects in California, Connecticut, Massachusetts, and New York, very few utilities have begun to experiment with using customer-sited DERs to relieve these kinds of pinpoint grid challenges. “We don’t have a way to do third-party substations,” Kenworthy said.
Xcel Energy spokesperson Kevin Coss said that the utility will work with local businesses, commercial and industrial sites, and nonprofits to install batteries “at strategic locations on the grid” to begin to test how each battery can mitigate local grid constraints. “These batteries will help meet increasing demand for electricity, maintain reliable service for our customers, maximize the efficiency of existing infrastructure, and support local jobs.”
Xcel Energy’s plan for paying for those batteries blurs the distinction between bulk-system and distribution-level values, as the utility’s batteries will serve both functions.
Xcel’s Capacity*Connect batteries will earn revenues for the bulk-system energy and capacity services they provide for the Midcontinent Independent System Operator (MISO), the entity that manages the transmission grid and wholesale energy markets across Minnesota and all or part of 14 other Midwestern states.
Those revenues will allow Xcel to pay back almost the entire cost of deploying the batteries, said Will Nissen, director of policy at the Minnesota-based Center for Energy and Environment, a nonprofit that’s in favor of the program. The utility has estimated that the batteries’ deployment and associated software development to manage them will add from 67 cents to $1.50 per year to a typical residential customer’s utility bill through 2030.
That’s key to the longer-term vision of using these batteries to avoid grid investment. Xcel has said it can’t start calculating the distribution-grid value of its batteries until it has had a few years to study them — the MISO revenues will fund this research.
Capacity*Connect will also get a $50 million investment from Google, as part of the tech giant’s broader deal with the utility to cover the energy needs of its new data center in the state.
“The beauty of this pilot is [that] it pays for itself with MISO revenues, while we learn about all the potential distribution value,” Nissen said. “It’s getting those bulk-system benefits while also studying how to use the distribution system as efficiently as possible.”
The commission ordered Xcel to establish specific estimates of the benefits that its batteries could provide to its grid by November 2027, when its next integrated grid plan is due, Kenworthy said. The commission also instructed Xcel to provide quarterly progress reports.
Vote Solar hopes that these provisions will drive the utility to “put a number on what avoided or deferred distribution investment is worth,” he said. “And we can take that to other forums where we’re trying to value DER and say, ‘This is what this device is worth, if we can do that thing.’”
Not all the stakeholders who have weighed in on the Capacity*Connect proceedings are as confident in that outcome, however.
“We really see this decision as a missed opportunity,” said Shannon Anderson, policy director at the nonprofit Solar United Neighbors, which is part of a coalition sponsoring VPP legislation in multiple states. “There’s no reason you can’t do ‘both and’ here — do what Xcel proposed and do a behind-the-meter VPP program.”
In fact, Public Service Co. of Colorado, Xcel Energy’s utility in that state, is currently rolling out a VPP program that will pay third-party companies that equip customers with batteries, smart thermostats, smart water heaters, smart heat pumps, and EV chargers, Anderson said.
In last week’s decision, the commission did order Xcel to report on how its experience in Colorado could apply to its work in Minnesota. But the commission declined to take up a proposal from a group of stakeholders that wanted it to order the utility to lay out a plan for doing something similar.
Nor does it seem likely that Minnesota’s legislature will order the commission to push Xcel to create a VPP program in the near future, Anderson said. Efforts to pass a VPP bill faltered last year, and similar legislation introduced this year has not passed out of a key committee, she said.
But VPP proponents are not giving up, Anderson said. “There are a number of filings coming, a lot of paperwork to evaluate and justify the program,” she said. “This is just the beginning of the conversation from our perspective.”
Tropical forests span 1.6 billion hectares (6.2 million square miles) of Earth. These ecosystems support a majority of the planet’s animal and plant species and contain plants that contribute to over a quarter of modern medicine. But over the past two decades, an average of 10 million hectares (nearly 40,000 square miles) of these forests—roughly the size of Kentucky—have been lost each year, according to the United Nations Environment Programme, affecting the ecosystems and communities that depend on them.
NASA scientists recently developed a new method for tracking tropical forest loss that delivers deforestation alerts more than three months faster than current methods. Although the technique was designed for the Amazon rainforest, data from a recently launched satellite are expected to expand its application globally.
July 22, 2020
Because tropical forests are so vast, local communities, conservationists, and policymakers rely on satellite data to manage them. Images acquired by satellites with optical sensors provide highly accurate alerts. For instance, the image above, acquired as part of the Harmonized Landsat and Sentinel-2 (HLS) project, shows newly cleared land in southwest Brazil in July 2020. Images from NASA-USGS Landsat satellites have revolutionized land management for over 50 years. In 1988, Brazil developed one of its first satellite-based monitoring systems using Landsat data, which remains in use today.
Though Landsat is an invaluable tool for Earth observation, it has a critical limitation: clouds. As an optical satellite, it relies on reflected light and cannot observe the ground through cloud cover. This creates data gaps that are especially limiting in tropical regions, which are cloudy most of the year. In some areas, months can pass without acquiring a cloud-free image, hindering efforts to track and curb unregulated forest clearing.
To address Landsat’s cloud challenge, researchers at NASA’s Marshall Space Flight Center tuned into a different wavelength. Led by Africa Flores-Anderson, associate program manager for NASA’s Ecosystem Conservation Program, the team piloted a system for the Amazon that combines existing satellite-based approaches with cutting-edge radar data. The approach builds upon a platform developed by the Cardille Lab at McGill University.
Synthetic aperture radar (SAR) doesn’t require daylight or clear skies. To generate an image, SAR instruments beam radar signals at a surface and measure the signals that bounce back. SAR satellites use various ranges of radar wavelengths, or “bands,” to measure features on Earth’s surface. Over forests, the shorter wavelengths of the C-band scatter off treetops, but the longer wavelengths of the L-band can make it down to the ground.
This L-band is central to Flores-Anderson’s approach. Similar efforts favored C-band because it was more readily available than other SAR data. But when felled trees—along with their branches and leaves—are not removed right away, C-band’s shorter wavelengths are scattered by remaining debris, obscuring evidence of destruction. In contrast, L-band’s longer wavelengths can penetrate this material and reveal the damage. The new method is the first of its kind to automatically combine the user-friendly, intuitive images from Landsat and the consistent, detailed insights from L-band SAR data.
These visuals show the benefit of combining optical images and L-band SAR data. The patch of deforested land in southwest Brazil (top row) is overlaid with colors that represent the month that deforestation was detected (bottom row).
The left map shows that SAR detected two patches of forest loss in January (purple), three months earlier than optical sensors (middle map). The patches appear small because deforestation happens gradually, Flores-Anderson explained. At that point in January, only those areas had been cleared.
By April (green), optical sensors had detected forest loss across a wider area, shown in the middle map. These sensors collect images every few days, while the SAR data used in this study captured the area only once or twice a month. In this case, the optical satellites observed the change during a break in the cloud cover.
The map on the right shows how the new algorithm combines information from both types of observations. To increase accuracy, this algorithm confirms deforestation only if there are multiple, consecutive observations of forest loss. This view confirms deforestation as early as February, up to two months earlier than optical-only, and with much more certainty than the optical- or SAR-only approaches.
On average, the new method for monitoring forests spots felled trees within 16 days with exceptional accuracy, nearly eliminating false alarms. These detections can identify deforestation in very cloudy regions up to 100 days sooner than optical-only systems.
“In the tropics, it’s important to detect deforestation as soon as it occurs,” Flores-Anderson said. “If an image of a cleared forest isn’t available until the following year, the area may already be regrown, and deforestation will be missing from our data.”
For experts like Sylvia Wilson, the chief forest and climate scientist at Wilpa Capacity Development with nearly 20 years of global forest monitoring experience with the U.S. Geological Survey, adding L-band SAR to optical is a scientific game changer. “L-band SAR gives us the opportunity to see what optical doesn’t,” Wilson said. “But it’s not one sensor versus the other; the future is SAR plus optical."
The NISAR (NASA-ISRO Synthetic Aperture Radar) satellite, launched in July 2025, will drastically increase the feasibility of systems like Flores-Anderson’s by providing more frequent and comprehensive L-band SAR data. L-band data has been relatively scarce, with limited images only available in a few areas like the Brazilian Amazon. Once more NISAR data become publicly available, they will provide free, global L-band SAR every 12 days. Flores-Anderson’s system is already prepared to incorporate this data.
“It doesn’t matter which sensor we get data from—whether it’s optical or SAR—it automatically adds to our model,” Flores-Anderson explained. “As more NISAR data become available, we will have more accurate, faster detection of change.”
NASA Earth Observatory images by Michala Garrison, using MODIS data from NASA EOSDIS LANCE and GIBS/Worldview, the Harmonized Landsat and Sentinel-2 (HLS) product, and model data provided by Flores-Anderson et al. Story by Lena Pransky (EarthRISE) with Jake Ramthun (EarthRISE) and Madeleine Gregory (Landsat Project Science Support).
As carbon dioxide levels hit record highs, scientists are testing new ways to fight climate change by locking it up in our oceans. On assignment for Climate Central, Correspondent Ben Tracy explores groundbreaking experiments using “antacid” chemistry to expand ocean carbon dioxide (CO2) storage and keep it out of our atmosphere.
Remell Bryant fed steel coils into the “cold strip” as a way to support her daughter as a single mother.
Valerie Denney worked on the “pickle line,” removing impurities from hot steel, before shifting to a career in public relations.
Jack Weinberg tested metallurgical content until he was laid off, then went on to negotiate international environmental treaties.
Terry Steagall played on the banks of a polluted river near the steel mill as a child, then spent 41 years inside the mill as a machinist, repairing gearboxes, cranes, and line shafts, before retiring in 2023.
Now, the four are collaborating to demand a shift away from coal-based steelmaking and toward cleaner methods for the Northwest Indiana industry in which they once worked. They’re all members of Gary Advocates for Responsible Development (GARD), a grassroots group founded in 2021 by former steelworker Dorreen Carey.
Such a transition could save thousands of jobs, create new economic opportunities, and avoid about $75 million in healthcare costs in the region, according to a report released Thursday by the Indiana University Environmental Resilience Institute and the consultancy 5 Lakes Energy, and commissioned by Indiana Conservation Voters.
Only six integrated mills — facilities that produce both steel and the iron needed to make it — are operating in the United States, and three of them are in Northwest Indiana. With their hulking, polluting blast furnaces, these mills may soon become a thing of the past in the U.S., as steel is increasingly being produced in smaller and cleaner operations, frequently in the Southern states.
The GARD organizers echo the report’s authors and other industry experts in warning that if Indiana’s mills don’t modernize and clean up, they could go the way of the other steel mills that once proliferated in the region, but were shuttered during the steel industry crisis of the late 1970s and ’80s. The region still hasn’t recovered from that era, and further closures could mean thousands of job losses and gutted public coffers. The report notes that Northwest Indiana’s steel mills once had more than 65,000 workers but employ only about 9,000 today. Without modernization, the study estimates, Northwest Indiana steel mill jobs could fall below 5,000 by 2034.
Converting a traditional integrated mill to much-cleaner direct reduced iron (DRI) technology costs billions of dollars, and the Biden-era incentives that could have encouraged companies to make the switch were eliminated by the Trump administration. It’s a hard sell, but GARD considers global steelmaker Nippon Steel’s 2025 acquisition of U.S. Steel’s Gary Works mill, in Gary, Indiana, an opportunity.
Steagall said he “didn’t see a pathway” to green steel until the Japanese company entered the picture.
Nippon plans to allocate $3.1 billion for upgrades to Gary Works. About $300 million of that will go toward relining its largest blast furnace — which will extend its life for about another 20 years. The company could use some of the remaining money to replace the mill’s three other blast furnaces with a DRI plant, GARD proposes in a recent report.
It would cost about $3.6 billion to transition Gary Works to cleaner steelmaking, according to the Indiana University report. Modernizing the area’s other two mills, both owned by Cleveland-Cliffs, would cost $2.8 billion to $3 billion each. That’s in line with what the companies have indicated they will spend to maintain those operations.
In a February earnings call, Cleveland-Cliffs announced that it is planning to reline an Indiana blast furnace next year. The company had in fact proposed a DRI conversion at one of its Ohio mills, but backed off the plan after Trump took office in 2025.
Advocates note that the crucial technologies needed for green steel — DRI and electric furnaces — already exist at commercial scale, and efforts are gaining steam globally to combine the two. Many existing DRI plants use natural gas, which results in much lower emissions than the coal that fuels blast furnaces. But using green hydrogen — produced by splitting water atoms using renewable electricity — would slash emissions even further.
The national climate research groups RMI and Industrious Labs are also touting the feasibility of greening the nation’s integrated steel mills. An RMI analysis shows that such overhauls cost roughly the same as relining and upgrading existing infrastructure.
The biggest challenge may be convincing company leaders to make a major change in an industry that “has never been known to move quickly,” as Steagall put it.
In an integrated steel mill like Gary Works, iron is added to a blast furnace, where it undergoes chemical reactions involving limestone and coke — a baked-down, concentrated form of coal. Molten iron is then converted to “primary steel” in a separate stage. This process results in the type of high-quality, flat-rolled steel suitable for automobiles and buildings.
But it is highly polluting, with about 2 million metric tons of carbon dioxide released for each ton of steel produced globally, along with high levels of particulate matter, sulfur dioxide, nitrogen oxides, and other pollutants.
The fortunes of Gary Works and other integrated steel mills declined starting in the late 1970s because of slowing demand and competition from abroad, including from “mini-mills,” which use electric arc furnaces to make steel — mostly from scrap metal — without producing any iron on-site. Integrated mills in Indiana, Illinois, Ohio, and Pennsylvania downsized their operations and then closed over several decades, transforming thriving cities into Rust Belt relics. Nationwide, steel sector employment fell from about 512,000 in 1974, according to a study by the National Bureau of Economic Research, to about 85,000 today, according to Federal Reserve Economic Data.
“Republic Steel, Bethlehem Steel, J&L Steel, they all shut down or were liquidated,” said Weinberg, who worked for eight years in Gary Works’ sheet and tin division.
Though the Gary Works mill survived, its workforce was greatly reduced – from more than 30,000 people at its peak in the 1970s to about 4,300 people today. By the 2010s, the city was notorious for its abandoned buildings and urban decay.
As GARD organizers see it, without investments in clean steel, Gary’s fortunes could fall further. The plant’s market niche — high-quality primary steel — is vulnerable to competition from the electric arc furnaces that make at least 60% of the country’s steel today.
Facilities using electric arc furnaces have typically not produced the highest-quality steel, mainly owing to their reliance on recycled steel scrap. But they do still require at least some virgin iron to produce steel, which can come from integrated mills or from on-site DRI facilities. Automakers typically demand steel made in integrated mills, but electric arc furnaces could increasingly compete for that market as their steel quality improves.
Big River Steel, along the Mississippi River in Osceola, Arkansas, is a prime example. Its electric arc furnace uses iron from Gary Works to make high-quality steel. U.S. Steel acquired the mill in 2021, and now it’s part of Nippon’s portfolio. Nippon announced in November that it will build a DRI plant at Big River, which would potentially displace the metal it currently sources from Indiana.
So, such electric arc furnace operations could become competitors, rather than customers, of integrated mills like Gary Works. And they could gain a market advantage if automakers and other industries demand a cleaner supply chain, as GARD and other decarbonization advocates predict.
Nippon lags behind most of its peers globally in its readiness for greening operations, according to a scorecard released March 30 by the international climate advocacy organization SteelWatch. The organization analyzed the decarbonization progress and potential of 18 major steel companies in 29 countries and found that Nippon ranked 17th; U.S. Steel, which was ranked before the acquisition, came in eighth; and Cleveland-Cliffs was sixth. While U.S. Steel could help facilitate Nippon’s decarbonization, SteelWatch said, the plan to reline rather than convert the Gary Works blast furnace represents a “backward trajectory.”
There’s a strong public health argument for greening the mills.
Emissions from blast furnaces are linked to an increase in various cancers, asthma, pulmonary disease, and other ailments. Industrious Labs found that in 2022, Gary Works emitted 182 tons of 24 different toxic chemicals. The health impacts are also a clear environmental injustice: 97% of those living within a three-mile radius of Gary Works are people of color, and almost two-thirds are low-income, according to Industrious Labs’ analysis.
Indiana University’s report found that Gary Works annually emits eight times more carbon monoxide and 50% more particulate matter than the state’s largest coal plant; and the region’s three primary steel mills account for not only the $75 million in healthcare costs but also 27,8000 work days and 26,700 school days lost to illness each year.
GARD member Natalie Ammons did not work in the mills, but her husband did. And she blames the Gary Works blast furnace for his early death from cancer.
Her family’s health problems have continued. Two of Ammons’ granddaughters, both of whom live near the mill, rely on breathing machines that look like scuba apparatus, she said. Modeling done by Industrious Labs using federal algorithms shows up to 114 premature deaths and over 31,000 asthma attacks linked to pollution from Gary Works each year.
Bryant retired from Cleveland-Cliffs Indiana Harbor refinery about four years ago, because she had developed a nodule on her thyroid that impeded her breathing. She attributes it to her exposure to pollution there.
“I was always super healthy. It is odd that happened shortly after I worked a lot of overtime in the lime plant,” she said.
Steagall cites examples like these in calling for Nippon to be “a good corporate citizen” for its American neighbors.
“They’ve got to make their mind up,” he said. “Do they want to be the king of steel or the king of death?”
Nippon has not responded to GARD’s proposals and requests for dialogue nor to a request for comment for this story.
The United Steelworkers union, which the GARD members once belonged to, has similarly not engaged with them. While GARD notes that unions are often reluctant to consider any changes that could disrupt the job market, it warns that the shift to mills in the South with electric arc furnaces could be disastrous for the union — as those plants are typically not unionized. (United Steelworkers did not respond to a request for comment.)
At a recent symposium at Purdue University Northwest, students and faculty clamored to hear more about GARD’s vision for the industry’s future. After the event, the GARD members gathered around a table and reminisced about the jobs they used to do. Their eyes lit up describing the complexities of the steelmaking process.
The metal “runs through a big acid bath, then we cut it to specification,” Denney said of the pickle line where she had worked. “At the end, they oil it, and you have this beautiful, very shiny, gorgeous steel.”
Gary itself could be similarly transformed, through clean steel, she imagines.
“People are used to Gary being kind of a throwaway city,” she said. “It’s all bad. There’s an opportunity for it to be all good now for the first time in a while. Nippon could be part of this change. It could be part of changing Gary forever.”
Maria Gallucci contributed reporting for this article.
A clarification was made on April 2, 2026: This story has been updated to clarify that direct reduced iron plants and electric furnaces exist separately at commercial scale.
Small, sun-driven power plants could soon be coming to backyards and balconies across New England. Lawmakers in all six of the region’s states are considering bills that would allow residents to take advantage of solar panel kits that plug in to standard home outlets, and supporters are optimistic that most — perhaps all — of these measures will succeed.
“As a concept, plug-in solar has a lot of momentum going on right now,” said Connor Yakaitis, deputy director of the Connecticut League of Conservation Voters. “It’s got bipartisan momentum. It’s got interest and intrigue from the utilities.”
Maine’s legislation is close to final passage, and could land on the governor’s desk as soon as next week. Stand-alone measures in New Hampshire and Vermont have each been green-lit by one legislative chamber. Plug-in solar provisions are part of a sprawling energy bill approved by the Massachusetts House of Representatives and working its way through the Senate. In Connecticut, permission for plug-in systems is part of a larger solar bill that has advanced out of a joint committee. Rhode Island’s bill has been held for study by a House committee.
“I am optimistic the bill will get passed,” said Sam Evans-Brown, executive director of Clean Energy New Hampshire, one of the organizations pushing the legislation in the Granite State. “We’re going to be able to come up with language that works for everybody.”
New England is not alone in its enthusiasm for plug-in panels, also commonly called “balcony solar” or “portable solar.” Interest in DIY solar is surging across the country, as escalating energy prices have people — and their elected representatives — searching for ways to lower their bills. Spiking oil prices caused by the Trump administration and Israel’s war with Iran are further heightening cost concerns.
Plug-in solar’s money-saving potential is attracting support from both sides of the aisle. In March 2025, deep-red Utah became the first to authorize the technology. A year later, similar legislation has passed in Virginia and awaits the governor’s signature, and bills are active in more than 20 other states, including some decidedly right-leaning places like Idaho and Oklahoma.
“We think this has taken off because people are thrilled about saving money and having some power to insulate themselves from rising energy bills,” said Cora Stryker, co-founder of Bright Saver, a nonprofit that promotes plug-in solar. “Crucially,” she noted, the legislation “has no fiscal implications. The price tag is zero.”
The matter is perhaps even more pressing in New England, where electricity prices are higher than almost anywhere else in the mainland United States. Homes in the region depend heavily on oil and natural gas for heating, exposing residents to high and volatile fuel prices.
“We are looking for any possible way to bring energy bills down for my constituents,” said Rhode Island state Rep. June Speakman (D), the House sponsor of her state’s balcony solar bill.
Balcony solar has taken off in Europe — most notably in Germany — over the past few years. The systems can be purchased online or from major retailers, like Ikea, and assembled at home. They plug in to a standard exterior outlet and send energy into the wires, rather than drawing electricity out, generally producing about enough power to run a refrigerator.
Plug-in solar systems are modestly sized, which means they can fit into most any sunny spot — from a well-lit backyard to an apartment-building balcony. The kits are relatively low-priced; today, they average about $3 per watt, according to Bright Saver, and the cost is likely to fall by about half once at least five states authorize their use. These prices make them accessible to consumers who can’t afford the upfront cost of rooftop solar panels. Also unlike rooftop solar, these systems can be installed without help from an electrician or approval from a utility company, which means they are an option for renters as well as homeowners.
“It’s not only empowering, but it’s also easy, and it’s so much cheaper,” Stryker said.
In the U.S., balcony solar has inhabited a sort of regulatory gray area, neither prohibited nor expressly authorized by law. The crop of bills working through state legislatures attempts to fix that problem. Provisions vary from state to state, but all the New England measures would allow residents to install systems up to 1,200 watts without utility approval or interconnection agreements. The new rules would also require the solar equipment to be certified by a national safety testing organization, like UL Solutions, which launched a testing program for these systems earlier this year.
In addition to laying out practical rules, these bills could have a more intangible impact, supporters say. They let residents know that plug-in solar is a viable option, not just a questionable technology the internet is trying to sell you.
“Legislation sends a signal that not only is this a thing that’s available on Temu — it’s also a thing you can and should consider buying,” Evans-Brown said.
Illinois could soon follow in the footsteps of Utah and Virginia with a law allowing plug-in solar arrays, often called “balcony solar.”
A bill that would make it simpler to install plug-in solar passed out of the state legislature’s Senate Energy and Public Utilities Committee on March 12. It’s now scheduled for a hearing in the full Senate, and a House committee on utilities is also considering the bill. Advocates are hopeful that the measure will pass both Democratic-controlled chambers this legislative session, which runs through the end of May, and then be signed by the state’s Democratic governor, JB Pritzker.
People are already plugging in these kinds of off-the-shelf small solar arrays to help power their homes, experts say. But legislation would ensure that more people can access the cost-saving clean power. Illinois’ bill would mandate that utilities allow people to plug in solar systems of up to 1,200 watts, without interconnection agreements, fees, or other barriers. That’s about enough energy to run a refrigerator and a few other appliances.
In Illinois, such units could save households up to $400 a year, according to an analysis by the advocacy group Solar United Neighbors, which notes that plug-in solar currently costs about $3 per watt, or about $2,000 for a typical model. Advocates predict that the cost will come down quickly if more states pass plug-in solar laws and the market expands.
More than two dozen other states are considering such bills. The concept has enjoyed bipartisan support across the country, with Utah’s Republican-dominated legislature passing the first law in March 2025. The Virginia legislature passed its law by a unanimous vote on March 11. Illinois’ red-state neighbors — Indiana, Iowa, and Missouri — have also introduced bills.
The momentum comes as affordability concerns mount nationwide. Electricity prices have spiked in many parts of the country, driven by factors including extreme weather and wildfires, natural gas price fluctuations, and the cost of infrastructure to get power where it’s needed. In Illinois, customers are seeing their bills rise sharply because of increasing electricity demand that is driven in part by data centers.
Illinois’ plug-in solar measure would go a step further than most by stipulating that homeowners’ associations and landlords could not enact rules, fees, or insurance requirements around arrays of 391 watts or less, proponents say. This would ensure that renters and condominium owners could take advantage of the option.
Despite the fast-growing enthusiasm for plug-in solar, some bills, like one in Wyoming, have failed. Utilities have raised safety concerns, such as danger to lineworkers if the arrays don’t shut off during power outages and continue sending electricity onto the grid, or a home’s electric system becoming overloaded.
Plug-in solar proponents note that safety concerns can be managed, especially through legislation that requires specific certification, as the Illinois bill does.
“This is a disruptive technology to the American market, and all disruptive technologies are good for the consumer and bad for the power structures,” said Cora Stryker, who co-founded the nonprofit organization Bright Saver last year to sell affordable plug-in solar kits. “We believe these are strategic efforts to confuse legislators and the public, but the real motivation is the threat to the business models of very powerful entities.”
The Illinois bill would mandate that plug-in solar systems not send any electricity into the home when the larger grid has an outage. That means the panels wouldn’t help during a blackout unless paired with a battery, but they would avoid harming lineworkers. Arrays that are commercially available already typically include such safeguards as part of the built-in microinverter.
The Illinois bill would also require that plug-in units be certified by UL Solutions (formerly Underwriters Laboratories) or an equivalent entity.
Hannah Birnbaum, co-founder and chief of advocacy at the nonprofit Permit Power, which focuses on reducing the bureaucracy involved in getting rooftop solar, said that it’s crucial to pass laws that include these sorts of safety provisions. Otherwise, people will continue to install unregulated systems, she said.
In California, for example, customers are already “quietly” using portable solar panels — even though the state has yet to pass the plug-in solar bill it’s considering.
“The real risk is inaction,” Stryker said. “Now there’s so much enthusiasm for plug-in solar, people are buying whatever systems they can get. It’s a regulatory gray area.”
In Illinois, utilities have thus far not raised opposition. ComEd spokesperson David O’Dowd said the utility does not have a position on the bill. Ameren did not respond to a request for comment.
Should the bill pass in Illinois, it would add to the state’s already robust incentive program encouraging residents, businesses, churches, schools, and other nonprofits to get rooftop solar. Clean energy advocates say plug-in solar provides a more affordable and convenient option, and one that’s accessible to both renters and those whose homes aren’t conducive to rooftop solar.
“It’s an untapped resource” in meeting larger clean-energy goals, according to Nick Johnson, an associate professor of sustainability and economics at Principia College in southwestern Illinois. Johnson was among over 100 residents who filed witness slips with the legislature in support of the bill.
“It’s a drop in the bucket for what we need, but every little bit helps,” he added.
In Germany, more than a million households have plug-in solar — a fact often underscored by advocates trying to popularize the technology in the U.S., where it’s still in the early stages. Even in Utah, only a few thousand households have plugged in the devices since they became legal.
Advocates expect the systems will take off once more states make it simpler for people to adopt them.
For her part, Kavi Chintam, Illinois campaign manager for the advocacy group Vote Solar, said she plans to put a plug-in solar array in her yard after the law passes. Her mother wants a solar array on her balcony, to power her TV.
“At a time when electricity prices are rising and rising, it gives an option for people to shave off some of that cost,” Chintam said. “There is something really empowering about seeing a panel you installed on your home. As the market expands, there will be more opportunities for people just to see these things out and about.”
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