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London, 7 October 2025 – Solar and wind outpaced the growth in global electricity demand in the first half of 2025, resulting in a very small decline in both coal and gas, compared to the same period last year. New analysis from Ember shows that record solar growth and steady wind expansion are reshaping the global power mix, as renewables overtake coal for the first time on record.
“We are seeing the first signs of a crucial turning point,” said Małgorzata Wiatros-Motyka, Senior Electricity Analyst at Ember. “Solar and wind are now growing fast enough to meet the world’s growing appetite for electricity. This marks the beginning of a shift where clean power is keeping pace with demand growth.”
Global electricity demand rose 2.6% in the first half of 2025, adding 369 TWh compared to the same period last year. Solar alone met 83% of the rise, thanks to record generation growth in absolute terms (306 TWh, +31% year-on-year).
Solar and wind grew quickly enough to meet rising demand and start to replace fossil generation. Coal fell by 0.6% (-31 TWh) and gas by 0.2% (-6 TWh), only partly offset by a small rise in other fossil generation, for a total decline of 0.3% (-27 TWh). As a result, global power sector emissions fell by 0.2%.
For the first time ever on record, renewables generated more power than coal. Renewables supplied 5,072 TWh of global electricity, up from 4,709 TWh in the same period in 2024, overtaking coal at 4,896 TWh, down 31 TWh year-on-year.
The 0.3% (-27 TWh) drop in fossil fuel generation was modest but significant, indicating that wind and solar generation are growing quickly enough that in some circumstances they can now meet total demand growth. As their exponential rise continues, they are likely to outstrip demand growth for longer and longer periods, cementing the decline of fossil generation.
The world’s four largest economies – China, India, the EU and the US – continued to shape the global outcome.
China and India both saw fossil generation fall in the first half of 2025 as clean power growth outpaced demand. China remained the leader in clean energy growth, adding more solar and wind than the rest of the world combined, helping to cut China’s fossil generation by 2% (-58.7 TWh) in the first half of 2025.
In the same period in India, growth in clean sources was more than three times bigger than demand growth. However, demand was exceptionally low at 1.3% (+12 TWh), compared to the same period last year at 9% (+75 TWh).
India’s record solar and wind expansion, combined with lower demand, drove down fossil fuels in the country, with coal falling 3.1% (-22 TWh) and gas 34% (-7.1 TWh).
By contrast, fossil generation rose in the US and the EU. In the US, demand growth outpaced clean power, driving up fossil generation. In the EU, weaker wind and hydro output led to higher gas and coal generation.
With half the world already past the peak of fossil generation, Ember finds clean power can keep pace with rising electricity demand, but progress is uneven. In most economies, faster deployment of solar, wind and batteries could bring benefits.
This analysis confirms what we are witnessing on the ground: solar and wind are no longer marginal technologies—they are driving the global power system forward. The fact that renewables have overtaken coal for the first time marks a historic shift. But to lock in this progress, governments and industry must accelerate investment in solar, wind, and battery storage, ensuring that clean, affordable, and reliable electricity reaches communities everywhere.
-- Sonia Dunlop
CEO, Global Solar Council
We are seeing the first signs of a crucial turning point. Solar and wind are now growing fast enough to meet the world’s growing appetite for electricity. This marks the beginning of a shift where clean power is keeping pace with demand growth. As costs of technologies continue to fall, now is the perfect moment to embrace the economic, social and health benefits that come with increased solar, wind and batteries. As costs of technologies continue to fall, now is the perfect moment to embrace the economic, social and health benefits that come with increased solar, wind and batteries.
-- Malgorzata Wiatros-Motyka
Senior Electricity Analyst, Ember
California lawmakers managed to pass a slate of bills aimed at controlling the state’s high and rising electricity costs in the final days of the legislative session this month. But the last-minute negotiations left one key money-saving measure on the cutting-room floor — continued funding for what might be the world’s largest virtual power plant.
Now, companies like Sunrun and Tesla that have enrolled tens of thousands of customers in that VPP program don’t know if they can pay them to participate next year, because it’s unclear if any other state funding can be cobbled together. If not, they’ll have to put those customers on hold — and California could lose hundreds of megawatts of cost-effective grid relief.
Lawmakers “are consistently undervaluing what distributed solar and storage can deliver for the system,” said Kate Unger, senior policy advisor for the California Solar and Storage Association, a trade group that supports the program. “We find this to be very shortsighted and frustrating, because DSGS is a cost-saving measure.”
DSGS stands for the Demand Side Grid Support program, which pays utility customers to help relieve costly peaks in electricity demand during extreme events like heat waves. They do this by cutting their own power consumption with devices like smart thermostats or by feeding extra power to the grid from backup batteries that have been charged by rooftop solar. Customers have already installed and paid for those systems, so making use of them is cheaper than building new power plants or grid infrastructure to manage those peaks.
DSGS has grown quickly since its 2022 launch to more than 1 gigawatt of grid-relief capacity, Unger said, about 700 megawatts of that from batteries in homes and businesses, which can be deployed rapidly. That’s much bigger than other similar programs in the state.
Backers say that’s because DSGS, which is administered by the California Energy Commission, is far less onerous for participants than VPP programs run by the state’s utilities.
It’s also more cost-effective, according to an August analysis from consultancy The Brattle Group. That report, which was commissioned by Sunrun and Tesla, found that solar-charged batteries in DSGS could deliver between tens of millions and hundreds of millions of dollars in net savings to all California utility customers over the next four years. Those projected savings are predicated on the program nearly doubling its current capacity, which is a credible goal given that California residents are adding backup batteries in increasing numbers.
But instead of expanding its funding to achieve that growth, state lawmakers cut it this year in the face of budget shortfalls, just like they did last year. A provision that lawmakers inserted in August into a bill reauthorizing the state’s greenhouse-gas cap-and-trade program would have provided DSGS with a stable funding stream into the middle of next decade, but it was stripped from the bill that emerged from closed-door negotiations between Gov. Gavin Newsom (D) and legislative leaders days before it was passed. That leaves DSGS with a dwindling pool of previously committed funding that is very likely to be depleted this year.
The remaining budget currently stands at about $64 million, according to the program administrator. DSGS would need at least $75 million more to continue operating in 2026, according to a letter sent to California lawmakers in August by dozens of companies, trade groups, and advocacy organizations.
DSGS backers are hoping the program might be able to secure a slice of the $1 billion in reserves to be disbursed annually from the state’s newly reauthorized cap-and-trade program. But Unger warned that competition for that money will be fierce — and lawmakers won’t make decisions on that spending until next year.
Without new funding, companies that have been active in DSGS will likely have to tell their customers they won’t be able to participate in 2026, said Brad Heavner, executive director of the California Solar and Storage Association. “How do you put your customers in a program if you don’t know they’ll get paid?”
The failure to fund DSGS is particularly frustrating, Heavner said, because it’s the rare example of a successful virtual-power-plant program in the state. Though California has ostensibly prioritized VPPs, it has little else to show for its efforts.
For more than a decade, the state has required its major utilities to incorporate rooftop solar systems, backup batteries, smart thermostats, and other distributed energy resources (DERs) into their grid operations and planning. But utilities have done very little to actually tap these devices beyond launching pilot projects (and terminating many of them), even as the number of DERs in the state has grown dramatically. A June progress report from the California Energy Commission found the state has barely expanded its demand-side capacity over the past two years, and remains far from hitting its goal of 7 gigawatts by 2030.
“California is really excellent at deploying DERs, but really lags in DER utilization,” said Gabriela Olmedo, regulatory affairs specialist at EnergyHub, a company that manages demand-side resources and virtual power plants in the U.S. and Canada. Many of those programs have grown to play a significant role in reducing stress on utility grids during peak demand, she said, including a large-scale initiative in neighboring Arizona. But California’s “fractured, overlapping, and confusing load-flexibility programs really preclude scale,” she said.
DSGS, one of many programs created in response to California’s grid emergencies in 2020 and 2022, has broken that pattern, said Ben Hertz-Shargel, global head of grid-edge research for analytics firm Wood Mackenzie and lead author of a recently released report on virtual power plants. In particular, DSGS has avoided the types of problems that have limited customer participation in other VPP programs, he said.
First, under DSGS, customers can be paid for sending power to the grid from their home batteries that have been charged up by rooftop solar, he said. Most other VPPs in California only allow homes to reduce their consumption from the grid to zero, not to send power back to the grid. That’s a legacy of these programs’ genesis as traditional demand-response offerings that reward customers for reducing power use.
DSGS is also superior to the Emergency Load Reduction Program (ELRP), the other large-scale VPP program created as a response to California’s grid emergencies, Heavner said. One of the biggest differences is that ELRP is triggered only during specified grid alerts, warnings, or emergency declarations by the California Independent System Operator, which manages the state’s energy markets. Those emergencies are relatively rare, so participants are idle most of the time.
DSGS, by contrast, is triggered whenever wholesale prices on the state’s transmission grid exceed a threshold of $200 per megawatt-hour, so it plays a more active role in suppressing the price spikes that drive up costs for utilities and customers, Heavner said.
DSGS is also open to customers of all utilities in the state, unlike ELRP and most of the state’s other VPP programs, which are managed separately by each of California’s three large investor-owned utilities. Companies that have participated in both sets of programs say it’s easier to sign up customers and get them paid promptly under DSGS than under utility-managed efforts.
A set of laws passed this year instructs state regulators to develop new VPP plans and programs, which could augment the current limited options. But “it will take years to establish that,” Heavner said. Meanwhile, “companies that have invested in dynamic grid response are left holding the bag right now.”
California may miss out on big money-saving opportunities as a result, he said. A 2024 analysis from The Brattle Group found that VPPs could shave more than 15% of the state’s peak demand by 2035, saving utility customers about $550 million each year.
The loss of funding for DSGS is particularly galling given the scale it has achieved, Heavner said. In a July test of the DSGS and ELRP programs, California’s three major utilities were able to dispatch about 540 megawatts of power from Sunrun and Tesla batteries, in what utility Pacific Gas & Electric described as “the largest test of its kind ever done in California — and maybe the world.”
Most of those batteries were enrolled in the DSGS program. Sunrun batteries alone accounted for at least 360 megawatts of capacity. As Sunrun CEO Mary Powell pointed out in a LinkedIn post, that’s more capacity than many of the state’s fossil-gas power plants provide.
Sunrun had enrolled more than 56,000 customers with solar-battery systems to participate in California VPP programs as of May, the majority of them in DSGS. The company offered participants up to $150 per battery enrolled in the 2025 season.
“We are concerned that California is walking away from its leadership position running the largest and most successful distributed power plant in the country,” Lauren Nevitt, Sunrun’s senior public policy director, told Canary Media.
Community solar has thrived in Illinois, thanks to clean-energy laws passed by state legislators in 2016 and 2021. Now, though, one major utility’s especially slow process for reviewing applications could jeopardize further progress. Developers stuck in the interconnection queue may not be able to access key federal tax credits that were sent to an early grave by the GOP’s One Big Beautiful Bill Act.
The beauty of community solar is that it allows anyone, even those who can’t put photovoltaic panels on their own properties, to access solar energy via subscriptions to a larger array sited elsewhere. Until congressional Republicans passed their budget law this summer, the companies building community solar could tap federal tax credits into the 2030s; now, projects must begin construction by July 2026 or be placed in service by the end of 2027 to qualify.
Before any power-generating project can connect to the grid, it needs to undergo a lengthy review. Utilities must determine the project’s viability and the cost of grid upgrades that it might require, which the developer usually pays for and needs to know ahead of time to secure financing. Though the process is notorious for taking too long, the actual length of time a proposal spends in this interconnection queue can vary greatly depending on the utility.
Advocates are calling out Ameren, which serves central and southern Illinois, for taking longer than the norm. One major reason is that the utility only studies community solar applications one at a time. At that rate, it takes years or even decades for proposals to be reviewed and ready for construction.
By contrast, ComEd, the utility that serves northern Illinois, reviews multiple project proposals concurrently and “typically performs hundreds of studies every month,” according to the ComEd team that specializes in interconnection and distributed energy resources.
Ameren currently has over 1,700 projects pending review in its interconnection queue, the vast majority of which are community solar, according to Ameren spokesperson Marcelyn Love.
The utility is moving toward studying proposals concurrently, like ComEd does, but the policy won’t be fully in place until January 2027, said Love. That’s too late for projects depending on the federal tax credit to make their finances work.
“I think we’ll see a lot of projects that can’t meet these deadlines and just fall off,” said Jessica Collingsworth, central policy director for Nexamp, a community solar developer with headquarters in Chicago and Boston. “Every developer is trying to start construction on as much as possible.”
Illinois currently ranks among the top five states for community solar capacity. Illinois lawmakers kick-started this development in 2016, when they created a state program now called Illinois Shines to incentivize development of the shared arrays.
About 768 megawatts of community solar are already operating statewide, according to a report by consultancy Wood Mackenzie and the Solar Energy Industries Association, a trade group. But far more proposals are pending, meaning Ameren and ComEd have needed to quickly figure out how to add increasing amounts of community solar to their grids.
ComEd now has about 200 community solar projects totaling more than 430 MW of generation in its territory, according to utility spokesperson David O’Dowd. In 2025 so far, the utility has received 442 requests for new community solar projects. It is dealing with about 750 pending applications in all, including around 80 that have interconnection agreements but are awaiting a customer signature, O’Dowd said.
Even with the glut of applications, ComEd said it has managed to complete interconnection studies and agreements in a timely fashion, in part because it studies projects concurrently.
Developers agree with that assessment. Nexamp, for example, “has experience in over a dozen markets and finds concurrent studies to be the fastest way to get local solar to the grid,” Collingsworth said. The firm has 31 community solar projects operating in ComEd territory and a number of proposals pending in Ameren territory.
“We need certainty around interconnection costs before we can feel confident beginning construction on projects,” said Collingsworth. “Anything that delays getting that certainty is a problem we need to solve quickly.”
Love said that Ameren is increasing its “internal and contractor resources” to be able to do multiple studies at the same time — in other words, the utility is bringing on more experts to review proposals.
“These improvements have already helped us advance 20 applications that were second in line, allowing us to both test out the concurrent study process and get more applicants information about their projects,” she said.
But the utility must balance the benefits of hiring more people to do the studies with the costs for those hires, which customers will ultimately pay for in their bills, she added.
Ameren is also working to address other reasons for interconnection delays.
For example, sometimes the utility spends a lot of time reviewing a project, only to ultimately decide it cannot be approved at all. To avoid this unnecessary use of resources, Love said Ameren is “studying the limits of what different circuits and substations on the grid can handle, to be able to more quickly predict when an application for connecting community solar in that area will be denied because the grid has reached its maximum capacity.”
The utility is “redesigning our approach to identify projects that have a high propensity for approval,” Love added, so that agreements can be signed more quickly, leaving detailed cost analyses until later in the process.
This means that Ameren “can get more projects through the pipeline and avoid spending time and resources on applications that are unlikely to move forward, due to high costs or other factors,” Love said.
Collingsworth said that more information and transparency from the utility make developers’ jobs easier, since they know which proposals to prioritize.
Love said Ameren has made maps and queue reports more user-friendly, so that developers will have a better idea of which projects are worth pursuing. The utility is also offering companies “a one-time opportunity to reduce the size of their project to help manage anticipated interconnection costs,” Love said, meaning that developers can change their proposal without having to resubmit it and lose their place in line.
While delays have not been a major problem in ComEd territory, according to developers, the utility has also taken steps to reduce interconnection wait times. It is allowing the use of a letter of credit or escrow account instead of cash as the deposit needed before construction can begin, and it is connecting developers seeking to do projects on the same part of the grid, so they can potentially collaborate to reduce costs.
A clean-energy bill that state legislators may consider during an October veto session aims to hasten the interconnection process across Illinois. The legislation would create a working group composed of utilities, developers, and other stakeholders that would report to the Illinois Commerce Commission, the body that regulates energy.
The state’s 2021 clean-energy law called for an interconnection working group, but “it hasn’t been a very productive space,” Collingsworth said. The newly proposed committee would be required to study and report to the Commerce Commission on certain issues, including interconnection timelines, cost-sharing between developers, and ways to create more transparency around the process. The Commerce Commission could then codify such concepts as binding rules and policies.
While the bill’s passage likely wouldn’t help projects meet the July 2026 construction-start deadline for federal tax credits, Collingsworth said it is important for the future of community solar in Illinois. Along with establishing the interconnection committee, the legislation would create a virtual power plant program, providing extra revenue to battery-equipped community solar projects that send power to the grid at times of peak demand.
Professionals in the solar industry said that the impending loss of federal tax credits underscores the importance of such state-level programs and policies.
“The tax credit is a key economic driver in Illinois, and without it, there is a much larger need for the incentives in the Illinois Shines program to fill the gaps,” said Nick Theisen, director of business development for TurningPoint Energy, which has more than 40 community solar projects built or in the works in Illinois, all in ComEd territory.
Andrew Linhares, who leads Midwest policy work for the Solar Energy Industries Association, echoed Theisen’s sentiment. “The bottom line is that state-level leadership on clean energy is more important than ever as federal policies and red tape are raising energy prices and making it harder to meet rising energy demand.”
For nearly a century, the Kelley’s Falls Dam in Manchester, New Hampshire, generated as much as 2,400 megawatt-hours of electricity per year. When the small hydroelectric station in a downtown park came up for relicensing in 2022, its owners faced what many dam operators now expect when trying to extend the lifespan of these power generators: strict requirements that would force them to spend millions on upgrades to qualify for a new operating permit. Instead, Green Mountain Power made a choice that has become common among hydroelectric operators. The utility simply surrendered its licenses.
Last year, the plant shut down.
Nearly 450 hydroelectric stations totaling more than 16 gigawatts of generating capacity are scheduled for relicensing across the United States over the next decade. That’s roughly 40% of the nonfederal fleet (the government owns about half the hydropower stations in the U.S.). The country is now on the verge of a major shift in hydropower. The facilities could be relicensed to supply the booming demand for electricity to power everything from data centers to aluminum smelters. Tech and industrial giants could even help pay for the costly relicensing process with deals like the record-setting $3 billion contract Google inked with hydropower operator Brookfield Asset Management in July for up to 3 gigawatts of hydropower. Or, as has been happening for years, the U.S. could continue to lose gigawatts of power as hydroelectric facilities shut down rather than absorb the high costs of relicensing — especially with cheaper competition from gas, wind, and solar.
The fleet of dams that helped electrify the nation starting in the late 1800s provides the second-largest share of the country’s renewable power after wind, and by far its most firm. But the average age of U.S. dams is 65 years, meaning the bulk of the fleet wasn’t built with newfangled infrastructure to enable unobstructed passage for fish and other wildlife. As seen in New Hampshire, the cost of upgrading facilities to allow for that passage can soar into the tens of millions of dollars — on top of the expense of upgrading custom-built equipment for each plant. Complicating matters further, after decades of decline in the hydropower sector, the manufacturing muscle for turbines and other hardware that make a dam work has largely atrophied in the U.S.
The biggest obstacle to a hydropower comeback may be the relicensing bureaucracy. The problem is that the Federal Power Act — passed in 1920 to regulate hydroelectric facilities — does not give any single agency full authority over hydropower the way the Nuclear Regulatory Commission has over atomic energy. The Federal Energy Regulatory Commission issues the key permits on the national level, but other agencies also play a role. The Fish and Wildlife Service, for example, may require a National Environmental Policy Act review to examine a dam’s effects on a specific fish species, a process that involves assessing multiple spawning cycles. And once that’s done for salmon, the agency may undertake yet another multiyear study on trout. FERC, meanwhile, can’t issue its licenses until state agencies overseeing waterways approve permits. That alone can eat up years.
As a result, it takes eight years on average to relicense an existing hydropower facility, according to the National Hydropower Association, the leading U.S. trade group. That’s more than five times slower than licensing for the typical atomic power station. (Nuclear, hydroelectricity’s closest competitor for clean, always-available power, is also notorious for its slow permitting timeline.)
“It takes longer to relicense an existing hydro facility than a new nuclear facility,” said Malcolm Woolf, the National Hydropower Association’s chief executive. “It takes just 18 months to get a new license for a nuclear plant.”
With no central body in charge of permitting hydropower plants, multiple state agencies have been known to take advantage of the once-in-a-generation certification process — eliciting support for tangentially related projects from dam owners who once represented a big and growing business.
“This is major infrastructure. These facilities cost billions of dollars,” Woolf said. “They’re like bridges and roads. They get a license for 50 years. The state agencies view [the relicensing process] as an opportunity to extract concessions from what they view as a deep pocket.”
At times, those concessions have little to do with the functioning of the hydropower plant itself. Woolf cited examples of dam owners pressed to build an amphitheater for Boy Scouts, and to fund the construction of regional roads that wouldn’t even go to the plant.
“One … regulator was requiring a facility to pay for a feral-pig-eradication program,” Woolf said.
“In the 1970s, maybe the industry was a deep pocket,” he added. “But now, with the low cost of other fuels like wind and solar and gas, it’s driving these facilities to bankruptcy and to surrender licenses.”
The eight-year timeline for relicensing is just an average.
In Idaho, the Hells Canyon hydroelectric plant has gone for 20 years without a permanent license. In Maryland, the Conowingo Dam’s relicensing process has also stretched on for two decades. In Massachusetts, the Northfield Mountain plant is in the middle of a 15-year permitting slog.
To continue operating, hydroplant owners obtain one-year extensions as they inch toward full licenses. “But if they don’t have a long-term license,” Woolf warned, “they’re not about to invest millions in upgrades.”
One potential bright spot in the relicensing quagmire has been a shift in federal tax policy. For years, the wind and solar industries have benefited from a rule that treats facilities as new if owners reinvest at least 80% of the plant’s market value into upgrades like new turbines or panels, making them eligible for bigger federal write-offs. In January, the Biden administration’s Treasury Department granted hydroelectric facilities the same flexibility.
But so far, no hydroelectric facility has made use of the federal investment tax credit except one small plant that was destroyed in a flood, thus requiring a total reconstruction. That’s because until recently the industry still lacked clear guidance on how to apply the tax credit.
“The question in the hydropower industry was, if you think of the Hoover Dam, is it 80% of the electric generating equipment? Or 80% of the whole Hoover Dam and the reservoir? So that’s what the Treasury clarified,” Woolf said. “It’s 80% of the electric generating equipment. So if you replace a 50-year-old generator with a new generator, you’re going to satisfy that.”
While renewables face ongoing opposition from the Trump administration, the president specifically named hydropower as a key priority in his Day 1 executive orders on energy. In July, Donald Trump signed the One Big Beautiful Bill Act, preserving hydropower’s access to key federal tax credits for the next eight years. If a hydro project is built in a designated “energy community” and uses domestically manufactured equipment, the tax credit can cover as much as half the investment.
Providing safe passage for fish through dams is a perpetual challenge, especially at older facilities that lack proper infrastructure. But dams that have been updated with newer, thinner turbine blades are also an issue, as the blades become guillotines for trout and salmon navigating through. American eels pose an even greater problem, as the snake-like fish — which can make up as much as half the biomass in rivers across the country — migrate downstream to spawn as breeding-age adults.
One of the simplest and most widely used tools to prevent fish from being killed in a dam’s turbines is a screen that blocks them from entering the plant’s water intake. Other methods include fish ladders or elevators that allow wildlife to ascend rising water to reach the other side. Less practical are trap-and-haul systems where fish are manually captured and set free above the dam.
“Fish-passage solutions can be extraordinarily expensive,” said Jennifer Garson, the former director of the Department of Energy’s Water Power Technologies Office. “The problem is the burden falls completely on hydropower operators to make these upgrades.”
The key to overcoming the issue may be marrying the refurbishment of hydropower stations with environmental upgrades. In 2019, the startup Natel Energy, which designs fish-safe hydropower turbines, installed its pilot project in Maine, then another in Oregon the following year. Natel’s technology — based on thicker blades that don’t sever fish as they move through the dam — was validated by the Pacific Northwest National Laboratory. The company won $9 million from the Energy Department to scale up its supply chain.
While the fish-safe blades are thicker than traditional turbine blades, Natel claims that its equipment is more efficient than the older equipment it’s replacing. Compared with turbines that are nearly 40 years old, CEO Gia Schneider said, the new Natel units produce more electricity per spin on average.
“They’re going to modernize, get fish-safe turbines that will safely pass eel, salmon, and herring that need to go through the plant, and they’ll get 5% more energy,” Schneider said.
Even replacing newer blades comes with little loss in efficiency.
“At another plant where we’re working on the design, the turbines are pretty young – only installed 10 years ago,” she said. “There, we’re going to get maybe 0.2% less energy out.”
On balance, Schneider noted, plant owners get more out of the facility, because even with new traditional turbines, dams require very fine exclusion screens and other equipment that restrict water flow enough to reduce energy output by anywhere from 5% to 15%.
“You’re losing a lot more from these bolt-on solutions,” she said. “At the end of the day, if you get 0.2% less on the turbine side, … on the whole-plant level, you’re coming out ahead.”
At the moment, hydropower finds itself in a similar position to that of nuclear energy a few years ago, where existing facilities risk closure due to relicensing costs amid competition from cheaper newcomers. The U.S. is now actively looking to restart its nuclear program, with the once far-fetched prospect of new large-scale reactors under serious consideration. Even if hydropower can similarly flip its fortunes, few in the industry anticipate an appetite in the U.S. for a Hoover Dam–size project. Still, there is ample opportunity for new hydroelectric capacity.
Just 3% of the nation’s 80,000 dams generate electricity. In 2012, an Energy Department report found that the U.S. could add 12 gigawatts of new power by overhauling those facilities to produce electricity. More than a decade later, “none of it was built,” Woolf said.
There are plenty of hydropower critics who welcome that stagnation. The history of damming rivers is rife with ecological destruction that fish-passage routes don’t entirely solve, as well as social upheaval from land seizures that uprooted poor, Black, and Indigenous communities from their homes to make way for new reservoirs.
And in parts of the U.S. where water is growing more scarce as the climate warms, reservoirs are drying up. Hydropower output in the American West hit a 22-year low last year after below-average snowfall, according to analysis by the Energy Information Administration. Yet other parts of the U.S., such as the Northeast, are getting wetter as the planet heats up.
While debate over hydropower continues in the U.S., nations overseas are moving ahead with new dam projects. In July, China started construction on what will, upon completion, be the world’s largest power station, a giant hydroelectric facility in Tibet. Last month, Brazil held its first auctions for new small- and medium-size dams with hopes of turning $1 billion in investments into more hydroelectricity. And Ethiopia just opened its megadam project meant to alleviate electricity issues in the country, despite pushback from Egyptians who say the facility could negatively impact the flow of water on the Nile.
The U.S. could get in on the game, or at least work to clear away hurdles preventing the country from taking advantage of the infrastructure that already exists. As the Trump administration looks to re-shore heavy industry through tariffs, Woolf said, “hydropower is a great resource for colocating manufacturing because you’ve got energy infrastructure and you’re typically in fairly rural areas where land is less expensive.” For data centers, reservoirs could offer the additional service of providing water for cooling hot computer servers, along with electricity. And when the U.S. still had 33 operating aluminum smelters in 1980, many of them relied on publicly owned hydropower facilities to provide cheap power. These plants could, in theory, play that role again as new demand for domestically produced aluminum — to manufacture electric vehicles and clean-energy equipment — puts strain on the remaining six smelters.
“We know we’ve got load growth. We know we’ve got grid variability from renewables and extreme weather. The flexibility of hydropower offers clean, firm generation that is unique,” Woolf said. “At the same time — through quirk of history — we’ve got so much of the fleet at relicensing and at risk of surrendering permits. This could be an amazing opportunity.”
See more from Canary Media’s “Chart of the week” column.
Globally, investors are pouring more money into renewable energy than ever — even as they pull back on spending in the U.S.
Over the first six months of this year, a total of $386 billion flowed to projects ranging from small rooftop solar installations to massive offshore wind farms, according to research firm BloombergNEF. That’s 10% higher than what investors doled out in the first half of 2024.
But the story is very different when you zoom in on the U.S.
As President Donald Trump enacts a scorched-earth campaign against renewables — particularly offshore wind — clean-energy investors are fleeing the nation’s increasingly volatile market. Spending was down by 12% compared to the first half of last year.
To an extent, the U.S.’s loss may have been Europe’s gain, according to BNEF. The European Union saw investment jump by 27% in the first half of this year, due in large part to major offshore wind developers shifting their focus from beleaguered projects on America’s East Coast to those in Europe’s North Sea. In the U.K., another offshore wind hot spot, investment tripled compared to the first half of last year, rising to $6.6 billion.
That increasing interest in erecting turbines in European waters helped buoy global investment figures. The offshore wind sector may be crumbling in the U.S. under Trump, but worldwide, it attracted more money in the first six months of this year than in all of last year.
Small-scale solar is also quickly gaining ground, especially in China, where investment in the energy source almost doubled even as funding for utility-scale solar fell by 28% due to policy changes that make those larger projects less lucrative.
Overall, the investment figures are trending in the right direction: up. But the growth remains sluggish compared to the blistering pace needed for the world to shift away from planet-warming fossil fuels.
This week, the Trump administration announced its most ambitious pro-coal plans yet — a multipronged effort to resuscitate the industry, despite the financial, health, and climate case against doing so.
The administration’s Monday announcement included three big pledges: The Department of Energy promised $625 million to prop up coal power plants, the Interior Department will open up 13 million acres of federal land for coal mining, and the EPA is delaying seven deadlines related to wastewater pollution from coal plants.
That promised DOE funding includes $350 million for recommissioning or modernizing coal power plants — an indication that the DOE will continue to force such facilities to stay open past their prime. The administration has already kept Michigan’s J.H. Campbell plant open for months beyond its planned retirement in May, racking up $29 million in costs to utility customers in just five weeks. At that rate, the plant would cost consumers $279 million each year to keep open, according to a recent Grid Strategies report.
J.H. Campbell is just one of roughly 30 coal plants that are supposed to retire through the end of 2028, when President Donald Trump’s term ends. Keeping them and other aging fossil-fuel plants open past their planned retirement could cost consumers as much as $6 billion each year, per Grid Strategies.
There’s a cheaper, and not to mention cleaner, way forward: According to a 2023 Energy Innovation report, every single soon-to-retire coal plant could be replaced with solar panels, wind turbines, and battery storage at a net savings to consumers. The rollback of clean-energy tax credits weakens that calculation, but renewables remain the cheapest, quickest way to add new power generation to the grid.
The Interior Department’s expansion of coal mining lands, meanwhile, ignores the fact that coal production has tanked in the U.S. since its peak in 2008, and that coal plants are already well stocked as it is.
And then there’s the administration’s focus on coal-plant wastewater — a critical piece of the industry’s operations, as burning coal produces coal ash, which can contaminate groundwater with deadly toxins. The Biden administration’s EPA had cracked down on loopholes that let power-plant operators avoid responsibility for these pollutants. Monday’s actions are among the Trump administration’s latest efforts to undermine those rules and let coal-plant owners off the hook for contamination.
Coal’s climate and health impacts — the worst among any U.S. electricity source — went unmentioned in any of the departmental plans. No surprise there: Late last week, it was also reported that the Energy Department has directed employees to avoid the use of pesky terms like “emissions” or “climate change.”
Fossil-fuel permitting keeps rolling amid shutdown
The U.S. government ran out of funding Wednesday after Congress failed to pass a stopgap bill, but the Trump administration is seemingly picking and choosing how to implement the shutdown.
At the EPA, where the administration has already implemented mass layoffs, about 89% of staff is set to be furloughed. Depending on how long the shutdown lasts, that reduced capacity could stymie Administrator Lee Zeldin’s deregulatory agenda.
Meanwhile the Interior Department will keep fossil-fuel permitting rolling along. More than half of the Bureau of Land Management’s staff will stay onboard to approve fossil-fuel projects under the Trump administration’s “energy emergency,” relying on money generated by permitting fees. The Bureau of Ocean Energy Management will similarly keep processing fossil-fuel permits and working on upcoming oil and gas lease sales, but “will cease all renewable energy activities,” according to a federal document.
EV tax credits are dead. What’s next?
Federal EV tax credits met their end this week, and automakers are already adapting to the new normal. Hyundai announced Wednesday that it’ll reduce the price of its popular Ioniq 5 by as much as $9,800 now that $7,500 federal rebates have ended. Tesla meanwhile took the opposite approach, raising lease prices for its models.
The looming expiration juiced EV sales for Hyundai, as well as Ford, General Motors, and Tesla, which all reported quarterly records from July through September. The longer-term impact of the tax-credit rollback remains uncertain, but it’ll be especially acute in the Southeastern U.S., Canary Media’s Elizabeth Ouzts reports. The region has deservedly been nicknamed the “battery belt” over the last few years as the Inflation Reduction Act spurred a wave of EV and battery manufacturing plants in Georgia, North Carolina, and beyond.
Inside the DOE cuts: The Trump administration says it’ll claw back $7.56 billion in grants for clean-energy projects, largely in states that voted for Kamala Harris in the 2024 presidential election, though grid-boosting projects that would’ve benefited red states are also on the chopping block. (Canary Media)
Hydropower’s looming crisis: Nearly 450 U.S. hydropower facilities are scheduled for relicensing over the next decade, but mounting costs and layers of bureaucracy could lead many to shut down instead. (Canary Media)
Deregulatory side effect: An Energy Innovation analysis finds Americans will end up paying more to fill their gas tanks if the Trump administration rolls back tailpipe-emissions rules that incentivize automakers to make more efficient vehicles. (The Verge)
Storage stays strong: Utility-scale battery storage set a quarterly record of 4.9 gigawatts installed in the U.S. in the second quarter of this year, though installations could fall as much as 10% in 2027 as federal support wanes. (US Energy Storage Monitor)
Battery-based breeze: Legacy air-conditioning giant Carrier is pairing AC units with batteries to relieve stress on the grid when lots of customers need to keep cool. (Canary Media)
Community solar cools: Community solar installations slowed 36% in the first half of 2025 from the same period last year, and the end of federal incentives suggests deployment will continue to fall. (Wood Mackenzie)
Trash or treasure: A billion dollars’ worth of aluminum cans end up in U.S. landfills every year, but with producers looking to curb their emissions and tariffs raising the price of virgin materials, that waste is becoming more and more valuable. (Canary Media)
America’s Lithium: The U.S. Energy Department says it’ll take 5% stakes in both Lithium Americas and the firm’s Thacker Pass project as the mine shapes up to become a key domestic source of lithium. (CNBC)
Curtains for coal: New England’s last coal-burning power plant, Merrimack Station in New Hampshire, shuts down after 65 years in operation. (Concord Monitor)
A correction was made on Oct. 3, 2025: Hyundai announced the price drop for its Ioniq 5 on Wednesday, Oct. 1, 2025, not on Thursday, Oct. 2.
At the turn of the millennium, France had one of the lowest-carbon electricity grids in Europe (and the world). While countries like the UK and Germany emitted well over 500 grams of CO₂ per kilowatt-hour of electricity, France emitted just 80 grams — six times less. This was mostly thanks to nuclear power.
In the 1980s and 1990s, France rapidly expanded its power grid, and almost all of this growth came from new nuclear plants. The chart shows this: in the 1980s alone, nuclear power grew from 60 to over 300 terawatt-hours.
By 2000, nuclear power supplied almost 80% of the country’s electricity, making it much cleaner than its neighbors, mostly relying on coal and gas.
France still has one of the cleanest grids in Europe, although it has added very little nuclear power in the 21st century. It has opened just one plant in the last 25 years, in Flamanville, following long delays and cost overruns.
In the last decade, solar and wind power have grown the most.
See what countries produce nuclear energy, and how their generation has changed over time →
Small solar-panel kits that can be assembled as easily as an Ikea bookcase and plugged into a regular residential outlet could be coming soon to New Hampshire and Vermont. Lawmakers and advocates in both states are preparing legislation that would make these plug-in solar systems accessible to residents who don’t have the space, money, or inclination to install a larger, conventional rooftop array.
“It’s really about energy affordability,” said Kevin Chou, cofounder of Bright Saver, a nonprofit that advocates for the adoption of plug-in solar. “It’s about access for people who wanted solar but haven’t been able to get it.”
These systems — also called “portable” or “balcony” solar — generally come in kits that even a novice can put together at home. They plug into a standard outlet, sending the power they generate into a home’s wires, rather than drawing electricity out.
Unlike rooftop arrays, plug-in systems don’t generate enough power to meet all, or even most, of a household’s needs, but they offset enough consumption to pay for themselves within four or five years, even without incentives like tax credits or net metering, Chou said. Models now on the market start at about $2,000. If the equipment becomes more popular and prices come down, the payback period could get even shorter.
“You don’t need any subsidies to make this work,” Chou said. “The pure economics are so attractive, it’s one of the best investments you can make.”
These systems have taken off in Germany, where more than a million have been deployed, but have been much slower to catch on in the United States.
Recently, though, the idea has gained traction in the U.S. In March, Utah lawmakers, working with Bright Saver, unanimously passed a law authorizing and regulating the equipment, making it the first state to lay out the welcome mat for plug-in solar. Last month, a Pennsylvania state representative announced plans to introduce a similar law, and Bright Saver is having conversations with lawmakers in about a dozen additional states about possible legislation, Chou said.
All of the legislative proposals follow the same principles as Utah’s law: They would define a new class of small, portable solar systems, and establish the right of households to use the systems without submitting applications or paying fees to the state or utilities. They also define safety standards for the systems, including that they be certified by Underwriters Laboratories, or UL, a company that sets standards and provides safety certifications for a wide range of products.
At the moment, two manufacturers make plug-in solar systems with inverters that have been certified as complying with safety requirements, Chou said. Because the market for portable solar is so new, however, UL has not developed standards for entire systems. Bright Saver and other plug-in solar supporters have been working with the company on this issue and expect a standard to be released in the next month or two, Chou said.
Other startups are waiting in the wings, hoping to launch their own products next year, once the questions about UL standards are resolved, he added.
“Bottom line: Once Vermont’s legislation passes, there will be existing manufacturers ready to sell into the state immediately, along with new entrants waiting for additional UL clarity, who are also preparing to launch,” Chou said.
Supporters hope the benefits of plug-in solar — lowered electricity costs, freedom to make personal energy choices — will help the idea gain support even in states not known for their embrace of renewable energy, and despite federal efforts to slow or stop renewable energy progress. The early and robust acceptance of the technology in deep-red Utah has bolstered this vision.
“I am optimistic that, as in Utah, it’s going to be seen as a commonsense way to just get out of the way and let people do good things,” said Ben Edgerly Walsh, climate and energy program director at the Vermont Public Interest Research Group, an organization backing Vermont’s expected plug-in solar bill.
In New Hampshire, a swing state known for its “live free or die” libertarian streak, Democratic state Sen. David Watters also thinks this dynamic might work in the technology’s favor, despite the state’s historical lack of support for measures boosting solar use.
“We’re really kind of stuck in a rut with anti-renewable-energy sentiment in the House,” Watters said. “This seemed like something that would fit into the ethos of people being able to make individual choices.”
Watters, a member of the state Senate Energy and Natural Resources Committee, worked with local advocacy group Clean Energy New Hampshire to author a rough draft of a plug-in solar bill based on Utah’s new law. It will be refined in the coming months and formally introduced in the legislature in January.
Notably, Watters said, his proposal would not stop homeowners associations or landlords from imposing their own rules on members and tenants.
“Their authority is not taken away,” he said. “For this state, that’s crucial.”
In Vermont, two Democratic state legislators — Sen. Anne Watson, chair of the Senate Committee on Natural Resources and Energy, and Rep. Kathleen James, chair of the counterpart committee in the House — are championing a plug-in solar bill based on model legislation drafted by Bright Saver. Watson is particularly excited for the potential of plug-in solar to reach low-income residents and renters.
“This creates access for folks who might otherwise not have the authority to put something on their roof, or who might need something a little more flexible,” she said.
Vermont, a decidedly left-leaning state, has long welcomed renewables. The state’s governor, Phil Scott, however, is a Republican who has shown reluctance to spend public money on clean energy. Further, the legislature lost its veto-proof Democratic majorities during the last election, so prospects for forward movement on energy and climate issues have been dimmed this year.
However, Watson has already heard a lot of positive feedback from her fellow lawmakers, even though the bill won’t be taken up until the legislature reconvenes in January. Indeed, several colleagues came to her with similar proposals before learning she was already working on it. She has also had initial conversations with the Scott administration and found it willing to consider the idea, she said.
“While I can’t say they are necessarily for it, the reception I’ve received so far is that they are open and interested in learning more,” she said. “I am hoping for broad support.”
Revolution Wind can officially resume. But unlike the last time President Donald Trump ordered construction on an offshore wind project to pause, relief came through the courts rather than politicking.
A federal judge on Monday ruled in favor of the Danish energy giant Ørsted, whose $6.2 billion Rhode Island project was halted last month by the Interior Department without, as the judge put it, any “factual findings.” A similar stop-work order that froze construction on New York’s Empire Wind was lifted by Trump officials in May following one month of heavy lobbying — and reported backdoor deal-making — by lawmakers and diplomats.
Judge Royce Lamberth, a Reagan-era appointee serving the U.S. District Court for the District of Columbia, granted a motion for a preliminary injunction sought by Revolution Wind to resume turbine construction while its complaint against the Interior Department works its way through the courts, which could take years. The project is 80% complete, and Ørsted released a statement on Monday saying workers will restart “as soon as possible.”
Monday’s decision marked a victory for Revolution Wind and could have broader legal ramifications for Trump’s ongoing war against offshore wind energy, given that several projects are still tangled up in litigation. And, if the recent ruling is any indication, the Trump administration may have a hard time convincing judges that walking away from already-approved wind farms makes sense.
“The Trump Administration’s erratic action was the height of arbitrary and capricious, and failed to satisfy any statutory provisions needed to halt work on a fully approved and nearly complete project. It was not a close call,” Connecticut’s Attorney General William Tong, a Democrat, stated in response to Lamberth’s decision.
Twelve other high-profile lawsuits are actively challenging Biden-era approvals for eight U.S. wind farms, according to the research firm ClearView Energy Partners. Traditionally, the government defends projects it’s already greenlit. Legally, however, it can pick and choose which approvals to stand up for.
For example, three of those projects — New England Wind, SouthCoast Wind, and the Maryland Offshore Wind Project — could soon lose their federal approvals. None of the three have started construction yet, but in the past month, government officials have filed documents in court for each, trying to undo approvals granted by the Biden administration.
“These other cases are different procedurally, but [the Revolution Wind ruling] shows that the courts are taking this seriously and that the Trump administration took these actions without sufficient justification,” said Nick Krakoff, a senior attorney for the Conservation Law Foundation.
The latest blow came on Thursday, when government lawyers filed a motion to reverse its approval of SouthCoast Wind, a massive 141-turbine project slated for federal waters near Massachusetts’s coastline. Krakoff said that the legal argument is nearly identical to one filed in the U.S. District Court of Maryland the week prior seeking to take back approvals from the Maryland Offshore Wind Project.
Both filings invoke a new legal interpretation of the Outer Continental Shelf Lands Act that argues that the Interior Department must weigh other ocean activities — like commercial fishing and Coast Guard operations — in an “absolutist approach,” said Krakoff, to evaluate potential conflicts with wind farms.
The standard interpretation, employed for almost a decade by past administrations and already upheld in a 2024 court decision, instructs agencies to take a more balanced approach to evaluating multiple ocean users.
“It’s not unprecedented for a new administration to switch positions. But it is unprecedented to seek to remand a permit because of it,” said Krakoff, who called the Trump-era interpretation of the law a “coordinated attack” on thousands of clean energy jobs.
Oddly, the Trump administration appears to be defending some wind projects at the center of these legal challenges while trying to tank the three others.
For example, on Sept. 8, the Interior Department’s Bureau of Ocean Energy Management filed a letter signalling that it wants to dismiss a lawsuit brought by the anti-wind group Protect Our Coast NJ that challenges New York’s Empire Wind.
Then there is the exceptional case of Virginia. Earlier this month, E&E News reported that House Speaker Mike Johnson (R) publicly defended Coastal Virginia Offshore Wind, which is the only offshore wind farm currently being built in a Republican-led state. ClearView’s analysts believe this GOP support may explain why the Trump administration has not tried to remand approvals for the Virginia project in response to a lawsuit brought by the Heartland Institute and other right-leaning think tanks challenging its construction. Instead, on Friday, government lawyers asked the judge for a 90-day extension on filing a report on the Virginia project’s status.
Being inconsistent in when and how it deploys new legal interpretations could backfire for the Trump administration.
On Monday, Lamberth told government lawyers that “mandating the immediate pause to construction of a project whose approval the Bureau continues to defend in other cases is the height of arbitrary and capricious.”
Meanwhile, Democratic lawmakers are clearly frustrated that most of the offshore wind projects in Trump’s crosshairs are in solidly blue states at a moment when they have little power in Congress to fight back. Many Democrats see the courts as the best hope for surmounting the administration’s continued efforts to block the development of wind power, which they view as necessary for meeting growing electricity demand.
“One of our most important roles right now is to illustrate to people that the actions taken by this administration are creating shortages and … spikes in your [electricity] prices. Second is the litigation pathway,” Sen. Brian Schatz, a Democrat from Hawaii, said during a press call on Monday.
The longtime climate hawk discussed new data showing that electricity prices in the U.S. have risen by 10% since Trump took office. Lawmakers from both sides of the aisle have proposed legislation that would streamline energy project permitting, but that is not a near-term solution for wind developers, Schatz said, adding that litigation is the faster route towards “success.”
Revolution Wind’s stop-work order had been bleeding its developers of “more than $2 million per day,” according to court filings, and posing a risk to New England’s future grid reliability.
“The time frame to get a new law in place and enforce that new law is unlikely to match up with the time frame of a developer who is almost invariably working on borrowed money and can’t wait three and a half years while we sort ourselves,” said Schatz.
For Revolution Wind, Monday’s legal victory may only be temporary — federal officials could appeal the ruling. A spokesperson for the Justice Department declined to comment. A similar but separate lawsuit challenging Revolution Wind’s stop-work order, brought by the attorneys general of Rhode Island and Connecticut, is winding its way through the courts. Last week, the feds requested that this case be transferred to the U.S. District Court in D.C. so that it can be consolidated with the developers’ case.
If the 704-megawatt project reaches completion, its carbon-free electricity will feed into New England’s regional grid, serving utility customers who just endured a winter where power bills skyrocketed.
Microsoft says it will get green steel from a first-of-a-kind facility in northern Sweden as the tech giant looks to curb the climate impact of its data center build-out.
This week, Microsoft announced a two-part deal with Stegra (formerly H2 Green Steel), which is building a multibillion-dollar plant set to be completed in late 2026. Instead of relying on traditional coal-based methods, the Swedish project will produce steel using green hydrogen — made from renewable energy sources — and clean electricity.
The first part of Microsoft’s agreement involves actual coils of steel. Because the company doesn’t directly buy construction materials itself, Microsoft has agreed to work with its equipment suppliers to ensure that Stegra’s green steel is used in some of its data center projects in Europe.
The second part of the deal enables Microsoft to claim green credentials for the infrastructure it builds outside of Europe, where Stegra isn’t planning to operate. Under this scheme, Stegra will sell its “near-zero emission” steel into the European market — except that the metal will be sold as if it had an industry-average carbon footprint and without a price premium. Microsoft will then buy “environmental attribute certificates” that represent the emissions reductions provided by Stegra’s product, helping to cover the extra cost of making green steel.
With the certificates, “We aim to signal demand, enable project financing, and accelerate global production,” Melanie Nakagawa, Microsoft’s chief sustainability officer, said in a Sept. 23 press release. Ultimately, she said, “The end game is to source physical materials with the lowest possible CO₂ footprint. Achieving this requires greater volumes of low-carbon steel available in more regions.”
The world produces roughly 2 billion metric tons of steel every year, most of which is made using dirty coal-fueled furnaces. As a result, the industry is responsible for between 7% and 9% of total global carbon emissions.
Microsoft and Stegra didn’t provide details about the financial value or volumes of steel tied to their deal. Johan M. Reunanen, who leads Stegra’s climate impact work, said only that its contract with Microsoft is neither the biggest nor the smallest offtake agreement that the steelmaker has signed since launching in 2021.
“But it’s very strategic for us,” Reunanen told Canary Media during a visit to New York for Climate Week NYC. “It gives Stegra access to a customer that is in data centers, which is a market that we’ll be developing.”
Stegra isn’t the only Swedish steelmaker chasing Big Tech. Last year, the manufacturer SSAB signed an agreement with Amazon Web Services to supply hydrogen-based steel for one of Amazon’s three new data centers in Sweden. SSAB operates the Hybrit pilot plant in Luleå — the world’s first steelmaking facility to use hydrogen at any meaningful scale, though the Stegra project will be the first large-scale plant to use this approach once completed.
Microsoft’s agreement with Stegra arrives at a tenuous time for developers of green hydrogen.
More than a dozen hydrogen projects have been canceled, postponed, or scaled back in recent months owing to soaring production costs and waning demand for the low-carbon and highly expensive fuel, Reuters reported in late July. That includes ArcelorMittal’s hydrogen-based steelmaking initiative in Germany, which the company shelved in June, as well as U.S. green steel projects formerly planned in Ohio and Mississippi.
Stegra, for its part, is seeking to raise additional cash to complete its flagship project in Boden, Sweden, after a government agency denied the company 165 million euros ($193 million) in previously approved grant funding. The Swedish Environmental Protection Agency reportedly objected to the fact that the steel mill will use some fossil gas during a heat-treatment process — though Stegra claims the project could still cut emissions by up to 95% compared to coal-based steelmaking.
Stegra has already secured 6.5 billion euros ($7.6 billion) from private investors for the project, which broke ground in 2022. The company is installing 740 megawatts’ worth of electrolyzers to convert electricity from the region’s hydropower plants and wind farms into hydrogen gas. The hydrogen will be used in the “direct reduction” process to convert iron ore into iron, which will then be transformed into steel using electric arc furnaces.
The sprawling facility, located just south of the Arctic Circle, is expected to produce 2.5 million metric tons of steel by 2028, before ramping up to make 5 million metric tons by 2030. Reunanen said that more than half of the steel produced during the first phase is already covered by offtake contracts with automakers like Mercedes-Benz, Porsche, and Scania, as well major companies including Cargill, Ikea, and now Microsoft.
The tech firm — which previously invested in Stegra through its $1 billion Climate Innovation Fund — is the first company to commit to buying environmental attribute certificates from a steel facility. Microsoft has struck similar deals to help drum up demand for lower-carbon versions of other industrial materials, including with cement startup Fortera and alternative-jet-fuel producers like World Energy.
RMI, a think tank focused on clean energy, said it helped advise Stegra and Microsoft on their deal, and both companies are part of an RMI initiative that’s working to design tools that track, validate, and account for certificates.
“Agreements like this one signal a wider demand pool for lower-carbon steel, expanding the offtake beyond conventional direct steel purchasers and into sectors where steel is a critical yet buried part of the supply chain,” said Claire Dougherty, a senior associate at RMI. She added that the deal “serves as a proof-of-concept for the role that [certificates] can play in getting first-of-a-kind, near-zero steel projects off the ground.”
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