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Ohio regulators have blocked yet another major solar project because of local pushback, even though a significant number of public comments opposing the array appear to be fabricated. It’s the latest blow to solar in a state that defers to local governments on renewable energy, but not on fossil fuels.
The Ohio Power Siting Board decided last Thursday to deny a permit for the 94-megawatt Crossroads Solar Grazing Center, which would combine solar panels with sheep grazing in central Ohio. Although the project otherwise met all legal requirements, the board concluded that it “fails to serve the public interest.”
Regulators acknowledged that Crossroads Solar would have statewide benefits, create jobs, and increase local tax revenue. But they said the project’s merits are outweighed by the existence of “consistent and substantial opposition” from local governments and nearby residents.
Critics of the decision are troubled that the regulators basically shrugged off the fact that a substantial number of public comments filed in opposition to Crossroads Solar were duplicative, anonymous, or seemingly faked. A recent Canary Media review found that dozens of comments contained apparent lies about people’s names or residence in Morrow County, where the project site is located. The board acknowledged those concerns in its ruling but asserted that substantial public opposition existed regardless of the potentially fabricated comments.
The controversy about those false comments, along with anonymous or multiple submissions, feeds into broader criticism that the board has reduced renewable energy siting to a local popularity contest.
“When the volume of public input is prioritized over its substance, it weakens trust in the process and makes it harder to build the energy system Ohio needs,” said Nathan Rutschilling, managing director of energy policy for the Ohio Environmental Council.
Like many states, Ohio faces soaring electricity demand and rising power bills. Clean energy could help address those challenges — provided it can get built.
“If we’re going to deny solar the ability to compete in Ohio’s marketplace, I think that’s going to result in an artificially high price for Ohio consumers,” said Democratic state Sen. Kent Smith, who is a nonvoting member of the siting board. He described the board’s Crossroads Solar denial as “a dangerous thing for the state in terms of both affordability and reliability.”
State and local restrictions on renewable energy have proliferated across the country in recent years, and Ohio is no exception. The state’s wind and solar developers face hurdles that fossil fuel companies do not, thanks to a 2021 law that lets counties ban renewable energy developments — an authority they do not have over oil, gas, and coal projects.
Morrow County instituted such a ban across half its townships last year. But because Crossroads Solar was in the regional grid operator’s queue before the 2021 state law took effect, it is exempt from the blanket prohibition.
However, for the past few years, the Ohio Power Siting Board and its staff have denied or recommended against permits for solar farms when all nearby local governments have been against a project. The Ohio Supreme Court has not yet ruled on a legal challenge to that practice, even though oral argument was held more than a year ago.
Initially, it seemed as if Crossroads Solar might escape this fate. Although Morrow County commissioners and the boards of trustees in two townships where parts of the project would be built were against it, the board in a third township — Cardington — remained neutral. Since opposition wasn’t unanimous, the siting board’s staff recommended in early December that regulators deem the project in the public interest.
But shortly after that recommendation, meeting minutes show that one Cardington township trustee changed his position because the staff report “did not set well with him.” That led the Cardington trustees to pass a 2–1 resolution opposing Crossroads Solar. The switch-up ultimately resulted in the siting board staff reversing its stance, filing testimony in January that encouraged regulators to rule against the project.
The Power Siting Board relied on that reversal to declare that Crossroads Solar was not in the public interest. It also asserted that there was “strong, united opposition to the project” by people in the area. It’s worth noting, however, that many locals supported Crossroads Solar. Its developer, Open Road Renewables, found that nearly half the public comments from people in nearby towns approved of the project, once the duplicate, anonymous, and unverifiable submissions were removed.
The Crossroads Solar case exposes deeper flaws in Ohio’s renewable energy siting process, some say.
It’s problematic that a single person’s vote on a town council “essentially derailed the whole project,” said Heidi Gorovitz Robertson, a professor at Cleveland State University’s College of Law. She argued that instead of reciting objections, regulators should evaluate whether those concerns have a factual basis and whether a developer’s plans already address them — and then decide whether any remaining issues actually justify denying a permit.
In the case of Crossroads Solar, Open Road Renewables agreed to address specific concerns about the project. In a late December settlement with the Ohio Environmental Council, the Ohio Chamber of Commerce, and various landowners, the company promised to follow best practices to keep roads clear and clean, use panels with an antireflective coating, minimize impacts to agriculture during construction, file a sheep-grazing plan to manage vegetation, work with a landscaping company to screen the panels from public view, and more.
But the Power Siting Board wasn’t swayed by the compromise, noting that the local governments and individual opponents who intervened in the case didn’t take part in the settlement negotiations, despite being invited to do so.
The board also appeared to buy into several obviously unfounded objections to Crossroads Solar, said Craig Adair, vice president of development at Open Road Renewables. For example, its ruling cited community skepticism about the company’s intention to graze sheep around the panels, since no contracts for such an arrangement had yet been signed. The board also noted opponents’ fears that the permit would later be transferred to another firm that wouldn’t make good on Open Road Renewables’ promises.
But the application’s commitment to use sheep would become part of the permit conditions, Adair noted. And, as a matter of basic contract law, any company that acquired the project would be subject to the same conditions as Open Road Renewables regarding permits, leases, easements, and other agreements.
The board also didn’t examine whether local governments’ objections to Crossroads Solar were based on misinformation, such as a laundry list of concerns about fires, contaminated drinking water, heat islands, and stray voltage.
“It’s taking fact and truth out of the equation, and it’s truly about concerns and politics,” said Doug Herling, a vice president at Open Road Renewables.
Instead, the board “denied a project that has no fuel requirements while we’re in the middle of an oil and gas crisis,” Herling continued, referencing the current supply disruptions caused by war in the Middle East. He also pointed out that solar can be built faster than gas plants, which face yearslong supply chain backlogs, and it doesn’t emit planet-warming and health-harming pollution.
Herling and Adair said the company plans to ask the board to reconsider its ruling.
Meanwhile, the permit denial “sends a dangerous signal to investors,” Adair said.
“I wish the state of Ohio luck in meeting its power needs and keeping power prices from going through the roof,” he said. For renewable energy developers, “it’s now a game of Russian roulette as to whether you would get a permit and what those criteria are.”
Big batteries have begun reshaping the U.S. grid. Now, the country has made surprising strides in making those energy storage systems itself, rather than depending on imports from China.
Batteries were always crucial for the effort to scale up renewable energy production, but they have taken on even more significance as AI leaders look for quick-to-build power sources to supply their headlong data center expansion.
That’s why batteries will account for some 28% of new U.S. power plant capacity built this year. For the first time, the country will be able to produce enough grid batteries to meet that surging demand on its own, according to new data from the U.S. Energy Storage Coalition, an industry group.
The onshoring began in earnest when President Joe Biden signed the Inflation Reduction Act in 2022, creating incentives both for domestic battery producers and for storage developers who use Made-in-America products.
Already, the U.S. has enough capacity to meet demand for finished grid battery enclosures. That involves connecting battery cells to power electronics, controls, and safety equipment in weatherproof steel containers that are ready to install. By the end of this year, the U.S. will also achieve self-sufficiency in a higher-value part of the supply chain: the battery cells themselves. It’s a major industrial coup that is bringing thousands of high-tech manufacturing jobs to communities across the country.
“For the first time, the United States now has the capacity to supply 100% of domestic energy storage project demand with American-built systems,” said Noah Roberts, executive director of the U.S. Energy Storage Coalition, on a Wednesday press call. “That is a fundamental shift from where we were just a year and a half ago, when the majority of battery storage systems were imported.”
This success outstrips the country’s considerable progress in solar panel manufacturing, too. The U.S. is self-sufficient in assembling solar modules, but that finished product still often depends on high-value components imported from far away — namely, solar cells. U.S. solar cell production remains a tiny fraction of its solar panel capacity.
By the end of 2025, U.S. factories had mustered the capacity to produce about 70 gigawatt-hours of finished grid storage systems each year, according to the coalition’s survey. Roberts expects that number to rise to 145 gigawatt-hours by year’s end. U.S. storage developers are likely to install about 60 gigawatt-hours annually this year and next, he noted, so the country will actually have a sizable surplus in manufacturing capacity.
As for the underlying cells, it’s a similar story with a slight delay. By the end of 2025, 20 gigawatt-hours of dedicated storage cell lines had opened, and the industry is on pace to hit 96 gigawatt-hours by the end of this year.
Now, the question the industry faces is not whether it can keep up with domestic demand — but whether it can export enough batteries to maintain that mismatch between manufacturing potential and domestic installations.
The development of U.S. grid-battery manufacturing has happened at a dizzying pace. Roberts called it “one of the fastest industrial scale-ups in recent American history.”
At the close of 2024, the U.S. had “effectively zero” factory capacity for battery cells designed for grid usage, which have different specifications than those in electric vehicles and which typically use the lithium iron phosphate chemistry.
LG Energy Solution Vertech, the grid-storage subsidiary of the Korean industrial giant, started turning things around last summer when it completed a dedicated cell production line for grid storage in Holland, Michigan. The company originally envisioned 4 gigawatt-hours of production, but quickly expanded that to 16.5 gigawatt-hours, said Chief Product Officer Tristan Doherty. Now LG plans to hit 50 gigawatt-hours of cell production capacity across North America this year.
“If you had told me that 10 years ago, that this is where we would be, I never would have believed it,” Doherty said.
The upstream supply chain, it must be said, still needs work. U.S. factories can only build the lithium-ion battery cells by importing the high-value battery materials, and China runs the show in that arena.
It’s also worth noting that this scale-up was accelerated by an unintentional nudge from the Trump administration, a sort of collateral benefit.
When the Trump administration passed its budget legislation last summer, it maintained Biden-era incentives for domestic energy manufacturing and grid battery projects even as it removed them for electric vehicle purchases.
The outlook for EV sales in America suffered as a result, and that prompted some manufacturers to repurpose their EV-battery facilities for the red-hot grid storage market. In just the last year, car companies like Ford and General Motors have retreated from their earlier EV ambitions and pivoted their battery lines to storage.
Just last week, LG said it and partner GM would retool an EV battery plant in Spring Hill, Tennessee, to make grid batteries instead; this will bring 700 people back to work after earlier layoffs. LG is also converting a plant in Lansing, Michigan, to make grid batteries instead of EV batteries, and will sell them to Tesla as part of a $4.3 billion supply deal.
It’s a stark reversal. In earlier years, grid battery developers had accepted surplus EV batteries as a sort of hand-me-down from the more mature supply chain; now, struggling EV battery producers are turning to grid storage in their moment of need.
Other companies have made their own direct investments in grid storage in recent years, including Tesla, Samsung SDI, Fluence, and SK On.
Even as the White House fights clean energy broadly, it’s showing interest in strengthening battery supply chains to reduce the upstream dependence on China. Just this month, the Department of Energy rolled out $500 million in funding for processing or recycling battery materials domestically.
The localization of grid storage supplies does more than stroke the national ego. As data center customers ravenously seek immense power supply as quickly as possible, domestic supply chains shorten the time it takes to add storage to the grid, argued Pete Williams, chief supply chain and product officer for Fluence, a major grid storage vendor.
“To deliver this ‘speed to power’ you need a resilient and a responsive supply chain, and that’s been certainly a challenge in the international markets,” he said. “With U.S. manufacturing, we can improve delivery certainty. We can also shorten project timelines for our customers.”
In the past, analysts framed industrial reshoring as a way to protect against the vagaries of geopolitical adversaries. These days, with the White House itself regularly upending global trade through tariff declarations and military interventions in crucial waterways, a local supply chain protects against U.S.-led disruptions as well.
This story was originally published by Grist. Sign up for Grist’s weekly newsletter.
When Krystal Steward started knocking on her neighbors’ doors in Ann Arbor, Michigan, in 2021, to discuss energy efficiency and sustainability upgrades, she was met with a lot of blank stares.
She was new to the issues herself, she said. But the longtime social worker kept at her new job doing outreach for Community Action Network, a local nonprofit dedicated to serving under-resourced communities. She slowly started getting people in her neighborhood to take part first in home-energy assessments, then in a city program to swap out appliances, make structural fixes, and more.
“In the beginning, it was kind of hard — a lot of people were reluctant. If someone is knocking on your door and telling you they can fix up your home for free, most people don’t believe that,” Steward said. But, she added, “Once one person tried it out, they’d tell their neighbors, and others would jump on board.”
Now, the neighborhood, Bryant, is set to pilot a first-in-the-country program that officials hope will speed the city’s transition to renewables — and offer a new model for how local governments can control their energy future.
The idea is technical, but has sparked enthusiasm across Bryant and Ann Arbor: a new city-created Sustainable Energy Utility, known colloquially as the SEU. Rather than replacing the privately owned utility that serves Ann Arbor, the plan is for this city agency to run in tandem, offering a supplemental service that residents can opt into.
If they do, they’ll stay connected to the regular grid, but will be outfitted with solar panels, battery backup systems, or other infrastructure, drawing on that power for their home use and opening up the prospect of selling any excess. The city, meanwhile, would pay for the installation and maintenance of these systems, which Ann Arbor would continue to own — a vision of energy generation and storage distributed across the city.
The plan begins in the coming months in Bryant, a 1970s-era community with about 260 homes, many of which are officially considered “energy burdened.” A quarter of residents pay more than a third of their incomes on utilities, in a neighborhood that is one of Ann Arbor’s only areas of unsubsidized affordable housing, according to Derrick Miller, Community Action Network’s executive director.
The SEU is a major step in a yearslong process to address Bryant’s energy affordability and sustainability concerns — and then expand the approach across the city.
“When we started having a conversation about how to decarbonize the neighborhood about four years ago, it felt outlandish. Now, it doesn’t feel like anyone can stop us,” Miller said.
The appeal of the SEU became clear in November 2024, when a ballot measure on the proposal was approved by nearly 80 percent of Ann Arbor voters. A little over a year later, city officials are ready to implement the vision, said SEU Executive Director Shoshannah Lenski.
In late February, the city announced that it was accepting expressions of interest from residents and businesses to take part, accompanied by a flurry of community meetings, animated videos, and ads in local theater playbills.
Customers who opt in will get two utility bills — one for the power supplied by these new city-owned clean energy systems, and one for any power they’re still drawing from the regular grid — which Lenski and her colleagues say will add up to less than they currently pay.
“Just like customers don’t own a power plant, the city owns and finances the system upfront, and they pay for that electricity through a monthly bill,” Lenski said. She noted that the model could prove particularly helpful for renters, who often get left out of green energy incentives. Signing up large multifamily buildings will be important to quickly expand the SEU’s size, she said.
In addition to installing clean energy systems at participants’ homes, the SEU could build its own microgrids, something that would set it apart from other municipal clean energy programs. For instance, the agency could install solar panels on a school to supply power when students and teachers are in the building, and that power could go to other SEU customers when classes are out.
Backers say the strategy allows Ann Arbor to build out its green energy system with lower financial risk — and lower potential for political or industry pushback.
“When coupled with DTE’s planned investments in clean energy, these voluntary, fee-based programs help accelerate economy-wide decarbonization while maintaining reliability and affordability,” Ryan Lowry, a spokesperson for DTE Energy, which currently supplies energy to the city, said in an email.
It might seem surprising that DTE, Michigan’s largest electric utility, is supportive of the SEU. But industry experts noted that many investor-owned utilities are struggling under the unprecedented new demands for power. Having a local government try to help manage power needs could be seen as an asset, they suggested — though DTE will have no formal role in the SEU.
So far, more than 1,500 people across Ann Arbor have indicated that they want to sign up. The SEU plans to serve around 100 to 150 customers in Bryant this year, expand out to reach 1,000 next year, and then grow by several thousand annually after that.
The approach answers a question prompted when Ann Arbor adopted an ambitious climate plan in 2020.
That framework included an electrical grid powered completely by renewable energy within a decade, but a city analysis in 2023 warned it was likely to miss that goal by more than 40 percent. In order to reach it, the city would need to push DTE to accelerate its renewable energy buildout, or lean on state officials to do so — or detach from DTE entirely and create a separate city-owned utility, an idea that does have some support in Ann Arbor.
But from the city’s perspective, these options seemed too risky or uncertain, Lenski said — until officials realized that the Michigan Constitution allows municipalities to create and run their own utility, even if there’s another present.
“That’s where the idea of the SEU was born,” she said.
When University of Michigan researchers compared the four options, they found the SEU model had the greatest potential to lower energy prices and emissions, boost reliability, and help low-income communities.
“Overall, it came down to having some benefits of local control without some of the costs,” said Mike Shriberg, a professor who led the research, noting a similar model should be possible in every state.
Still, some worry the strategy does not go far enough. Advocates who want the city to break with DTE and replace its services with a utility fully owned by Ann Arbor are seeking a November ballot measure to set that process in motion. (Organizers are currently collecting signatures.)
Brian Geiringer, executive director of the advocacy group Ann Arbor for Public Power, said the SEU plan still leaves too much responsibility for the city’s energy transition with DTE.
But if voters do approve creating a fully public utility, he said, it would not mean an end to the SEU: The two approaches could work together, with the SEU focused on generation within Ann Arbor, and a publicly owned utility able to make its own decisions on purchasing power.
“If you draw a circle around Ann Arbor, the SEU is doing stuff inside the circle. And we’re interested in having the city control what comes in from outside of the circle,” Geiringer said.
Like Ann Arbor, hundreds of cities are working to implement climate goals — and running into similar gaps between ambition and practicality, especially when it comes to control over energy sources.
“Cities have set these goals, and the utilities aren’t obligated to follow those,” said Matthew Popkin, manager for U.S. cities and communities at RMI, an energy think tank.
“So Ann Arbor’s SEU is an example of cities taking more control of their future without dismantling or acquiring existing utility systems,” said Popkin. “That’s a really interesting model.”
Other models also exist. In Washington, D.C., for instance, a program called the D.C. Sustainable Energy Utility has been operating for 15 years, overseeing the city’s efforts to help residents use less energy.
The initiative is far narrower than the Ann Arbor vision, functioning not as a utility but rather as an organization contracted by the city to boost energy efficiency and increase access to clean energy through subsidies and rebates.
The program is a central part of the city’s goals to reduce its greenhouse gas emissions, said managing director Benjamin Burdick, and has helped cut some 10 million metric tons of emissions while saving residents more than $2 billion from reduced energy use.
Nationally, “the conversation that we’re hearing is around how do you continue to talk about climate with affordability,” he said. “Programs like the D.C. SEU are going to continue to be the way that we double down.”
The work in Ann Arbor is now receiving its own attention across the country.
“What caught my eye about Ann Arbor’s efforts were the references to citizen involvement and co-investment in their own grid,” said Jim Gilbert, a retired medical product designer in Boulder, Colorado, who is now helping that city assess the Ann Arbor model.
Boulder has dealt with recent power outages due to worsening climate impacts and aging infrastructure, and Gilbert said an SEU could offer a way forward.
Back in Ann Arbor, as the city prepares to launch the initial pilot of its SEU, the plan is to reach half of the Bryant neighborhood by the end of the year — and local residents are “all in,” said Krystal Steward.
Older members of the community are particularly excited, she said, noting that many are on fixed incomes and will particularly benefit from lower energy bills.
“It’s hard for me to keep up,” Steward said. “Now it’s not me reaching out to residents to sign up — they’re blowing up my phone.”
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.”
See more from Canary Media’s “Chart of the Week” column.
Clean energy is on a tear. In China and India, it’s growing so fast it’s starting to unseat king coal. In the European Union, solar and wind now produce more electricity than do all fossil fuels combined. Even in the U.S., amid the Trump administration’s attacks on clean energy, nearly all new power capacity comes from renewables and batteries.
But who, exactly, is making all of the solar panels, wind turbines, battery packs, and electric vehicles enabling this transition?
In a word: China. Let’s look at the latest numbers from the Clean Investment Monitor by Rhodium Group and the Massachusetts Institute of Technology. Right now, over 90% of the world’s solar manufacturing capacity is in China. So is 83% of the planet’s battery production capacity, and nearly three-quarters of wind technology manufacturing capacity. China’s grip on the EV sector almost looks measly in comparison, at just two-thirds.
China’s lead is explained by several factors. For one, the country itself uses way more clean energy tech than does any other, due not only to its massive population but also Beijing’s concerted effort to make the nation more self-sufficient on energy. Last year, more than half of the solar and wind installed worldwide plugged into China’s grid. The country dominates global EV adoption, too.
But China also exports enormous amounts of these technologies. The country’s expansion of manufacturing to meet its own domestic energy goals has allowed it to produce super-cheap solar panels, batteries, wind turbines, and EVs. That’s made clean energy more attractive to buyers in other countries.
But China’s investment in these factories is contracting, hard. Last year, it invested $60 billion in cleantech manufacturing overall — less than half of what it put in the year before. In 2023, it spent $50 billion on clean energy manufacturing in a single quarter. Investment in clean energy manufacturing has been sluggish in the U.S. and Europe, too, for what it’s worth, but it’s not crashing at anywhere near the same rate.
China is pulling back for a pretty intuitive reason. It’s already built more clean energy manufacturing capacity than the world wants to use at the moment. The Clean Investment Monitor team expects this mismatch to get even worse by 2030, so as it stands, it makes little sense for China to continue speeding ahead on new factory construction.
Overall, the clean-energy manufacturing picture could look a bit different by the end of this decade — but only by a little. Even with the U.S., Europe, India, and others expected to make some headway in the battery and EV markets, China’s lead ultimately isn’t expected to go anywhere.
Nuclear energy developers have historically operated by a simple principle: Go big.
Reactors cost a lot of money to build, so the logic has been that it’s easier to recoup that investment if the project produces more electricity. Of late, a new generation of companies has made waves by bucking that conventional wisdom and instead aiming to build smaller reactors that can be made cheaper through bulk orders and mass production.
But with few advanced reactors built to date, that argument remains theoretical — and a new report shared exclusively with Canary Media suggests the path to proving it out is harder than many in the industry acknowledge.
It’s a chicken-and-egg situation. Next-gen nuclear startups must establish supplies of rare and legally sensitive types of fuel while also competing for a small pool of skilled workers and a limited output of valves, pumps, heat exchangers, and other equipment. Manufacturers are hesitant to ramp up production without a clear signal that advanced reactors will pan out. Investors, in turn, are leery of reactors meant for mass production that rely on unprepared supply chains.
That’s the core takeaway from the new analysis by the Nuclear Scaling Initiative, a campaign by the nonprofits Clean Air Task Force, the EFI Foundation, and the Nuclear Threat Initiative. The Nuclear Scaling Initiative launched in 2024 and aims to promote fleet-scale construction of reactors in a bid to start bringing at least 50 gigawatts of atomic power capacity online worldwide every year at some point in the 2030s.
The study, conducted by the nuclear consultancy Solestiss, highlights two paths it says are promising for the industry: either sticking to proven designs or simplifying supply chains to tap into the traditional nuclear business’ existing materials and know-how.
It comes as the Trump administration pumps billions of dollars into advanced reactors while also courting developers of more conventional large-scale reactors — and amid a high-stakes debate over which approach is best.
Earlier this month, the Bill Gates-backed TerraPower won the Nuclear Regulatory Commission’s approval to begin construction on the country’s first commercial plant with sodium-cooled fast reactors in Wyoming. In December, the decommissioner-turned-developer Holtec International won a $400 million Department of Energy grant to build its first 300-megawatt small modular reactors in Michigan, using a pressurized-water-cooled design. The DOE awarded another $400 million grant to help American-Japanese joint venture GE Vernova Hitachi Nuclear Energy build its first 300-megawatt SMR in Tennessee, based on a traditional boiling water design.
The Trump administration, meanwhile, is trying to get developers to commit to building more AP1000s — the flagship large-scale reactor from Westinghouse Electric Co. The only two nuclear reactors designed and constructed in the U.S. this century used the Westinghouse design. (A third came online in 2016 but first started construction in 1973.)
The variety of designs racing to become the nation’s fourth new reactor in decades calls into question the feasibility of rapidly scaling up production of any one model.
“We can do any one of these first projects all at once. But can we sustain a build-out of TerraPower, GE, Westinghouse, and Holtec? All the ones that are just moving forward right now? The answer to that is not yet,” said Dillon Allen, president of the advisory services division at Solestiss, who started his career working on nuclear propulsion in the U.S. Navy before moving into the utility business. “Once you’re building four to eight AP1000s and a handful of SMRs of other sizes, you start to run into smaller component bottlenecks.”
Those bottlenecks would worsen if microreactor companies succeed in their objective of securing dozens and dozens of orders for their designs.
“While small reactors have been tried before, mass-manufactured small reactors have not,” Aalo Atomics CEO Matt Loszak, whose 10-megawatt reactors also use liquid sodium as a coolant, wrote in a post on X this week. “Small is more expensive than large, if you only make one reactor. But if you make 1000s per year, small could be cheaper than large. This is what Aalo is setting out to prove.”
One major obstacle to this plan is transportation. To build something and send it without prior testing is no problem, since a reactor that hasn’t been fired up and irradiated “is just a big hunk of metal,” Allen said. But once it’s irradiated, it’s subject to different considerations.
National laboratory researchers have started to discuss a framework for a U.S.-wide transportation network with established logistics and safety standards, the report notes, but no such rules have yet materialized.
The biggest barrier for next-gen nuclear, however, is likely to be the fuel supply. Some small reactor companies have been proactive here. Aalo, for example, has opted for the most commonly used reactor fuel on the planet, low-enriched uranium, so it can tap into the existing global supply chain.
But most advanced nuclear startups are banking on what’s known as fourth-generation reactors. These designs rely on coolants other than water and mostly aim to use one of two types of fuel: high-assay low-enriched uranium, commonly known as HALEU (pronounced HAY-loo), or tristructural isotropic fuel, for which HALEU is typically an input. Tristructural isotropic fuel is also known as TRISO.
HALEU, which firms like TerraPower and microreactor developer Oklo plan to use, is only really produced at a commercial scale by Russian and Chinese state-owned companies. Efforts to bring new centrifuges online in America are slow-going. Meanwhile, the TRISO fuel that startups such as Valar Atomics or Radiant need requires not only securing HALEU but also separating that enriched uranium into ceramic-coated pellets the size of poppy seeds. Manufacturers admit that TRISO may never cost less than low-enriched uranium.
The complications don’t stop there. Because HALEU is up to four times more enriched than traditional reactor fuel, it comes with stricter regulations. On the Nuclear Regulatory Commission’s security-clearance scale of category one, which allows for handling normal reactor fuel, to three, which includes military-grade enrichment levels, facilities with HALEU need to be rated at a category two. No such facilities exist in the U.S. today, though the commission just issued its debut permit for one last month.
As for traditional fuel, the existing supply of low-enriched uranium falls short of what would be required to meet the U.S. goal of quadrupling the nation’s nuclear capacity to 400 gigawatts by 2050.
“The supply chain is pretty well suited to support a fleet of 100 operating reactors,” Allen said, referring to the 94 commercial reactors in service in the U.S. “But then you can have 150, then 180, and pretty soon 200 after that. If you double that demand on the LEU supply, it’s not just the enrichment” that’s a limiting factor.
It’s also, he said, the production of raw uranium and the facilities to carry out conversion, where purified uranium ore is turned into a gas, and deconversion, where it’s solidified once again.
Expanding these upstream operations may be challenging, but it isn’t impossible. In fact, Allen said he came away from writing the report with the impression that supply chains are more capable of scaling up than he previously thought. But his team’s work demonstrates the steep obstacles faced by the entire industry — not only advanced reactor firms — as it attempts to bolt into action following decades of anemic construction in America.
The biggest impression the research left on Allen, he said, is that the AP1000 has a good shot at becoming the next reactor built in the U.S. Its costs are more predictable — and thus easier to finance — thanks to the lessons learned during construction of the two units that came online at Southern Co.’s Alvin W. Vogtle Electric Generating Plant in central Georgia in 2023 and 2024.
“I’m more bullish on the AP1000 than I was when I started this effort,” he said. “I’m broadly bullish on the supply chain.”
The DOE is considering alternatives to the AP1000 to satisfy President Donald Trump’s order to facilitate construction on at least 10 large-scale reactors by the end of the decade. In response to the news that the administration held talks with its rivals, Westinghouse said the AP1000 is“the only construction-ready, gigawatt-scale, advanced modular reactor that is fully licensed and operating in the U.S.”
The U.S. ultimately should focus on designs it can scale up rather than spreading its efforts in many different directions, said Stephen Comello, the executive director of the Nuclear Scaling Initiative. At that point, nuclear power will become cheap enough to be “boring.”
“Once you start accumulating that knowledge from repetition, nuclear construction becomes boring — just like natural gas combined-cycle plants, just like all other complex megaprojects and energy infrastructure that’s out there,” he said.
There’s little doubt that the AP1000 has a well-established supply chain and data showing it runs well, he said.
The question is, “Can you do it in a repeatable, cost-effective way? That’s where the risk lies with the AP1000,” Comello said. “It runs, the technology is great. But we have to prove to investors that we can overcome the execution risk. But here’s the thing: All reactors share execution risk to some extent. Others have a technology risk because they are still not proven at scale.”
A new study, led by researchers at Columbia University and Woods Hole Oceanographic Institution (WHOI), identifies a diverse set of molecules released by marine phytoplankton that fuel microbial life and help drive Earth’s carbon cycle. While scientists know that carbon is moved through an invisible network of phytoplankton and other microbes in the surface ocean, the specific compounds have long been a mystery. These compounds are small, chemically difficult to detect in salty seawater, and are rapidly consumed by other organisms almost as soon as they are produced.
Phytoplankton, a type of microscopic organism, take in carbon dioxide and convert it into organic carbon through photosynthesis, like plants. Each year, this process moves many tens of billions of tons of carbon through the sunlit surface ocean and contributes to the oxygen in the air we breathe. These massive natural carbon flows highlight the central role the surface ocean plays in regulating Earth’s carbon cycle.
“For this study, we placed six phytoplankton species representing major groups of marine phytoplankton under controlled conditions. They had the nutrients and light they needed to grow,” said Yuting Zhu, co-lead author of the study and former WHOI postdoctoral investigator, now with Old Dominion University. “Using a chemical-tagging method developed at WHOI, we were able to quantify the composition of biologically available small molecules released by globally abundant microorganisms.”
These compounds accounted for up to 23% of the dissolved organic carbon that phytoplankton released and may support a substantial share of microbial metabolism in the global ocean.
However, many bacteria are metabolic specialists, or picky eaters. The study found that different phytoplankton species release distinct combinations of metabolites, including carbon compounds also containing nitrogen, phosphorus, and sulfur. Because bacteria vary in which molecules they can consume, the chemical “menu” produced by phytoplankton helps determine which microbial communities thrive in different parts of the ocean.
“The findings help illuminate a long-standing mystery about the composition of the ‘chemical currencies’ that are moved by microbes in the surface ocean,” said microbial oceanographer Sonya Dyhrman, a researcher at Lamont-Doherty Earth Observatory, which is part of the Columbia Climate School, and professor of Earth and environmental sciences. “I think of it as a microbial carbon economy. By identifying the currencies produced by phytoplankton, scientists can begin to build more realistic representations of how marine microbial communities cycle billions of tons of carbon.”
To explore the broader implications, the team, also including researchers from the Massachusetts Institute of Technology and Marine Biological Laboratory, combined laboratory measurements with global ecosystem modeling. Their results suggest that phytoplankton-derived metabolites could supply up to 5 percent of the daily carbon needs of SAR11, one of the most abundant groups of bacteria in the surface ocean.
“Combining the ecological and chemical approaches here allowed us to view the system through a new lens,” said co-lead author Hanna Anderson, a researcher at Lamont and PhD candidate in Earth and environmental sciences at Columbia. “Thinking synthetically about how these carbon substrates can mediate interactions between phytoplankton and heterotrophs, which in turn cycle this carbon within the marine food web.”
The research was conducted as part of the National Science Foundation-funded Center for Chemical Currencies of a Microbial Planet, a science and technology center that investigates how small molecules govern interactions among microorganisms across Earth’s ecosystems.
“Understanding these exchanges is critical because a huge portion of Earth’s carbon cycle passes through this microbial system, but we still don’t fully understand it,” said the center’s director and co-author of the study, WHOI senior scientist Elizabeth Kujawinski. “If we understand what molecules phytoplankton release and what molecules bacteria can take up, we can start building models of how these organisms interact. We think of the surface ocean as a network, where phytoplankton and bacteria are connected by molecules—some compounds feed many different bacteria, while others only support a few.”
Future studies will investigate how environmental conditions such as nutrient limitation, temperature changes, and ocean acidification alter the molecules that phytoplankton release and how microbial communities respond to those “chemical currencies.”
This article was adapted from a press release by the Woods Hole Oceanographic Institution.
06.03.2026 - Global warming has accelerated since 2015, according to a new study by the Potsdam Institute for Climate Impact Research (PIK). After accounting for known natural influences on global temperature, the research team detected a statistically significant acceleration of the warming trend for the first time. Over the past ten years, the estimated warming rate has been around 0.35°C per decade, depending on the dataset, compared with just under 0.2°C per decade on average from 1970 to 2015. This recent rate is higher than in any previous decade since the beginning of instrumental records in 1880.
“We can now demonstrate a strong and statistically significant acceleration of global warming since around 2015,” says Grant Foster, a US statistics expert and co-author of the study, which was published today in the scientific journal Geophysical Research Letters.
“We filter out known natural influences in the observational data, so that the ‘noise’ is reduced, making the underlying long-term warming signal more clearly visible,” Foster added.
Short-term natural fluctuations in global temperature caused by El Niño, volcanic eruptions, and solar cycles can mask changes in the long-term rate of warming. In their data analysis, which is based on measurement data, the two researchers work with five large, established global temperature data sets (NASA, NOAA, HadCRUT, Berkeley Earth, ERA5).
“The adjusted data show an acceleration of global warming since 2015 with a statistical certainty of over 98 percent, consistent across all data sets examined and independent of the analysis method chosen,” explains Stefan Rahmstorf, PIK researcher and lead author of the study.
After correcting for the effects of El Niño and the solar maximum, 2023 and 2024, which were exceptionally warm years, become somewhat cooler, but remain the two warmest years since the beginning of instrumental records. In all datasets, the acceleration begins to become apparent in 2013 or 2014. To test whether the warming rate has changed since the 1970s, the research team applied two statistical approaches: a quadratic trend analysis and a piecewise linear model that objectively determines the timing of any change in the warming rate.
The study does not investigate the specific causes of the observed acceleration. However, climate models show that an increasing rate of warming is fundamentally within the scope of current climate modelling, according to the authors.
“If the warming rate of the past 10 years continues, it would lead to a long-term exceedance of the 1.5° limit of the Paris Agreement before 2030,” says Stefan Rahmstorf. “How quickly the Earth continues to warm ultimately depends on how rapidly we reduce global CO₂ emissions from fossil fuels to zero."
Winter winds lofted clouds of dust from the Sahara Desert, carrying it north toward the Mediterranean and dispersing it widely across Europe in March 2026. When the dust combined with moisture-laden weather systems, a dirty rain fell in parts of Spain, France, and the United Kingdom.
This animation highlights the concentration and movement of dust throughout the region from March 1 to March 9. It depicts dust column mass density—a measure of the amount of dust contained in a column of air—produced with a version of the GEOS (Goddard Earth Observing System) model. The model integrates satellite data with mathematical equations that represent physical processes in the atmosphere.
The animation shows dust plumes originating in northwestern Africa being blown both to the west across the Atlantic Ocean and north toward the Mediterranean. As plumes spread throughout Western Europe over several days, people observed hazy skies from southern England, where sunrises and sunsets took on an eerie glow, to the Alps in Switzerland and Italy, where a dust layer encroached on the Matterhorn.
Not all of the dust remained aloft. Storms encountered some of the dust, causing particles to fall to the ground with rain and coat surfaces with a brownish residue. A low-pressure system, named Storm Regina by Portugal’s weather service, moved across the Iberian Peninsula and brought so-called blood rain to southern and eastern Spain, along with parts of France and the southern UK in early March, according to news reports.
Over the Mediterranean, areas of “dusty cirrus” clouds developed higher in the atmosphere, where dust particles can act as condensation nuclei for ice crystals, according to MeteoSwiss, Switzerland’s Federal Office for Meteorology and Climatology. Scientists are studying these clouds to better understand their formation and how they affect weather, climate, and even solar power generation.
In a new analysis, researchers used NASA’s MERRA-2 (Modern-Era Retrospective Analysis for Research and Applications, Version 2), observations from MODIS (Moderate Resolution Imaging Spectroradiometer), and other satellite products to parse the effect of airborne Saharan dust on solar power in Hungary. They found that photovoltaic performance dropped to 46 percent on high-dust days, compared with 75 percent or more on low-dust days. They determined the greatest losses occurred because dust enhanced the presence and reflectance of cirrus clouds and reduced the amount of radiation that reached solar panels.
Some research suggests more frequent and intense wintertime dust events have affected Europe in recent years. Researchers have proposed several factors contributing to these outbreaks, including drier-than-normal conditions in northwestern Africa and weather patterns more often driving winds north from the Sahara.
NASA Earth Observatory animation by Lauren Dauphin, using GEOS-FP data from the Global Modeling and Assimilation Office at NASA GSFC. Story by Lindsey Doermann.
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