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Kamloops, British Columbia, is a radiant place, receiving over 3,100 hours of sunshine a year. So it’s no wonder that in 2016, Thompson Rivers University (TRU) decided to harness all that luminescence and convert it to electricity.
If the university’s solar array had been installed on a roof or mounted above ground in a corner of a soccer field, that probably would have been the end of the story. Instead, TRU didn’t follow trends — it set one: It became the first place in Canada to embed solar panels into the ground. By 2017, a 12-meter walkway with 16 solar modules near the campus daycare, together with a compass (sunburst) design of 62 modules in front of the arts and education building, were producing power. By its second summer of operation, the compass produced enough electricity to power an entire classroom of computers at TRU’s arts and education building for the day.
For Amie Schellenberg, an electrical instructor at TRU and part of the team that spearheaded the sidewalks, ground-mounted solar arrays just make sense.
“Why wouldn’t we use the space we already have?” she asks. “We don’t need to create new space, or repurpose anything. We don’t need to plow fields or redo rooftops — the ground is there.” Historically, solar panels have been mounted above ground, typically on roofs or in gigantic solar parks. But wide-open spaces and sunlit rooftops aren’t always an option in cities.
“It’s hard to integrate traditional rooftop solar into urban centers,” says Gilbert Michaud, chair of the American Solar Energy Society’s policy division. “Buildings shade each other and condo buildings may have restricted HOA policies. It makes it really hard for people in urban environments to install solar, even though population centers have a demand for cool energy and want to see it.”
This is where in-ground solar shines. In 2021, the city of Barcelona installed Spain’s first photovoltaic (PV) pavement as part of the city’s goal to become climate neutral by 2030. In the Netherlands, an embedded 400-meter solar sidewalk in front of Groningen Town Hall is powering the building as part of that city’s ambition of becoming CO2 neutral by 2035. The project is part of the European Union’s Making City project, which aims to develop positive energy districts (PEDs) that demonstrate innovative solutions to tackle climate-neutral goals. The 400-square-meter installation is projected to offset approximately 18 tons of CO2 annually. “It is an example of how to use space in the city in a smart and sustainable way,” Philip Broeksma, councilor of energy from the Municipality of Groningen said when the sidewalks were revealed in 2023.
With places around the world looking to produce more solar energy, the question is: Can in-ground solar be scaled to meet demand?
Most solar installs are fixed tilts at a 45-degree angle, Michaud explains. “Larger installations [such as solar farms] move with the sun to capture as much light as possible. A horizontal sidewalk is much less efficient,” he says.
Not everyone agrees. Pavegen, a U.K.-based company, has combined the concept of in-ground solar tiles with the kinetic energy generated by people’s footsteps. When someone walks across the tile, a mechanism underneath it triggers an electric current that generates power.
“An example of kinetic [foot power] alone in Yosemite National Park has exceeded 35 million joules of energy. That’s equivalent to around 9,000 kilometers on an e-bike, or 10,000 hours of talk-time on a standard smartphone,” says Paul Price, head of marketing and communications for Pavegen. “When the tiles capture solar energy, they generate 30 times more.”
Pavegen’s Solar+ system, which uses the combined power of solar energy and kinetic energy, is poised for large-scale distribution this fall. Suited for integration into school campuses and city promenades, it will be able to power everything from LED streetlights to digital devices.
But how durable is the surface of a solar panel? The solar paths at TRU were covered with an epoxy and finished with a gritty, anti-slip surface that felt spongy to walk on, but this still wasn’t enough to protect the array from a Canadian winter.
“We do get snow every winter,” Schellenberg says. “And to be honest, every year, something new happened, whether it was a piece of rail that lifted off, or a couple of fasteners, or there was some water seepage underneath.”
Since the installation of TRU’s sidewalks, technology has advanced, and according to Price, companies such as Pavegen now design installations with integrated drainage channels beneath the sub-frame, ensuring water flows away efficiently and doesn’t compromise performance or safety. But despite this, installing inground solar tiles is no easy feat.
At TRU, troughs had to be cut into the concrete for wires that connect the array to the university’s electrical grid. Solar panels generate DC (direct current) electricity, so an inverter cabinet, to convert the current to usable AC (alternating current), was installed inside the arts and education building. These infrastructure changes aren’t cheap. A sustainability grant of $35,000 Canadian from the university covered the cost, not including the panels, which were donated. Schellenberg says the power generated from the sidewalks has offset this cost and it all has broken even financially. Still, she and Michaud concur that, as things stand now, in-ground solar in North America can be expensive and may lack electrical efficiency. The good news is that they both see change on the horizon.
“As the technology gets better, costs go down, and as policies are adopted, including tax credits, it becomes much more feasible,” Michaud says. Schellenberg imagines unlimited possibilities for the technology, both big and small. “An unused corner of a Walmart parking lot could become a solar-generating hub,” she muses.
In fact, this is an idea that has already reaped dividends in Moult, France. The Lidl supermarket has installed 50 square meters of in-ground solar panels in a back corner of its parking lot to reduce its energy bill. In one year, the panels produced the equivalent of 7,000 hours of use for five cash registers.
As fossil fuel-powered vehicles become antiquated and EVs increase in popularity, Schellenberg sees wireless in-ground solar EV charging stations becoming commonplace. “This could be the boost that those EVs need to make it the next 100 kilometers,” she notes.
In Amsterdam and Paris, this is already proving successful. Select bus stops and terminals are embedded with solar panels that collect energy and store it in batteries below the surface. As an electric bus pulls into the stop to pick up passengers, it’s able to draw power from the embedded system and top up its charge without needing to return to the central depot. A single charging point can produce 15 to 20 kilowatt-hours per day, enough to power a bus for several kilometers. At TRU, the in-ground solar arrays were a prototype and never meant to produce a lot of power. In the six years they were operational (2016 to 2022), they generated just enough electricity to power a single home for half a year. To put this into perspective, Topaz Solar Farm in San Luis Obispo County, California, is the largest in the U.S., spanning 4,700 acres. Over nine million above-ground mounted solar panels supply power to approximately 180,000 homes.
By 2023, the sidewalks had stopped producing power and couldn’t be maintained, but they weren’t removed. Schellenberg hopes that when people see them, they are inspired to think outside the box. She’s proud of the project and doesn’t measure its success in kilowatt hours but rather in what’s possible when it comes to renewable energy solutions. “It is another extension of finding ways to solve problems,” she says.
New York Governor Kathy Hochul has made energy affordability a centerpiece of her political platform this year, blasting proposed utility rate hikes and even promising to slow down implementation of the state’s climate law over the concern that the clean energy transition is costing New Yorkers too much.
But Hochul’s administration is slashing an energy affordability program that was once a priority for the governor, New York Focus has learned.
The EmPower+ program was designed specifically to help low- and moderate-income households “save energy and money” through energy efficiency upgrades. Since 2023 — at Hochul’s initiative — it has been New York’s one-stop shop to help residents take advantage of green building upgrades they might not otherwise be able to afford, like better insulation and replacing old boilers.
“I don’t know of any other program that makes such a big difference to the energy bill and the quality of life for a household that goes through [it],” said Jessica Azulay, executive director of the advocacy group Alliance for a Green Economy.
The program is now facing drastic budget cuts. In a July 11 meeting, the New York State Energy Research and Development Authority (NYSERDA) warned local contractors who install the upgrades that it would be cutting the EmPower+ budget from roughly $220 million this year to $80 million in 2027.
Michael Hernandez, New York policy director at the pro-electrification group Rewiring America, said he was “shocked” to learn of the impending cuts and has been sounding the alarm among advocates and lawmakers.
Azulay called the projected cuts “devastating.”
“As families are facing rising energy bills, the state is cutting back on a key tool that it has to help people get their energy bills under control, and to have homes that are more comfortable and safer and healthier,” she said.
In recent years, EmPower+ has served tens of thousands of New Yorkers, helping them identify ways that their homes might be wasting energy and fix them through installing better insulation and air sealing and switching to efficient new appliances like heat pumps. The program targets one- to four-family homes, allowing both homeowners and renters to participate.
The program covers up to $24,000 worth of upgrades per household, using a mix of state and federal funding. It aims to cover the full cost of upgrades for low-income households and, in some cases, guarantee that participants never pay more than 6% of their income on energy, by providing ongoing subsidies where needed.
Even New Yorkers who have gotten relatively minor upgrades through the program say it can make a big difference.
Isaac Silberman-Gorn, a first-time homeowner in Troy, outside Albany, said the program recently allowed him to replace a “dinosaur” of a dryer with a brand-new heat pump model. Thanks to the upgrade, his energy usage no longer spikes every time he does a load of laundry.
“It’s the first new appliance I’ve ever had,” he said. “Our energy bills are lower. I’m not worried about the thing starting a fire, which is nice.”
Silberman-Gorn, who works part-time as a bicycle mechanic and at an environmental nonprofit, said he wouldn’t have been able to afford the state-of-the-art new dryer if EmPower+ hadn’t covered the cost. “That was a game changer,” he said.
The program relies heavily on the work of local contractors, who conduct NYSERDA-funded energy audits for homes and then, typically, file the application to NYSERDA for upgrades that might be warranted. They’ve been a key avenue for bringing people into the program, often through customers who refer the companies to friends and neighbors they think might be eligible for similar upgrades.
NYSERDA told contractors in last week’s meeting that they can no longer sign up new customers for EmPower+ themselves. Clean energy advocates and contractors participating in the program see this as another way to tighten the belt.
“That will naturally slow the program down big-time,” said Hal Smith, CEO of Halco Home Solutions and president of the Building Performance Contractors Association of NYS, a trade group.
He said his own company, which works across the Finger Lakes region and has a staff of about 180, should be able to weather the cuts because it does a variety of work and serves customers across the income spectrum. But he worries that some companies working mainly or even exclusively for EmPower+ may have to shut down entirely or lay off much of their staff.
The cuts are particularly hard to stomach after years where NYSERDA was pushing for “more, more, more,” Smith said, building up the program as the state scrambled to meet clean energy targets and encouraging as many contractors as possible to get on board.
“That’s been the march for years, and we’ve all grown, grown, grown,” he said. “Now NYSERDA is saying we have to put on the brakes.”
A NYSERDA spokesperson said that EmPower+ remains a high priority for the agency and that it is only pausing applications from contractors while it reviews how to direct funds to the households most in need. (The spokesperson did not comment on the agency’s funding cuts to the program.)
Smith said he doesn’t blame any one actor for the cuts. The EmPower+ program — which was the result of a 2023 merger between two others — draws its funding from a dizzying array of sources. There’s money from New Yorkers’ utility bills, through a program approved by the state’s Public Service Commission; from the East Coast cap-and-trade program known as RGGI; from the state budget; from a federal home energy rebate program created under former President Joe Biden; and from the longer-standing federal heating assistance program LIHEAP.
Scott Oliver, an EmPower+ program administrator at NYSERDA, told contractors last week that federal and state budget cuts were forcing the agency to scale back the program. Hochul and state lawmakers gave EmPower+ a $200 million funding surge in 2023 but earmarked only $50 million for the program this year. President Donald Trump’s administration is seeking to eliminate LIHEAP entirely and cut back other weatherization funds.
Hochul could direct NYSERDA to tap other funding sources for the program, advocates say.
The cap-and-trade program RGGI has earned New York anywhere from $100 million to $400 million a year over the last decade and accumulated a surplus of more than $850 million, according to NYSERDA’s latest financial statement. The state’s new $1 billion climate fund included only $50 million specifically for EmPower+, but has another $110 million for unspecified green buildings projects, which the governor could use for the program. (The New York State Assembly had sought in negotiations to allocate more than $300 million just to EmPower+.)
And the Public Service Commission, New York’s utility regulator, recently increased the funding going from energy customers’ bills to programs like EmPower+, if not by as much as some advocates had hoped.
Advocates say it’s not yet clear whether Hochul’s administration intentionally cut EmPower+ or whether the program, with its complicated mix of funding, has simply slipped through the cracks.
Still, Hernandez, of Rewiring America, said it was bewildering that Hochul’s administration could allow such cuts to proceed while the governor emphasizes energy affordability as much as she has: “How can she be saying, doing both of those things at the same time?”
In a statement, the governor’s office highlighted the $50 million for EmPower+ in this year’s state budget.
“Governor Hochul has made affordability for New Yorkers a top priority,” said Hochul’s energy and environment spokesperson Ken Lovett. “The Governor continues to push back against devastating cuts in Washington, and calls on our state’s Congressional Republican delegation to join the fight to protect our state’s most vulnerable citizens.”
The EmPower+ cuts further slow New York’s progress toward meeting legally binding climate targets, in particular a requirement to slash energy use in buildings by 2025. That deadline is now just months away, and the state is far from meeting it.
Some climate hawks in the state legislature are beginning to cry foul over the EmPower+ cuts.
“I’m sure that right now the governor is doing her best to look at where we can cut corners,” said Assemblymember Dana Levenberg, of Westchester and the Hudson Valley, referring to the massive funding cuts coming down from Washington. “This is not where we should be doing that.”
In their presentation last week, NYSERDA officials said they were still looking for alternate sources of funding to keep EmPower+ whole.
“This is a problem that is absolutely fixable, and we need the governor to step in here and make the call,” said Azulay, of Alliance for a Green Economy.
Hochul has promised that she’s attuned to such concerns. “Utility costs are a huge burden on families,” she told reporters earlier this month, “and I’ll do whatever I can to really alleviate that.”
New Hampshire’s new state budget redirects an estimated $15 million from a dedicated renewable energy fund into the general fund, likely signaling the end of plans to expand a popular pilot supporting municipal solar developments.
While some New England states have moved to strengthen clean energy policy in the face of President Donald Trump’s efforts to quash renewable power development, New Hampshire has taken a different path: The provisions of the latest budget leave just $1 million in the renewable energy fund each year for programs that, in fiscal year 2024, cost more than $5 million to administer.
“This is a big step backward for renewable energy in the state. There’s going to be very little left over,” said Nick Krakoff, senior attorney in New Hampshire for the Conservation Law Foundation. “That means there would be basically nothing left for this municipal program.”
The renewable energy fund, established in 2007, receives money from electric service providers that are unable to meet their obligations to source a certain level of renewable power each year. Most years, the fund takes in anywhere from $2 million to $8 million. The money has traditionally supported a handful of renewable energy incentives, and revenues have generally exceeded spending. At the beginning of fiscal year 2024, the fund had a balance of nearly $15.3 million.
Earlier this year, the state energy department started laying out plans to use some of this money to support solar projects developed by municipal governments. Such developments have both financial and environmental benefits, saving money for towns — and thus taxpayers — while cutting greenhouse gas emissions from electricity generation in a region that relies heavily on natural gas to fuel its power plants.
Still, municipal solar projects can be a hard sell for voters in New Hampshire, a state with a reputation for frugality. The state has no sales tax or income tax, so government operations are funded mainly by hefty property taxes. It is also home to many small towns with constrained budgets. Though solar installations can save a town money, voters are generally reluctant to approve the upfront cost, which could increase their property taxes.
“The reality for New Hampshire residents is that municipal budgets are very, very, very tight, and property taxes keep going up,” said Sarah Brock, director of the nonprofit Clean Energy New Hampshire’s Energy Circuit Rider program, which helps towns develop clean energy and energy efficiency projects. “Every year at town meeting, there’s a pretty substantial reluctance to approve money for just about anything.”
In 2024, the state launched the Municipal Solar Grant Program to help towns overcome those hurdles and install solar panels on municipal property. The pilot program has a specific focus on small or economically disadvantaged towns that would have a harder time funding such projects on their own. The initiative uses $1.6 million in funding that the state received through the federal Bipartisan Infrastructure Law, passed in 2021.
Thirty towns applied for the funding through the pilot; 16 were selected to receive grants between $45,000 and $200,000. Staff with the Energy Circuit Riders program identified perhaps 20 more towns that might also be interested in future funding opportunities.
“We had over 50 towns in our active project pipeline that would want to go after this funding,” Brock said. “We know the demand is there.”
The plan was to follow up with a permanent program paid for by the renewable energy fund. In the spring, the state energy department asked for comments on the proposed program and ideas about how to modify the approach used in the pilot.
The annexation of the renewable energy fund, however, could put an end to these plans, advocates said. With only $1 million available each year, there would not be enough money available to continue existing offerings like its nonresidential competitive grant program and rebates for wood pellet stoves at current levels. Adding an entirely new initiative may be a nonstarter.
“No one is telling us the program is dead, but it is possible that it will be impossible to run if there isn’t funding for it,” Brock said.
Neither the office of Gov. Kelly Ayotte nor the state energy department responded to requests for comment about the future of the program.
The first project completed under the pilot was a 26-kilowatt solar array atop the town hall in Kensington, New Hampshire, in the southeastern corner of the state and home to about 2,000 people. Kensington has an annual budget of just $2.6 million, so voters were unlikely to approve a nearly $100,000 investment, even if it promised savings in the long run, said Zeke Schmois, chair of the town’s energy committee. So the local solar boosters turned to the state.
The town received about $92,000 for the project. The final panels went up in early July, making Kensington the first place to complete an installation as part of the grant program.
“This isn’t a solar farm, but it’s huge for a town like ours with such a small budget and such a small population,” Schmois said.
Kensington expects the installation to offset about 70% of the town hall’s annual electricity use, Schmois said. But those savings are just the beginning of the impact: The town historical commission was involved with the approval process and realized that modern solar panels can blend inconspicuously with roofing. The group is now eager to collaborate on future solar projects, Schmois said.
Other towns hope for similar benefits. Dublin, New Hampshire, received a grant of about $43,000 for a solar array that should meet all the town fire station’s power needs once it is installed later this summer, said Susan Peters, the chair of Dublin’s select board and founding member of its energy committee. She hopes the installation’s location along a major state highway will help normalize the idea of solar, and help build support for another project under consideration: a ground-mounted array near a capped landfill.
“The fact that we’re doing this project strengthens people’s interest,” she said.
Rooftop solar costs way more in the United States than it does elsewhere in the world. That’s long been a headache for the sector to navigate. But now with Republicans in Congress killing off the decades-old tax credit for rooftop solar, it’s a life-or-death problem.
So says Andrew Birch, a 25-year industry veteran who’s built a career on cutting solar projects’ “soft costs,” which make up roughly two-thirds of the price of a rooftop solar installation in the U.S. and consist of everything other than equipment costs.
Some of those factors are under a solar company’s control, like how much it spends on acquiring customers and managing projects. Others aren’t, like the expense associated with navigating complex permitting and interconnection processes that differ from city to city and from utility to utility.
Those costs rise when solar systems are accompanied by batteries, something that is becoming increasingly common as households look for backup power and respond to new incentive structures that prioritize storage, as is the case in California, the nation’s largest rooftop solar market.
Big upfront costs are the No. 1 reason Americans decide not to put solar panels on their rooftops. The forthcoming spike in installation costs created by the new GOP megabill will only make that hurdle higher. After this year, households will lose access to tax credits for 30% of the cost of solar, batteries, and other home clean-energy equipment, and companies that offer solar systems under third-party ownership models will face a set of uncertain restrictions that could choke off that part of the market.
In order for the U.S. to keep installing rooftop solar at a healthy rate — something that’s key to combatting climate change and helping people manage rising electricity costs and electrify their cars and homes — the industry needs to figure out how to prevent costs from ballooning once the incentives disappear.
“We’re now being forced to operate as an industry without subsidies,” Birch said. That puts the onus on the industry to both tighten its belt in areas that are under its control and press state lawmakers, local government officials, and utility regulators to reform their parts of the equation.
“We can survive and thrive — if we can reduce soft costs,” he said.
Birch, a native Australian known as “Birchy” in the solar world, is working on just that himself.
He helped launch SolarAPP+, an “instant permitting” software platform being used by more than 160 cities and counties across the U.S. to process solar permits in hours rather than weeks. OpenSolar, the company he co-founded and leads, offers free solar project design and management software to installers, paid for by equipment manufacturers and dealers eager for the increased sales it can bring.
There’s plenty of evidence that lowering these costs is possible: The soft-cost problem is a bit of a uniquely American phenomenon. In other places with high rooftop solar penetration, like Australia, the world’s rooftop solar leader, these costs are far lower.
Solar companies in Australia can quote, sell, and install a 7-kilowatt solar system with a 7 kilowatt-hour battery for about $14,000 in a matter of days, Birch estimated. In the U.S., that same system costs about $36,000, and getting permits and interconnections can take months — long enough to kill a fair number of installs before they can be completed, he said.
When it comes to cutting soft costs, local permitting reform is a big target.
Permitting regulations and processes vary widely across the roughly 23,000 city, county, and other local authorities that have jurisdiction over building permits, electrical code enforcement, and other must-haves for a solar or battery installation. Permitting can add roughly $1 per watt to the cost of a typical solar installation, according to the industry trade group Solar Energy Industries Association (SEIA).
Some do a good job of making the process smooth and straightforward. Others can be far less helpful and efficient. Slow or cumbersome permitting takes a toll on solar installers, stretching the time it takes to complete current projects and move on to the next.
“If you can ensure you’re making it through in three weeks versus three months, you’re operating much more efficiently,” said Barry Cinnamon, CEO of Northern California solar and battery installation firm Cinnamon Energy Systems. On the other hand, “in cities where the permitting is slow, you inevitably get them coming back in two weeks saying, ‘You’re missing a dash in that form — send it back,’ and then two or three weeks later saying, ‘We’re not sure the battery can go in that spot. Try again.’”
It’s hard to standardize permitting across local authorities, which range from well-staffed big-city departments to tiny towns with one or two people working on it. But software that can reliably complete the tasks of permitting officials can save time and reduce errors for big and small permitting authorities alike.
In 2018, SEIA and nonprofit the Solar Foundation launched the Solar Automated Permit Processing initiative and enlisted the U.S. National Renewable Energy Laboratory to develop an automated permitting platform. SolarAPP+ was the result. After pilot tests in 2020 proved it dramatically sped up permitting without sacrificing quality, the platform was made available at large.
Automated permitting turns multiple back-and-forth processes into a “one- to two-page digital form,” Birch said. Code standards groups like Underwriters Laboratories and the International Code Council have signed off on SolarAPP+, and similar automated platforms from startups and from city permitting departments are now providing similar same-day options.
The advantages of instant permitting are so great, Cinnamon said, that he’s stopped doing projects in cities and counties that don’t offer some form of it. With less than six months to finish projects that can secure tax credits, “we don’t have the time” to spend elsewhere, he said.
The next step is to expand instant permitting from hundreds to thousands of cities and counties by taking on statewide permitting reforms, said Nick Josefowitz, CEO of Permit Power, a nonprofit advocacy group.
Over the past several years, states including Democratic strongholds like California and Maryland as well as Republican redoubts like Florida and Texas have adopted solar permitting reform laws, he said. New Jersey lawmakers passed a bill this summer that now awaits Gov. Phil Murphy’s signature.
Reform looks different in every state. California set mandates for cities and counties to use instant permitting, while Texas and Florida required cities and counties to allow licensed and credentialed third parties to issue permits and conduct inspections on homeowners’ behalf. Colorado’s law backed off on mandates but offered incentives for local authorities to deploy instant permitting, while New Jersey’s law would empower a state agency to set up instant permitting for cities and counties to use.
Lowering permitting costs can allow solar installers to cut their prices, which increases their business, spurs more competition, and gives households more options, Josefowitz said. A series of studies this year from Brown University’s Climate Solutions Lab and the Greenhouse Institute found that streamlined and instant permitting in Arizona, Colorado, Illinois, Minnesota, New Jersey, New York, and Texas could result in an additional 2 million home solar installations between now and 2030, saving households a collective $100 billion.
The results are good not just for households and solar installers but for cash-strapped municipalities, said Elowyn Corby, mid-Atlantic regional director for nonprofit group Vote Solar, which advocated for New Jersey’s newly passed reform bill.
“When you put the onus on municipalities to process these permit applications, that’s an enormous drain on their resources as well, especially in lower-income communities where there isn’t as much municipal infrastructure,” she said. “We’re hoping this brings capacity back to local governments.”
Permits aren’t the only solar roadblocks. Utilities also need to approve solar and battery systems at homes connected to their grids before they’re allowed to be turned on. Solar installers have long complained that slow or costly interconnection processes are a significant drag on their bottom lines.
“I’ve heard from some of our installers — and some of the bigger ones — that the interconnection approval process is more of a challenge and a bigger cost than the permitting side,” said Ravi Mikkelsen, CEO of Atmos Financial, a financial technology company that connects lenders with solar installers and customers. “Some utilities are better than others, but across the board, this is a major issue.”
Interconnection rules are complicated, and utilities apply them differently. But reports from solar installers over the years have highlighted problems ranging from lengthy waiting times and restrictions on new solar hookups to exorbitant costs assessed on homes wanting to interconnect.
A lack of state regulator oversight for interconnection policies complicates efforts at reform, Josefowitz said.
Regulators in some states like California set rules for all regulated utilities, but other state regulators don’t. Even those that have set statewide guidelines for utilities have been slow to adopt rules that require them to put in place more streamlined processes or take the latest technology advances into account. A 2023 ranking from Vote Solar and the nonprofit Interstate Renewable Energy Council assessed state adoption of interconnection “best practices.” The groups gave only New Mexico an A grade and six other states B grades, while marking 13 with an F for lacking any statewide standards.
“We need [regulator] rules about when projects can be fast-tracked, what types of systems when and where can be automated and approved by software,” Josefowitz said.
Extreme amounts of rooftop solar can cause problems on power grids designed to carry electrons from big substations to customers.
“But batteries totally change the game on this,” he said, enabling homes to store solar power when utility grids don’t need it and release it when they’re in short supply.
That’s why solar companies ranging from nationwide players like Sunrun to regional and local installers are recasting their business approach to include becoming “virtual power plant” providers — active providers of energy and grid resources that help augment the resources that utilities can bring to bear.
Opportunities to earn money for these services are relatively scarce today. But with Republicans in Congress and the Trump administration making it much more expensive and difficult to build more renewable energy to meet the growing demand for electricity, utilities may be well advised to reduce the barriers to installing solar and batteries that can provide it, Mikkelsen pointed out.
“At $2 a watt, you can bring down the cost of your power, and you can save money on electrification,” he said. But also, “your battery can be used economically much more frequently and becomes super-valuable to the grid. You want to unlock the power of batteries? You fill them with cheaper electrons.”
Maine is sprinting to build clean energy projects before federal tax credits expire.
State utility regulators are fast-tracking plans to procure nearly 1,600 gigawatt-hours of renewable energy, with the goal of getting projects started before key incentives disappear under the budget law signed by President Donald Trump this month. Developers were given just two weeks to submit proposals, with a deadline of July 25.
These projects should help the state make up for clean-energy developments derailed by the pandemic, and ultimately progress toward its newly mandated target of 100% clean energy by 2040.
“This is an opportunity to get some things done that Maine had every intention of getting done a handful of years ago,” said Eliza Donoghue, executive director of the Maine Renewable Energy Association, a nonprofit industry group. “It’s good news.”
The move comes as the clean-energy industry pushes other states, including New York and California, to help speed up wind and solar deployments before subsidies expire in the coming years.
For its part, Maine is looking for enough bids to meet roughly 13% of its annual electricity usage. Preference will be given to developments that make use of property contaminated by toxic PFAS, following the discovery in recent years that at least 60 Maine farms have unsafe levels of these “forever chemicals” in their soil and water.
This specification is a win for renewable energy, wildlife, and farmers whose land has been rendered unusable for agriculture, said Francesca Gundrum, director of advocacy for Maine Audubon.
“This work to help deploy solar and other renewable technologies is exactly the kind of siting we need to see more of in Maine,” she said. “Whatever we can do to minimize the turnover of habitat is something we’re going to be supportive of.”
The current procurement has its roots in a bill the Maine Legislature passed in 2023, calling for the state to source renewable energy from installations sited on PFAS-contaminated land. A request for proposals was issued in August 2024, but none of the initial bids were deemed cost-effective, and none were selected. This year, the Legislature went back to the drawing board, tweaking details about how solar and storage projects can enter proposals.
The amended bill was enacted in June with an “emergency preamble,” allowing it to become law immediately, rather than waiting the typical 90 days after the legislative session adjourns. That move required the approval of at least two-thirds of lawmakers in both the state Senate and House, which is an encouraging sign of support for renewables across political divides, said Dan Burgess, director of the Maine Governor’s Energy Office.
“It’s really exciting that a bipartisan coalition of legislators sees this as an opportunity to bring on low-cost clean energy in Maine,” he said.
Previous renewable energy procurements in 2020 and 2021 chose 24 wind and solar developments to buy power from. Many of these projects, however, fell apart when the COVID-19 pandemic disrupted global supply chains and drove up inflation, Burgess said. This latest solicitation is a great opportunity to make up some of that lost ground, he said.
Maine was an assertive early adopter of the “renewable portfolio standard,” a state-level regulation that requires utilities to obtain a certain percentage of their power supply from renewable resources. When Maine adopted the policy in 1999, it required 30% of the electricity sold to be renewable (a number it hit immediately because of the high concentration of hydropower in the state). The total requirement increases over the years; the state is now aiming for 90% renewables by 2040 with the final 10% coming from non-emitting but not necessarily renewable sources, like nuclear.
Today, about 32% of Maine’s electricity comes from gas-fired power plants, and another 31% from hydropower. Solar and wind together contribute roughly one-quarter of the supply.
Studies suggest that Maine’s commitment to renewable energy has already saved residents significant sums and stands to create even more financial benefits. A 2024 report on the impact of the renewable portfolio standard found that utility customers saved a total of about $21.5 million each year from 2011 to 2022. An analysis released in January concluded that reaching 100% clean energy by 2040 would save the average Maine household around $1,300 per year.
The current procurement is to be the last under the existing regulatory structure, in which the state Public Utilities Commission is the body that runs such solicitations. Legislation signed this month will create a cabinet-level energy department — currently Maine has only an energy office — with the authority to run regular procurements as needed to advance the state’s renewable energy goals.
“Instead of doing these one-off procurements specifically directed by the Legislature, we’re now getting to have that predictability,” Donoghue said.
A controversial bill to unravel North Carolina’s climate law would cost the state more than 50,000 jobs annually and cause tens of billions of dollars in lost investments, a new study finds. The research comes days before the Republican-controlled state legislature aims to override a veto of the measure by Gov. Josh Stein, a Democrat.
First passed by the Senate in March, the wide-ranging Senate Bill 266 repeals the 2030 deadline by which utility Duke Energy must curb its climate pollution 70% compared to 2005 levels. It leaves intact a mandate that the company achieve carbon neutrality by midcentury.
Senate leader Phil Berger, a 13-term Republican from Rockingham County, has said his chamber will vote on the override Tuesday, July 29. The House, which approved the bill with bipartisan support in June, could attempt an override of Stein’s July 2 veto the same day.
Conducted by BW Research for clean energy nonprofits, the new analysis draws on earlier projections from Public Staff, the state-sanctioned customer advocate. That modeling showed that without a near-term climate goal, Duke would build about 40% less new generation capacity over the next decade — leaning harder instead on aging fossil-fueled units to meet demand.
The fresh research calculates the economic losses of foregoing those new power plants, including massive amounts of solar and wind along with 300 megawatts of new nuclear and 1,400 megawatts of combined-cycle gas plants.
From 2030 to 2035, North Carolina would see nearly 50,700 fewer jobs annually and over $47.2 billion sacrificed in power-plant construction, the study says. More than $1.4 billion in tax revenue would also be left on the table.
“This study conveys in real terms the impact of arbitrarily removing a market signal that has proven to be a job creator and an economic booster for North Carolina,” said Josh Brooks, chief of policy strategy and innovation with the North Carolina Sustainable Energy Association.
BW Research finds that if SB 266 became law, Duke would have 12 fewer gigawatts of capacity in 2035 to meet peaks in power demand, like those that happen on unusually cold winter mornings. Experts say the company would likely have to purchase more out-of-state power or rely more heavily on fossil fuels as a result.
“This limitation hampers the state’s ability to meet current energy needs and undermines its competitive edge in attracting energy-intensive industries,” the analysts say.
The new study is the second to show how Public Staff’s modeling belie claims from SB 266 proponents that the bill will save money and promote more power generation.
Late last month, three researchers from North Carolina State University found that with fewer solar, wind, and nuclear plants as projected by Public Staff, Duke would have to burn almost 40% more natural gas between 2030 and 2050.
Under a worst-case but plausible scenario for gas prices, the trio found, customers could pay $23 billion more in fuel costs on their electric bills by midcentury as a result. The figure would cancel out projected consumer savings from building fewer new sources of generation, a fact not lost on the governor.
“My job is to do everything in my power to lower costs and grow the economy,” Stein said in a statement when he vetoed SB 266 early this month. “This bill fails that test.”
In his veto message, Stein also referenced another study, from EQ Research, showing the measure would make energy more expensive for North Carolina households.
“[SB 266] shifts the cost of electricity from large industrial users onto the backs of regular people,” Stein said. “Families will pay more so that industry pays less.”
Still, the findings from independent researchers and the three NC State professors may not be enough to counter the lingering narrative that SB 266, dubbed the Power Bill Reduction Act, will help customers.
Duke Energy and major industrial groups have lined up in support of the measure — the latter falsely suggesting that solar power investments have raised electric rates.
The North Carolina Chamber, the state’s major business lobby, says the bill’s enactment would provide “businesses and consumers with more affordable, predictable energy costs.” The group plans to include SB 266 in its annual scorecard rating legislators’ performances.
Perhaps most daunting for clean energy advocates and other bill opponents is that several Democrats appear swayed by these arguments. While Republicans have enough members to overrule Stein in the upper chamber, they’re one vote shy in the House. With all members present, that means the 11 House Democrats who previously voted for SB 266 would need a change of heart to uphold Stein’s veto.
House Speaker Destin Hall, a Republican from Caldwell County, says that won’t happen.
“I’m disappointed in the governor’s veto of the ‘Power Bill Reduction Act,’ which would have delivered cheap, reliable energy to North Carolina, cut the red tape that is choking innovation and long-term energy solutions, and saved consumers over $12 billion dollars,” Hall said in statement moments after Stein rejected the bill. “Considering the strong bipartisan support in both chambers, we anticipate overriding this veto.”
But Will Scott, Southeast climate and clean energy director for the Environmental Defense Fund, hopes the study will help change lawmakers’ minds.
“This shows that passing this legislation is going to have negative consequences for our ability to meet growing demand,” he said, “and that’s going to have knock-on economic impacts across the state.”
The rooftop solar industry is facing an unprecedented crisis. Utilities are cutting incentives. Major residential solar installers and financiers have gone bankrupt. And sweeping legislation just passed by Republicans in Congress will soon cut off federal tax credits that have supported the sector for 20 years.
But the fact remains that solar panels — and the lithium-ion batteries that increasingly accompany them — remain the cheapest and most easily deployable technologies available to serve the ever-hungry U.S. power grid.
Sachu Constantine, executive director of nonprofit advocacy group Vote Solar, thinks that the rooftop solar and battery industries can survive and even thrive if they focus their efforts on becoming “virtual power plants.”
Hundreds of thousands of battery-equipped, solar-clad homes across the country are already storing their renewable energy when it’s cheap and abundant and then returning it to the grid when electricity demand peaks and utilities face grid strains and high costs — in essence, acting as “peaker” power plants.
In places like Puerto Rico and New England, these VPPs have demonstrated their worth in recent months, preventing blackouts and lowering costs for consumers, and the approach could be scaled up dramatically. “If we do that, despite the One Big Beautiful Bill, despite the headwinds to the market, there is space for these technologies,” Constantine said.
Right now, there aren’t many other options for meeting soaring energy demand, he added. The megabill signed by President Donald Trump this month undermines the economics of the utility-scale solar and battery installations that make up the vast majority of new energy being added to the grid. And despite the Trump administration’s push for fossil fuels, gas-fired power plants can’t be built fast enough to make up the difference.
Meanwhile, the U.S. power grid has not expanded quickly enough, increasing the risk of outages and subjecting Americans to the burden of rising utility rates, Constantine said. State lawmakers and utility regulators are under growing pressure to find solutions.
Solar and batteries, clustered in small-scale community energy projects or scattered across neighborhoods, may be “the only viable way to meet load growth” from data centers, factories, and broader economic activity, Constantine said. And by relieving pressure on utility grids, they can help bring down costs not just for those who install them, but for customers at large.
This summer has brought new proof of how customers can turn their rooftop solar systems and batteries to the task of rescuing their neighbors from energy emergencies. Over the past two months, Puerto Rico grid operator LUMA Energy has relied on participants in its Customer Battery Energy Sharing program to prevent the grid from collapsing.
“Last night we successfully dispatched approximately 70,000 batteries, contributing around 48 megawatts of energy to the grid,” LUMA wrote in a July 9 social media post in Spanish. Amid a generation shortfall of nearly 50 MW, that dispatch helped avert “multiple load shedding events” — the industry term for rolling blackouts.
Puerto Ricans have been installing solar and batteries at a rapid clip since 2017, when Hurricane Maria devastated the island territory’s grid and left millions of people without power, some for nearly a year.
“There were tens of thousands of batteries already there that just needed to get connected in a more meaningful way,” said Shannon Anderson, a policy director focused on virtual power plants at Solar United Neighbors, a nonprofit that helps households organize to secure cheaper rooftop solar. “The numbers have been really proven out this summer in terms of what it’s been able to do.”
Puerto Rico’s VPPs are managed by aggregators — companies that install solar and battery systems and control them to support the grid. Tesla Energy, one such aggregator, provides live updates on how much the company’s Powerwall batteries are contributing to the system at large.
The impacts of distributed solar and batteries aren’t always so easy to track — but clean-energy advocates are busy calculating where they’re making a difference.
During last month’s heat wave across New England, as power prices spiked and grid operators sought to import energy from neighboring regions, distributed solar and batteries reduced stress on the grid. Nonprofit group Acadia Center estimated that rooftop solar helped avoid about $20 million in costs by driving down energy consumption and suppressing power prices.
A good portion of that distributed solar operates as part of the region’s VPPs. The ConnectedSolutions programs run by utilities National Grid and Eversource cut demand by hundreds of megawatts during summer heat waves. And Vermont utility Green Mountain Power has been a vanguard in using solar-charged batteries as grid resources at a large scale, in concert with smart thermostats, EV chargers, and remote-controllable water heaters. All told, that scattered infrastructure gives the company 72 extra megawatts of capacity to play with during grid emergencies.
Mary Powell, who led Green Mountain Power’s push into VPPs before that term had caught on, left to become CEO of Sunrun, the country’s largest residential solar installer, in 2021. Choosing to hire Powell indicated the company’s growing interest in becoming something of a solar-powered utility.
This summer, Sunrun dispatched hundreds of megawatts from more than 130,000 batteries across California, New York, Massachusetts, Rhode Island, and Puerto Rico. It recently expanded into Texas’ competitive energy, in partnership with Tesla.
“We are living in the future of virtual power plants in places like Puerto Rico, and California, and New England, and increasingly Texas,” said Chris Rauscher, Sunrun’s head of grid services and electrification. “It’s just about other states putting that in place in their territories and letting it run.”
Sunrun, Vote Solar, and Solar United Neighbors have been working for the last year to advance state policies that support VPPs. So far this year, the groups have promoted model VPP legislation in states including Illinois, Minnesota, New Mexico, Oregon, and Virginia.
In May, Virginia passed a law requiring that utility Dominion Energy launch a pilot program to enlist up to 450 megawatts of VPP capacity, including at least 15 MW of home batteries, Anderson said.
The legislative effort has had less luck in New Mexico and Minnesota, where bills failed to advance, Anderson said. In Illinois, a proposed bill did not pass during the regular legislative session, but advocates hope to bring it back for consideration during the state’s “veto session” this fall, she said.
A lot more batteries are being added to rooftop solar systems in Illinois, Anderson noted — a byproduct of the state clawing back net-metering compensation for solar-equipped customers starting this year. Similar dynamics have played out in Hawaii and California after regulators reduced the value of solar power that customers send back to the grid, making batteries that can store extra power and further limit customers’ grid consumption much more popular.
Rooftop solar advocates have fought hard to retain net-metering programs across the country. But Jenny Chase, solar analyst with BloombergNEF, noted that most mature rooftop solar markets have shifted away from rewarding customers for sending energy back to the grid at times when it’s not needed.
“In some ways that’s justified, because net metering pushes all responsibility and cost of intermittency onto the utility,” she said.
VPPs flip this dynamic, turning rooftop solar and batteries from a potentially disruptive imposition on how utilities manage and finance their operations to an active aid in meeting their mission of providing reliable power at a reasonable cost. Utilities have traditionally been leery of trusting customer-owned resources to meet their needs. But under pressure from lawmakers and regulators, they’re starting to embrace the possibilities.
In Minnesota, utility Xcel Energy has proposed a “distributed capacity procurement” program that would allow it to own and operate solar and batteries installed at key locations, letting the company defer costly grid upgrades. Rooftop solar advocates have mixed feelings about the proposal, given their longstanding complaints about Xcel’s track record of making it more difficult for customers and independent developers to build their own solar and battery systems.
Similar tensions are at play in Colorado, where Xcel is under state order to build distributed energy resources like rooftop solar and batteries into how it plans and manages its grid. This spring, Xcel launched a project with Tesla and smart-meter company Itron aimed at “taking these thousands of batteries we have connected to this system over time and [being] able to use them to respond to local issues,” Emmett Romine, the utility’s vice president of customer energy and transportation solutions, told Canary Media in an April interview.
But waiting for utilities to deploy the grid sensors, software, and other technology needed to perfectly control customers’ devices runs the risk of delaying the growth of VPPs, Anderson said. Simpler approaches like those being taken in Puerto Rico — where aggregators manage VPPs — can do a lot of good quickly. “Once you get that to scale, there will be a lot of learnings for the next stage,” she said
State- and utility-level incentives that encourage individuals to participate in VPPs are also a vital countermeasure against the damage incurred by the “big, beautiful bill” passed by Republicans this month, Anderson said. Under that law, households will lose a 30% tax credit that offsets the cost of solar, batteries, and other home energy systems by the end of this year.
However, companies such as Sunrun and Tesla will retain access to tax credits for solar systems that they own and provide to customers through leases or power purchase agreement structures, as long as they begin construction by mid-2026 or are placed in service by the end of 2027. And tax credits for batteries remain in place until 2033 for these companies.
VPP programs can’t make up for the loss of the tax credit for customers who haven’t yet installed solar or batteries, Anderson said. But by financially rewarding participants, they can help consumers recoup initial costs, she said, as long as they aren’t hampered by ineffective state policies.
“Folks can earn over $1,000 a summer through [some VPPs],” she said. “You couple in the leasing model for solar and storage, which is going to get a little more popular in the aftermath of the bill,” due to its ability to continue to earn tax credits, “and I think it’s a pretty good way to get batteries for low or no cost up front.”
A contested solar agrivoltaics project avoided having its permit denied by Ohio regulators, likely thanks to the neutral stances of a county board and one of its townships.
The Ohio Power Siting Board approved construction of the 120-megawatt Frasier Solar project late last month despite local groups’ organizing efforts, which led the other township within the project’s 840-acre footprint and a neighboring township to pass anti-solar resolutions. The power siting board has found that unanimous local government opposition was reason enough to decide other solar projects did not meet a public interest requirement under state law. One of those cases is before the Ohio Supreme Court.
In the Frasier case, however, local governing bodies for Knox County and Clinton Township stayed neutral. Knox County voted unanimously in 2023 to accept a payment arrangement instead of property taxes, which will add more than $40 million for local governments over the project’s 40-year useful life, but it took a neutral position on the project itself.
About six months after an evidentiary hearing — basically an administrative trial — on Frasier Solar, Knox County restricted new solar projects within most of its boundaries. However, legal counsel for the Ohio Ethics Commission found that a conflict of interest prevented Drenda Keesee, a newly elected Knox County commissioner, from taking official action against Frasier Solar because she owned property next to the project site. Another county commissioner served as an ad hoc power siting board member for the Frasier decision, so he could not take a position before hearing the case. He wound up voting with the board’s majority to grant the permit.
Prior to the administrative trial, Clinton Township’s board had clarified that despite an anti-solar position for future projects, it was officially neutral on Frasier Solar.
“We had a very small dog in the fight,” Clinton Township Trustee Jay Maners told Canary Media, noting that most of the project will be in Miller Township. He recalled that there was sparse attendance at early trustee meetings when the project was discussed, with most in favor of it. Then “everything exploded” with people suddenly voicing opposition, he said.
“There was a lot of misinformation,” Maners said, such as solar opponents falsely claiming tax dollars would pay for the project, and solar proponents warning about rising energy prices.
The Ohio Power Siting Board’s June 26 ruling discussed Clinton Township’s neutral stance on Frasier Solar, as well as that of Knox County, to stress that local government opposition was not unanimous. The board found that the project was in the public interest and approved the permit.
Supporters are celebrating the win for Frasier Solar but worry about how much the power siting board focused on whether local government opposition was unanimous. That leaves solar energy vulnerable to a standard that depends on potentially arbitrary local government rulings, rather than regulatory experts’ judgment of projects’ merits.
Frasier Solar is exempt from parts of Senate Bill 52, a 2021 law that lets counties block large solar and wind projects before they get to the power siting board. Yet its developer, Open Road Renewables, faced substantial local opposition and misinformation, much of which was stoked by a dark money group with multiple connections to fossil fuel interests and the anti-solar speakers it brought in. Opponents also went to local township meetings to push for anti-solar resolutions.
The staunch local opposition and involvement of fossil fuel interests fit a pattern playing out across the country. The Sabin Center for Climate Change Law at Columbia University last month reported a 32% jump in the number of contested projects for 2024 compared with 2023.
Only within the past few years have state regulators used unanimous local government opposition as a reason to kill proposed solar projects. Those projects, like Frasier, were otherwise exempt from parts of the 2021 law. But Ohio regulations don’t contain such a rule. Another part of Ohio law appears to say that local government consent isn’t a condition for siting decisions.
“I’m certainly happy to see this project move forward, and it had every reason to move forward,” said Dan Sawmiller, Ohio energy policy director for the Natural Resources Defense Council. Yet he questioned what the role of the power siting board is if it lets unanimous local opposition control whether projects go ahead.
“They’ve got the goal post cemented in, and it’s in the wrong location,” Sawmiller said. As he sees it, the board and its staff have a responsibility to use their expertise to make decisions in the public interest for the whole state.
It’s also hard to fact-check local government resolutions, said Heidi Gorovitz Robertson, a Cleveland State University law professor who testified as an expert witness for the Ohio Environmental Council. Those decisions could be based on misinformation or simply be a response to political pressure, with little focus on the factual basis for objections.
Frasier Solar became “known nationally as part of a case study on how the fossil fuel industry stokes opposition to renewable energy projects,” said Dave Anderson, policy and communications director for the Energy and Policy Institute, a watchdog group on utility and fossil fuel influence.
Testimony at the administrative trial revealed that an anti-solar group called Knox Smart Development had big financial backing by Tom Rastin, who has been a leader of the Empowerment Alliance, an anonymously funded group that promotes the natural gas industry. Rastin is a former vice president of Ariel Corp., which makes equipment for the oil and gas industry.
Anti-solar media flourished throughout the area during the permitting process too. An eight-page Ohio Energy Reporter sent by bulk mail consisted mostly of anti-solar advertorials. Anti-solar stories and ads also ran in outlets such as the Mount Vernon News, which ProPublica described as a conservative “pink slime” publication.
Evidence introduced by the developer last summer characterized some of the opposition’s publicity as “misinformation campaigns,” which the power siting board noted in its opinion.
Nonetheless, the project had an “encouraging level of support, both locally and from across the state,” said Craig Adair, vice president for development at Open Road Renewables. About 40% of those who spoke at local public hearings or filed comments favored the project.
More significantly, the siting board considered the merits of comments, not just the total numbers. In doing so, the board focused on Robertson’s testimony, which found that half of opponents’ unique arguments at local hearings were factually inaccurate or unsupported by evidence. About a third were already addressed by permit conditions, and nearly one-tenth were just subjective opinions, she also found.
“The happy news is that the siting board and the staff weren’t snowed by the number of opposing comments,” Robertson told Canary Media. “We really were able to take the wind out of their sails on the vast majority of the negative comments.” A similar analysis may help in future cases, she suggested. “We can’t let truth and facts disappear. We have to keep pushing what is real.”
The board’s ruling also noted evidence provided by chapters of the International Brotherhood of Electrical Workers about jobs and other positive economic benefits. Additional experts for the Ohio Environmental Council described how the solar farm and revenue from it could help local governments deal with climate change impacts.
“Given the risks Ohio faces from climate change, the board’s review of any application is incomplete without considering impacts,” said Karin Nordstrom, one of the Ohio Environmental Council’s lawyers in the case.
Adair welcomed the other parties’ supporting evidence and said he hopes to see the same level of scrutiny in future cases. “As long as the board continues to review projects on their merits and not fall prey to the misinformation, it’s encouraging,” he said.
Still, solar and wind projects continue to face hurdles under state law that don’t apply to fossil fuels. While counties now have the power to block most large solar and wind projects, local governments can’t even enforce zoning restrictions against oil and gas development.
“A lot of businesses are going to say, ‘I’ll take my investment elsewhere,’” Adair said. And while some projects like Frasier may get approval, the combination of SB 52 and other deference to local governments “is going to leave you vulnerable to getting the supply that you need on the grid,” he added.
An enormous array of over 750,000 solar panels blankets the prairie landscape in Pueblo, Colorado, providing clean energy to one of the largest electricity-based steel mills in the country.
The Rocky Mountain Steel mill, which opened in 1881, today uses electricity instead of coal to produce steel rails and pipes. In late 2021, it became the first and largest solar-powered steel plant in the United States — and possibly the world — when electricity began flowing from the 300-megawatt Bighorn Solar project next door, supplying roughly 90% of the power used by the facility’s electric arc furnace.
The storied steel mill recently marked a different kind of milestone. Atlas Holdings, a private-equity firm in Connecticut, said last month that it plans to acquire Evraz North America, which owns the facility in Pueblo as well as steelmaking operations in Portland, Oregon, and Western Canada. The sale is expected to close later this year.
“This [is] a major investment in creating a more vibrant domestic steel production industry right here in the United States and Canada,” Sam Astor, a partner at Atlas, said in a June 27 news release.
The deal, which could reach up to $500 million, arrives at a complex moment for U.S. steelmakers working to decarbonize their facilities.
Recent U.S. efforts to build cutting-edge, low-emissions ironmaking facilities that use green hydrogen — made with renewable power — have all but vanished due to challenging economics and shifting political tides. Building large clean-energy projects like Bighorn Solar to power industrial sites just got much harder to do under the megabill that President Donald Trump signed into law this month, which slashes incentives for and imposes restrictions on wind and solar.
At the same time, the nation’s steel industry is slowly getting cleaner as manufacturers invest in new capacity that relies on electricity and fossil gas, not coal. And Rocky Mountain Steel is no longer the country’s only solar-powered steel plant. U.S. Steel’s Big River Steel mill in Arkansas draws from the 250-MW Driver Solar project, while steelmaker Nucor Corp. has a deal to buy 250 MW of power from the Sebree Solar farm under construction in Kentucky.
Steel is an essential material used to make everything from railroads, bridges, and buildings to solar-panel racks, electric vehicles, and grid components. Producing the high-strength metal is currently an extremely dirty business, responsible for as much as 9% of global carbon dioxide emissions and a significant amount of harmful local air pollution.
That’s because most steel production globally involves burning copious amounts of coal in a blast furnace to turn raw iron ore into iron; the iron is then made into steel in a separate furnace. The United States still operates a dozen blast furnaces, which account for roughly 30% of the country’s annual steel production.
The remaining 70% of U.S. steel output comes from electric arc furnaces, including the hulking unit at Rocky Mountain Steel’s facility, which is capable of producing 1.1 million tons of steel per year. These power-hungry furnaces turn scrap metal into a glowing orange liquid that is then transformed into recycled steel parts.
Producing steel this way can curb CO2 emissions by up to 75% compared to traditional coal-based methods, according to industry research. However, the carbon intensity of steel made in an electric arc furnace depends on the electricity used — and most of the 100-plus such facilities operating in the U.S. rely primarily on coal- and gas-fired electric grids.
Until a few years ago, Rocky Mountain Steel got its power from Xcel Energy’s coal-fired power plant in Pueblo.
Lightsource bp financed, owns, and operates the neighboring $285 million Bighorn Solar project. The developer sells the electricity it generates to Xcel under a 20-year power purchase agreement; the utility then provides power to Evraz North America for the steel mill. When the 1,800-acre solar array came online in late 2021, Bighorn became the nation’s largest on-site solar facility dedicated to a single customer.
“This project proves that even hard-to-abate sectors like steel can be decarbonized when companies come together with innovative solutions,” Kevin Smith, who was then the CEO of Lightsource bp, Americas, said in an October 2021 press release. The fixed-rate power agreement gives the mill’s owner “the low, predictable electricity prices it needs to stay in Pueblo and invest in its future there, keeping more than 1,000 jobs in the local community,” according to the release.
Evraz North America first announced plans to sell its assets in August 2022 after its parent company, Evraz plc, was sanctioned by the British government following Russia’s invasion of Ukraine. Evraz plc is part-owned by a Russian oligarch.
Atlas Holdings, the firm acquiring Evraz North America, didn’t immediately return questions this week about whether the sale would affect the solar-power agreement in Pueblo. However, Atlas noted in its June 27 news release that the “Pueblo steel mill stands as a remarkable testament to commitment to sustainability” owing to the solar project.
The American solar manufacturing renaissance was charging ahead. Then President Donald Trump took the reins.
Since Trump resumed occupancy of the White House, promising to bring back manufacturing jobs, new investment in clean energy factories has plummeted from its Biden-era highs, and factory cancellations have surged instead. Now, with Trump’s signing of the One Big Beautiful Bill Act earlier this month, things are about to get even rockier for clean energy manufacturers — but several of the leading firms reshoring solar panel production still see reasons for qualified hope.
That’s not to say the path ahead will be easy. The law swings a battle-axe through the clean energy incentives that were carefully crafted by Democrats in the 2022 Inflation Reduction Act. Solar and wind deployment credits will disappear after 2027. Now, the U.S. will install somewhere between 57% to 62% less clean energy from 2025 to 2035, per a new analysis by Rhodium Group. That’s bad for all the customers and industries who will need vastly more electricity over that timeframe — not to mention the climate — but it also portends a shrinking market for American manufacturers to sell into.
“It’s a massive self-inflicted wound,” said Sen. Jon Ossoff (D-Ga.), an architect of the original clean energy manufacturing policy. “This law is a targeted attack on the advanced energy industry. It will hamstring industrial development; it will undermine energy independence and drive up energy costs by interrupting the development and installation of new generation capacity.”
But for manufacturers who have kickstarted a stunning reshoring of the solar supply chain after years of decline, the legislation’s final form is not nearly as dire as some earlier drafts. Chiefly, Republicans preserved the flagship manufacturing credit, which pays a company for each unit they make of key clean-energy components.
“Because manufacturing and job creation has always been a highlight of all politicians, independent of their party, that part has not been touched,” said Martin Pochtaruk, CEO of Heliene, which runs 1.3 gigawatts of domestic module production in Minnesota. However, the new law “has axed the businesses of many of our clients two years out, so it will require a lot of work by a lot of people to reshuffle how their businesses are run, and how they finance.”
The one major change the law did make to the manufacturing tax credit was to add in “foreign entity of concern,” or FEOC, restrictions, a whole new bureaucratic regime that polices companies’ corporate or supply-chain ties to China. New FEOC restrictions also apply to energy projects, and they actually resemble policies several domestic manufacturers have been requesting for years.
Take the case of T1 Energy, a solar manufacturer currently churning out 12,000 modules a day outside Dallas, on track for up to 3 gigawatts produced this year. Chinese giant Trina Solar actually built the factory but sold it to T1 (formerly known as Freyr Battery) in December, such that it is now operating under the control of a U.S.-based firm traded on the New York Stock Exchange. The company’s executive vice president for strategic communications, former longtime Wall Street Journal energy correspondent Russell Gold, called the law’s FEOC measures “good policy.”
“It promotes U.S. ownership and control of solar manufacturing and solar production,” Gold said. “Given how important solar is becoming on our power grids, that’s totally appropriate.”
Dean Solon, the billionaire solar entrepreneur who has manufactured connectors and cabling systems in Tennessee since the dawn of the modern solar industry, seemed unconcerned when I asked him in June about whether the new FEOC rules were too stringent.
“FEOC? Isn’t that a shitty little Italian car?” he responded.
For now, solar manufacturers that have factories operating or nearly operational can squint and see a good few years ahead while the tax credits are still accessible, though after that, it’s anybody’s guess. Companies that were about to commit to the multiyear effort to build new factories, however, just got an undeniable signal from Congress to take their jobs and economic dynamism elsewhere.
“The hill’s a lot steeper than it was before this for those kinds of investments,” said Mike Carr, executive director of the Solar Energy Manufacturers for America Coalition.
Somewhat improbably, Trump’s signature policy effort let the Biden-era 45X clean energy manufacturing credit continue as planned before phasing down after 2030 and stopping entirely in 2033 (except for wind manufacturing, which got whacked with an early end).
Unlike the earlier House version, Gold noted, the law preserves transferability, which lets factories monetize their credits when they lack sufficient tax burden themselves; factories cost a lot up front before they start making money, so this is especially useful in their early years. Factories almost lost stackability, which guarantees credits for companies that produce several steps of the supply chain, but the final text preserved that, Gold added.
“When you look at 45X, which is what solar manufacturers do receive, it is exactly like what was included in the Inflation Reduction Act and proposed by Sen. Ossoff in the Build Back Better days,” Pochtaruk said.
That has direct implications for a solar cell factory Pochtaruk was developing somewhere in the U.S. but put on hold after the election as he waited to see if 45X would survive. Now that its fate is clear, Heliene can return to developing that factory, if the company determines it still makes sense in the new market landscape.
The major lingering concern for solar manufacturers is what happens next with their customers. The law, after all, attacks the demand-side credits that were designed to stimulate purchases of made-in-America solar products.
The early demise of the solar deployment credits will hit manufacturers in two major ways.
First, with the stroke of Trump’s pen, the amount of clean energy projects expected to come online in the U.S. over the next decade just dropped. Demand for the American factories that opened up to serve that market just took a commensurate hit. Americans pay a lot more for solar panels than the rest of the world, due to the trade protectionism in place to help factories here; thus, U.S.-made solar is for U.S. consumers, and can’t readily export to foreign markets if domestic demand suddenly drops.
Second, in destroying the solar deployment credits, Republicans also eliminated the domestic content adder, a bonus incentive that encouraged developers to pick domestic equipment over cheap imports.
“They removed the key incentive driving investment in American manufacturing of solar technology,” Ossoff said. “Go ask the industry. This is a huge gift to the Chinese Communist Party, which will reinforce China’s stranglehold on the solar value chain.”
Marta Stoepker, a spokesperson for Qcells, which runs the largest solar-module factory in the U.S., located in Dalton, Georgia, corroborated the importance of that policy for encouraging domestic purchases.
“Policy levers like domestic content and trade are critical to ensuring U.S.-made solar can compete against China,” she said.
That said, the new megabill might leave a path for solar installations to continue at a healthy clip for the next five years. It’s the five years after that when solar could fall off a cliff.
Under the new law, solar developers need to start building their projects between now and July 4, 2026, to secure the full 30% investment tax credit. (If they start after that date, arrays must be placed in service by the end of 2027.) Starting Jan. 1 next year, companies will also need to meet the newly written FEOC rules that limit the amount of Chinese-produced materials in a power plant. As far as the IRS is concerned, developers have officially started building once they begin physical construction or buy 5% of the overall capital cost of the project — say by purchasing transformers or inverters. Then, under what’s called safe-harboring rules, developers have four years from the end of that year to finish the project, provided they show continued progress.
That timeline, then, could support something close to the recent high level of solar deployment into 2030, which would be great for newly minted factories that need a little more time to get their footing. Qcells is racing to finish a new factory in Cartersville, Georgia, that will produce 3.4 gigawatts of panels and the cells and wafers that go into them. T1 is still ramping up to its full capacity of 5 gigawatts.
If the market follows the pattern from previous times Congress was set to end solar incentives, developers will rush to safe-harbor projects before the deadline, fast-tracking work that could have been spaced out over the next few years. Then they’ll have several more years to buy the rest of the project equipment, giving domestic factories more time to spin up.
Nonetheless, factories will have to navigate upheaval among their customers in the mad dash to lock in these incentives. Larger developers can afford to hustle and start a number of projects in the next year to secure the full tax credit. Smaller developers typically finish and sell projects to finance their next efforts, a strategy that could be foiled by this truncated timeline.
“There is going to be consolidation, because the larger entities will buy out projects developed by smaller ones that cannot continue to bring them forward,” said Pochtaruk.
Besides the impending blows to domestic demand, a few other variables could skew the fate of the solar manufacturing renaissance.
For one thing, manufacturers will have to navigate the new FEOC rules themselves, proving they are not beholden to China in order to claim the 45X manufacturing credit. The firms who spoke with Canary Media said that, right now, doing so seems manageable, but a lot depends on how the final IRS guidance is written. The Treasury Department has until the end of 2026 to issue rules, according to the budget law.
Despite the uncertainty, some are very confident they’ll make do.
“Our optimism comes from having spent the last six or seven months working through these issues,” said Gold, whose company moved to ensure U.S. control of the factory before Trump took office. “We could give a workshop on how to achieve compliance, by this point. We’re not going to, because we want a competitive advantage, but we could.”
Not everyone is so sanguine. One alarming scenario would be if the administration uses new FEOC rules to launch investigations into clean energy manufacturers or developers. Ossoff deemed that a clear danger.
“It’s the most corrupt administration in American history, and they will wield implementation as a political cudgel,” Ossoff said. “They’ll pick winners and losers based on political considerations.”
As if to underscore that exact point, the White House published an executive order last Monday that targets the very credits that Trump had signed into law three days prior. The order specifically raises the possibility of the Treasury Department “restricting the use of broad safe harbors unless a substantial portion of a subject facility has been built.” Those safe-harbor rules are the same ones providing something of a lifeline to the American solar factories over the next few years. The solar industry is watching this measure intently to see how it affects the already-distorted outlook for the market.
“This is a longstanding, well-established set of practices,” Carr said of the IRS safe-harbor rules. If something happened to upend that established precedent, “basically everybody in the industry would sue pretty much immediately.”
Should manufacturers make it through the near-term turbulence, they’ll still have to figure out what happens to the solar market after the current tax credit-fueled runway peters out around 2030. That future could always involve a policy swing away from the current trajectory.
Over the last decade, solar tax credits have shown a Houdini-esque ability to bounce back from certain death through last-minute legislative maneuverings. But if this latest death proves more enduring, the industry will have to transition to a model that doesn’t revolve around monetizing tax credits. That change will be scary and uncertain for companies, but it would bring the U.S. market closer to the global norm.
“There will be no tax equity — there will be equity and debt, like on all projects in the rest of the planet,” Pochtaruk said. “There’s no tax credits in Chile, in South Africa, in Australia, in Namibia. Pick a country where solar is the most-deployed power generation source; [it’s happening] with no tax credits.”
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