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A longstanding federal tax credit for rooftop solar is about to expire, making it more expensive for homeowners to access cheap, clean energy — and sowing uncertainty for the companies that put photovoltaic panels up on roofs.
But a small Durham, North Carolina, company called EnerWealth Solutions sees a path forward — at least for the next two years. Its model is to buy rooftop solar panels with a tax credit still available to commercial entities and rent them to homeowners, passing along the savings.
It’s an approach that firms around the country can adopt as the beleaguered rooftop solar sector tries to weather the Trump administration’s assault on clean energy.
The leasing strategy could be particularly useful in places like North Carolina, where a robust solar industry has taken root but state policy support for home rooftop panels is waning. In early 2023, funding dried up for a popular rooftop solar rebate program run by Duke Energy, the state’s predominant electric utility. Later that year, Duke began lowering bill credits for customers who send their solar power back to the grid.
A sunny state of 11 million people, North Carolina is a leader on utility-scale solar but middling when it comes to residential solar adoption. Just over 55,000 homes are now equipped with rooftop panels, according to the U.S. Energy Information Administration, so the industry has ample room to grow.
“It’s so imperative that we’re opening every avenue to get these technologies into the hands of as many North Carolinians as possible,” said Matt Abele, executive director of the North Carolina Sustainable Energy Association, an advocacy group.
EnerWealth’s first residential leasing customer is one of the industry’s own. A certified public accountant and financial consultant for solar firms, Casey Gilley said installing an array on his Chapel Hill home is something of an unspoken requirement. “You can’t work in the business and not have solar,” he said. “Right?”
While his profession may not be entirely typical, Gilley is an average Tar Heel in other ways. He’s trying to do his part to reduce pollution and save energy. He wants to guard against coming electricity-rate increases. And forking over a down payment on a full-price solar array for his family of five was a no-go.
Plenty of people EnerWealth aims to serve fit that profile, says Brian Liechti, director of solar leasing. That’s why, until the end of 2027, when companies like his can no longer access the tax credit, the goal is simple: “Make hay and electrons while the sun shines,” he said.
Veterans of the solar industry say they’re used to the ebb and flow of policies designed to encourage homeowners to go solar. But there’s no doubt that they’ve had an especially hard year.
Most crushing was the passage of the One Big Beautiful Bill Act by President Donald Trump and the Republican-controlled Congress in July. The law eliminates the 30% tax credit for home solar at the end of this year, nearly a decade sooner than it was previously set to expire. The change is pushing sales to new heights, but a crash is expected once the incentive is gone in 2026.
The White House also clawed back $7 billion in grants intended to help low-income households go solar, including a $156 million initiative projected to benefit 12,000 families across North Carolina. The state’s Attorney General Jeff Jackson is among 23 attorneys general around the country suing the Trump administration for terminating the program, calling the move illegal.
The policy whiplash comes amid a difficult macroeconomic environment for rooftop solar. High interest rates and inflation have lingered for years, dampening interest in the sector among those without the cash to buy a solar array outright.
Despite these woes, North Carolina installers see a few bright spots.
For one, a Duke trial program called PowerPair, in which customers receive a rebate of up to $9,000 for investing in a battery along with a solar array, has seen thousands of enrollees since its launch in the spring of last year. The pilot has reached its limit in the company’s eastern and far western territory but still has room in the central part of the state.
What’s more, a 2017 state law creates a small crack in Duke’s monopoly. While agreements between homeowners and non-utilities for the purchase of electricity are forbidden as ever, the statute allows individuals to rent the use of solar equipment up to a certain cap. This provision has been little-used to date in the residential sector but is a cornerstone of the EnerWealth model.
Then, there’s a final puzzle piece for the company: the pro-solar policy that escaped the purge in the One Big Beautiful Bill Act. While incentives for individuals dry up Dec. 31, commercial entities can receive at least a 30% credit for investing in renewable energy through the end of 2027.
EnerWealth, then, can keep buying rooftop solar panels for another two-plus years, benefit from the credit, and then pass on some of the savings to its lessees. For now, the company doesn’t have to fear hitting the Duke solar leasing cap established in 2017. And customers who can cash in on the PowerPair battery incentive while it still lasts will see even more savings.
These federal and state incentives can come together to produce savings for North Carolinians, even in a tough time for rooftop solar.
Though Gilley might conceivably have borrowed money and installed his panels in time to use the expiring tax credit, he chose the EnerWealth lease model instead.
“I ran the numbers of ownership versus lease, and they were very similar,” he said. But what ultimately tipped the scales toward the latter was that it didn’t require a down payment or any ongoing costs. “I didn’t have to come up with any cash,” he said. “Also, I don’t have to worry about any maintenance or any problems for the next 25 years.”
PowerPair is still available in Gilley’s area, so he used the $9,000 rebate as a down payment on the battery and the solar system. He receives net-metering bill credits and still pays Duke for electricity — but about $210 less per month than before. Even with his $150 monthly payment to EnerWealth, Gilley is saving about $60 a month.
His rental payment for the equipment will step up 1.5% each year. “But electricity prices are going to escalate at a much higher pace than that,” he predicted. “So, my annual savings will only grow.”
When the residential tax credit expires in two months, homeowners who want to go solar will have an even easier choice to make: Finance their equipment over time at roughly 7% interest rates or rent it for about 25% less per year, thanks to passthrough savings from the tax credits.
“A lease is the only way to monetize the tax credit for residential systems,” EnerWealth’s Liechti said.
According to EnerWealth calculations, the lower lease payments on a $35,000 battery and solar array mean customers will save nearly $15,000 in overall electricity costs over 20 years. Even those who can pay for a system outright might choose a rental option, which spreads the costs out over time and produces monthly bill savings right away.
Meanwhile, in terms of customer experience, there’s little difference between renting and owning the panels and battery. Homeowners have a buyout option beginning in year seven. If they move, they can purchase the equipment and include the expense in the home’s sale price, or transfer the lease — and monthly bill savings — to the new owners.
While EnerWealth is breaking ground in the solar leasing market in North Carolina, other companies are sure to follow, said Scott Alexander, chief strategy officer for the company.
“We’re just one tool in the toolbox,” he said.
The EnerWealth model does have its limits. It’s only available in Duke territory, which covers most but not all of the state. It’s also much more attractive with the PowerPair rebate, which is soon to dry up and faces an uncertain future after that.
Most of all, the leasing economics will get a lot less appealing in two years, when the 30% tax credit runs out for commercial entities, too.
After that, Alexander said, “we have to innovate. We have to pivot. No business lasts forever. We’ve got two years.”
A correction was made on Nov. 6, 2025: An earlier version of this story mischaracterized the advantages of leasing rooftop solar and a battery versus purchasing a system at full price up front. The latter offers consumers more savings over the long term, according to EnerWealth’s calculations, while leasing provides the advantage of immediate net savings.
Zohran Mamdani surged to a historic victory in Tuesday night’s election for New York City mayor, riding a campaign that was laser-focused on halting soaring rents, improving mass transit, and rebuking President Donald Trump’s crackdown on immigration in a metropolis where more than one-third of the population is foreign-born.
The city’s skyrocketing electricity prices, however, received scant mention — even as utility rates animated races around the country, including Democrat Mikie Sherrill’s gubernatorial victory in New Jersey. Despite kicking off his career as a state lawmaker in 2020 by fighting to close the city’s fossil-fueled peaker plants, Mamdani, a 34-year-old democratic socialist, made little hay about climate change at all during the campaign.
Yet the next mayor of the nation’s largest city inherits a world-leading experiment in retrofitting buildings to slash emissions, open questions about how to transition to cleaner power sources, and a patchwork of adaptation efforts meant to protect aging infrastructure from mounting deluges.
The most significant climate policy under the mayor’s purview is a statute called Local Law 97. Passed in 2019, the law requires buildings over 25,000 square feet to slash emissions 40% by the end of this decade and to reach net-zero by 2050. To do so, the nearly 50,000 buildings that qualify must swap oil- and gas-fired heating systems for electric heat pumps.
When the first phase of the law came into effect last year, just 8% of the buildings covered needed to make upgrades to comply, estimated the Urban Green Council, a nonprofit focused on building decarbonization. But more than 50% of buildings will need to make changes to hit the 2030 emissions target.
“That’s a lot,” said John Mandyck, the Urban Green Council’s chief executive. “There’s a lot the next mayor is going to have to do.”
Among the law’s biggest opponents were co-op buildings, condos, and landlord associations that said compliance would cost too much. One anti-Mamdani PAC, as New York Focus reported, sought to make the law a defining issue in the race, saying the candidate from Queens would only raise the price of bringing buildings into line.
In a policy proposal, Mamdani said he would lobby Albany to extend a general tax break that helps middle-income co-op and condo owners pay for building renovations, and to reduce the fees to apply. He also vowed to staff up the agencies in charge of helping building owners navigate the rules. He said in a mid-October debate that he’d heard “from so many” that “it’s cheaper to pay the fine than to actually get into compliance.”
The city could also lower costs by finding a way to purchase heat pumps and other appliances in bulk, Mandyck said. Last year, the New York City Housing Authority agreed to buy 10,000 state-of-the-art induction stoves for apartments in the nation’s largest public housing system, and the state kicked off a new contest shortly after for heat pumps. At the debate, Mamdani said he would look to NYCHA as a model.
But Mandyck said, while the NYCHA programs are “off to a great start,” they’re still only pilot projects.
“That can be part of the solution,” he said. “But there needs to be some new entity, whether an authority or something, that would find a way to do bulk purchasing to aggregate to the market. This is a huge market.”
Yet the buildings covered under Local Law 97 represent just about 5% of the city’s total skyline.
“There’s 950,000 other buildings in New York City,” Mandyck said. “We’re going to have to think about how we help the smaller buildings decarbonize, too.”
To electrify the entire city without spiking emissions, New York will need more clean power plants.
Right now, the city depends on fossil fuels for more than 90% of its power. The mayor has limited say over the electrons that flow into the five boroughs, and the dense urban landscape leaves little space for solar and wind installations within the city. Mamdani’s one major clean-energy plan is aimed at adding solar panels to the roofs of schools, but even that would likely require approval from Albany while only meeting a fraction of local demand.
City Hall does, however, play a role in negotiating contracts for the city’s public institutions with the New York Power Authority, the state-owned utility.
Roughly one-fifth of the power NYPA sells statewide goes to public customers in the city. New York Gov. Kathy Hochul, a Democrat, directed NYPA in June to work on building at least 1 gigawatt of new nuclear reactors in the state in the coming years, and the Mamdani administration could play a part in brokering a deal for those electrons. At the final mayoral debate, Mamdani said he considered a new nuclear plant “something worth exploring,” though he’s remained mum on nascent efforts to reconstruct the Indian Point power station that once provided about a quarter of New York City’s power.
Mamdani will also inherit a climate problem with more immediately tangible stakes than decarbonization: the need to update New York’s aging infrastructure to deal with increasingly extreme weather.
Routine rainstorms regularly overwhelm the city’s stormwater systems and cause deadly torrential flooding. Just last week, two men died in basements in Brooklyn and Manhattan amid heavy rains.
Since the devastation of Superstorm Sandy in 2012, the city has begun a series of adaptation projects totaling billions of dollars — but some less glamorous work has been underway for decades.
Take the New Creek stormwater project on the East Shore of Staten Island as an example. The project, championed by outgoing Mayor Eric Adams, a Democrat, is part of the Bluebelt Program that started on Staten Island in 1996 and transformed the city’s least populous borough into a testing ground for water-management infrastructure. The Department of Environmental Protection now plans to apply those solutions in Brooklyn, Queens, and Manhattan. Five of the 19 project sites are fully complete, and the rest are on track to be finished in the next five years, said Robert Brauman, deputy chief of Bluebelt operations at the agency.
On a sunny Wednesday morning, roughly 12 hours after Mamdani delivered a trumpeting victory speech, Brauman stood atop a concrete structure overlooking the large freshwater stream known as New Creek. Just a few years ago, it was a trickle running through a corrugated culvert under a quiet stretch of the Midland Beach neighborhood that would, in bad weather, turn into a torrent. Today, however, the water travels through a carefully regulated S-shaped pipe system, allowing New Creek to keep stormwater from flooding the surrounding neighborhoods. The city’s Department of Environmental Protection combed over 19th-century botanical records to select plants native not just to the five boroughs but to Staten Island specifically to flank the body of water.
“That prevents flooding downstream, and it gives all the plants we installed time to clean the water, so the native wetland vegetation can suck up nitrogen and phosphorus and everything else and clean the water before it goes out,” said Brauman. “That’s perfect adaptation.”
After walking the perimeter of the project, he arrived at the dead end of Mason Avenue and stopped on the sidewalk. Between the curb and the asphalt of the street was a concrete path that looked like a hard version of the polygreen foam popular on children’s playgrounds. When Brauman poured a sip of coffee from a McDonald’s cup, the liquid spread for a moment, then started to disappear. The specially made porous pavement absorbs fluids, reducing how much liquid flows into storm drains during heavy rainfall.
“This is one of the first ones on Staten Island,” Brauman said. “The city is trying to incorporate it into more projects.”
Mamdani has yet to announce whether he’ll keep Rohit Aggarwala as the Department of Environmental Protection’s commissioner. But Brauman said he’s confident projects like this will continue either way, even if Mamdani had little to say about adaptation on the campaign trail.
Mandyck said the Urban Green Council plans to think through potential policy proposals in the coming months for how to better organize and grow the city’s efforts.
“It’s clear we need to take adaptation more seriously,” he said. “There are a lot of good things going on right now in New York, but they’re a little decentralized.”
In the depths of the 75-year-old Kendall Cogeneration Station along the Charles River in Cambridge, Massachusetts, a clean-heating transformation is underway.
For years, the facility has burned natural gas to produce steam for Boston and Cambridge’s century-old underground heating system. Now, it’s aiming to become a clean “district energy” system, capable of delivering warmth during bitter New England winters without baking the planet — a first for a citywide network in America.
Last year, Vicinity Energy, the owner and operator of the steam heating network, finished installing a 42-megawatt electric-powered boiler at the Kendall facility. Earlier this year, the company confirmed plans for its next step: installing a 35-megawatt industrial heat pump from Everllence, a German energy systems manufacturer formerly known as MAN Energy Solutions.
“That project was greenlit this summertime,” Vicinity Energy CEO Kevin Hagerty told Canary Media, and demolition to make way for the new heat pump has already begun.
“We’re anticipating that being completed midway through 2028. We’ll turn the heat pump on and turn the Charles River into a renewable energy resource,” Hagerty said.
The industrial heat pump will draw from the river water’s latent thermal energy to create boiling-point temperatures within the Kendall facility’s steam-generation complex. The technology will function even in the winter because the low-temperature refrigerant it uses is far colder than even the icy-cold Charles, creating a temperature differential that the heat pump can harness to produce steam.
All that steam flows through about 25 miles of piping to heat roughly 70 million square feet of buildings in Boston and Cambridge, including college campuses and biotech facilities. Vicinity has secured commitments to use the lower-carbon steam from its electric-powered heating systems from area customers such as Emerson College and life sciences real estate company IQHQ.
Hagerty said other “very large offtakers are underwriting this,” although he declined to name them. “The pump is not fully subscribed yet, but it’s getting there.”
The system will be among the biggest in the United States, which has roughly 900 district energy systems ranging from those in airports and on college campuses to the citywide steam network in Manhattan, the country’s oldest. District heating is also popular in European cities, where comparatively high fossil-gas prices are driving a more urgent embrace of large-scale clean-heating systems.
For customers in Cambridge and Boston, Vicinity’s “eSteam” plan makes sense for reasons of political economy, Hagerty said. Massachusetts has set mandates to expand its supply of carbon-free electricity and to reduce its use of fossil fuels in buildings. A preexisting, centralized system like the Kendall facility’s can convert to electric heat pumps and boilers far more cost-effectively than individual buildings could on their own, he said.
“It’s about one-half to one-fifth the cost for buildings to use our eSteam and electrify through the district energy system than it is for them to locally electrify and decarbonize,” Hagerty said.
Most of those savings come from the fact that the Kendall facility’s electric grid substation and steam pipe network are already built, he said. That obviates the need to retrofit individual buildings with electric heating — or for utilities to make distribution grid upgrades to accommodate a heat pump at every building.
District energy systems like Vicinity’s also benefit from economies of scale, Hagerty said. Large, centralized networks can mix and match mutually reinforcing technologies like electric boilers and heat pumps. They can recapture waste heat from other parts of the system and use it to make more steam, as is being done with the Kendall facility’s gas-fired electricity-generation turbine, which provides peak power and “black start” services for the local grid.
District energy systems can also store and shift energy, as Vicinity plans to do with the thermal energy storage that makes up the next stage of its eSteam conversion plan. It’s looking at systems that can convert electricity into heat storage, which would “allow us to relieve the stress on the electric grid and be a lot more flexible,” he said.
If anything, the Boston-Cambridge system is only starting to utilize the cost-effective decarbonization strategies that district energy systems enable, Hagerty said. Europe is leading the way on that front, with showcase projects such as the 70-megawatt industrial heat pumps now using the chilly water of the Baltic Sea as a thermal exchange to heat water to keep buildings warm in the city of Esbjerg, Denmark.
“They currently have the largest industrial-scale heat pump for district energy in the world,” said Alejandro Gorosito, U.S. national sales manager for Everllence, which provided the heat pump for the Danish city. It won’t hold that distinction for long, he said — Everllence is building a 150-megawatt heat pump for a similar project in Cologne, Germany.
In Europe, adoption of industrial heat pumps is helped along by the fact that fossil fuels tend to be more expensive than electricity. Because heat pumps are far more efficient than fossil-fueled options, they can be the most cost-effective choice when electricity is cheaper, Gorosito said — a fact that can push companies without climate goals to pursue the clean-heat technology.
In much of the United States, where fossil fuels are abundant and power prices are rising fast, the math doesn’t favor heat pumps, Hagerty conceded. But for Boston and other cities that require building owners to reduce their carbon emissions, and for states like Massachusetts that aim to decarbonize their economies, district energy systems can serve as a “regulatory hedge for our customers,” he said.
“They need to make decisions as to whether or not they’re going to heat their building with natural gas, because we’ve got regulations in place that are going to start enacting fines … Do they want to take the risk of spending millions of dollars on something that they may not be able to use in five to 10 years?”
As of Sept. 30, Ohio lawmakers eliminated a key legal tool used to rein in air pollution from power plants and industrial sites. Now, advocates are suing to restore that right.
For decades, environmental groups in Ohio and elsewhere have used air nuisance rules in state plans as a catchall way to enforce the federal Clean Air Act. Ohio’s version let people take legal action against companies whose emissions “endanger the health, safety or welfare of the public, or cause unreasonable injury or damage to property.” The rule dates back more than 50 years.
Environmental groups have used air nuisance rules to file or threaten lawsuits against coal-burning power plants, iron and steel facilities, coke plants, and other industrial operations, which emit not only planet-warming greenhouse gases but also harmful pollutants like nitrogen dioxide, sulfur dioxide, and lead.
Defendants in cases brought under Ohio’s version of the rule have included Suncoke Energy, AK Steel–Middletown Works, Georgia-Pacific Corp., and Phthalchem. Consent decrees and settlements have produced orders or agreements to stop alleged nuisances, clean up waste, and expand monitoring.
But a last-minute addition to the state’s 3,156-page budget bill, House Bill 96, told the Ohio Environmental Protection Agency (EPA) to cut that protection out of the state’s Clean Air Act plan.
“The air nuisance rule is the tool that Ohioans have to hold polluters accountable,” said Neil Waggoner, the Sierra Club’s Beyond Coal campaign manager for the Midwest. “This is the state government saying … we’re going to take this away from you in the most secretive fashion possible.”
The Sierra Club is a plaintiff in the lawsuit, along with the Ohio Environmental Council, SOBE Concerned Citizens, and the Freshwater Accountability Project. The fifth plaintiff, Donna Ballinger, is a Middletown resident who lives close to iron and steel operations, which she claims cause nuisance conditions. An August report by the Environmental Integrity Project documented likely air quality problems in that area.
Experts warn that eliminating the right to file air nuisance complaints weakens Ohio’s enforcement of pollution measures at an already perilous moment for environmental regulation.
For months, the Trump administration has been rolling back federal pollution standards and making huge personnel cuts to the staff charged with enforcing the remaining rules and permits. The Ohio EPA has authority to enforce the Clean Air Act but doesn’t always pursue alleged violations.
“Both at the federal and state level, we’re seeing less enforcement,” said Miranda Leppla, who heads Case Western Reserve University’s Environmental Law Clinic and represents the Ohio Environmental Council and the Sierra Club in the lawsuit. “If Ohioans don’t have the ability to bring these enforcement actions on their own through the air nuisance rule, there’s a very serious concern that air quality will continue to degrade and Ohioans’ health will get worse.”
Echoing a recent law in Louisiana, HB 96 also blocks the Ohio EPA from acting on data that groups may collect through community air-monitoring efforts. Such data can fill important gaps and alert communities and enforcement officials to problems that may not be detected by EPA monitors miles away.
Ohio’s limits on using the data will particularly harm fence-line communities, Leppla said.
“At a time when Ohio is seeing renewed industrial building, including new facilities like data centers, as well as a greater federal push for more fossil fuels, it is more important than ever that Ohioans preserve their right to both collect air pollution data themselves and use that data to file suits against harmful air nuisances,” said Chris Tavenor, general counsel for the Ohio Environmental Council.
The complaint, filed on Oct. 24 in the Franklin County Court of Common Pleas, asserts that lawmakers violated the single-subject rule in the Ohio Constitution when they tacked the air pollution provisions onto the massive budget bill.
“This is fundamentally unrelated to the main purpose of the biennial budget,” Waggoner said. “And it was stuck in here in an intentional way so that folks would not have an opportunity to see it, talk about it, or debate its merits.”
The Sierra Club, Ohio Environmental Council, and other groups raised a similar argument two years ago after eleventh-hour changes to a bill about poultry included a new definition of natural gas as “green energy.” That case, also at the Franklin County Court of Common Pleas, has been briefed, and parties are waiting for Judge Kimberly Cocroft to issue her ruling.
A 2019 decision in Paulding County, Ohio, rejected a challenge to the late amendment in the 2014 budget bill that tripled property-line setbacks for turbines on wind farms. That case wasn’t appealed and would not bind the court in Franklin County.
Despite the similarities, the new lawsuit is different because the ban goes beyond how state agencies operate, Leppla said. “The air nuisance rule was created specifically to allow Ohioans who are suffering from noxious air pollution and nuisances to protect themselves when the government does not act.”
HB 96 is not the first attempt to take away Ohioans’ right to bring air nuisance claims. In 2020, the first Trump administration’s U.S. Environmental Protection Agency removed Ohio’s air nuisance rule, Waggoner noted.
The Ohio Environmental Council, the Sierra Club, Ballinger, and another Sierra Club member mounted a successful challenge in federal court, but due to delays in agency action it wasn’t until this February that the rule became effective again.
“And now here we are with the Ohio legislature attempting to remove it again, when it had already been found to be illegal to do so,” Leppla said.
To prevent another lapse, the plaintiffs in the new lawsuit have asked Judge Julie Lynch to grant a preliminary injunction against removing the rule while the case proceeds.
As defendants, the State of Ohio and the director of Ohio EPA have 28 days to file responses after the complaint was served. What happens next will depend on those filings and the judge’s rulings on any motions.
The Ohio attorney general’s office did not respond to Canary Media’s request for comment. Ohio EPA spokesperson Bryant Somerville said the agency is reviewing the lawsuit but had no further response because the matter is in litigation.
U.S. Rep. Mikie Sherrill won the governor’s race in New Jersey on Tuesday running on a platform of keeping electricity prices down. Environmental groups see Sherrill’s election as a triumph for the Garden State’s struggling offshore wind sector.
Sherrill, a four-term Democrat and a U.S. Navy veteran, arrived on the political scene in 2017 and advocated for offshore wind projects on Capitol Hill. As a gubernatorial candidate, she was one of only three Democrats who explicitly endorsed offshore wind on campaign websites early in the race.
Her Republican opponent, Jack Ciattarelli, ran on a promise to ban future offshore wind development. His campaign website sells “stop offshore wind” tote bags, t-shirts, stickers, and beverage koozies. Sherrill handily beat Ciattarelli, winning 56% to 43% at press time.
“In-state produced power through offshore wind and other renewable technologies is the only path forward to ensure carbon reduction while prioritizing price stability, economic growth, and resource adequacy,” said Paulina O’Connor, executive director of the New Jersey Offshore Wind Alliance, an advocacy group whose work is funded in part by wind developers.
Sherrill will take office next year without any offshore wind projects operational or under construction along the state’s roughly 130 miles of coastline. That’s in stark contrast to the other East Coast states that, like New Jersey, have incentivized offshore wind development through tax breaks and have planned grid and clean-energy goals around the sector’s growth. Massachusetts, Virginia, New York, and Rhode Island all have installations completed or currently underway.
New Jersey’s incumbent Phil Murphy, also a Democrat, was once a fierce proponent of offshore wind but has ostensibly distanced himself from the sector in recent months as President Donald Trump’s war on offshore wind proved, in some ways, insurmountable for a lame-duck governor.
The Trump administration has frozen the permitting pipeline for all of New Jersey’s earlier-stage offshore projects. Atlantic Shores, the state’s only fully approved wind farm, had one of its federal permits revoked in March by the Environmental Protection Agency. Shell, the project’s codeveloper, officially withdrew from the project last week.
As governor, Sherrill’s ability to counter federal anti-wind policies will be limited. But she can make sure the state remains a player in the industry, which is still advancing in nearby New York. In that state, one project, South Fork Wind, is fully operational, and another, Empire Wind, is under construction.
Sherrill, for example, could expand funding for programs that train workers for wind jobs. She could increase legal pressure against the Trump administration for obstructing certain projects, as Rhode Island and Connecticut have done. New Jersey’s Attorney General Matthew Platkin, along with 17 other attorneys general, is already suing the Trump administration over its broad-reaching executive order that froze federal permitting for wind power.
Her campaign promise to freeze New Jerseyans’ utility rates through a State of Emergency declaration on Day 1 and to push back on federal overreach signifies a willingness to come out fighting.
“Governor-elect Sherrill campaigned on the need for bold action to reduce family energy costs. [The American Clean Power Association] welcomes the Governor-elect’s recognition that clean power is key to meeting demand and keeping costs low,” said Jason Grumet, CEO of the trade group, in a statement released shortly after Sherrill’s acceptance speech on Tuesday night.
In January, Sherrill will take the reins from Murphy, who set New Jersey on a path to building a 100% zero-emissions power grid by 2035 but ultimately failed to generate any new offshore wind power. New Jersey voted on Tuesday for a candidate who aims to keep the state’s climate ambitions alive. The long-held vision of offshore wind turbines being central to these goals endures — for now.
For decades, Puerto Ricans have struggled with a dysfunctional energy system. Now residents are grappling with two very different plans for how to fix it.
President Joe Biden’s administration invested heavily in distributed generation: rooftop solar and battery arrays on homes and businesses across Puerto Rico. But President Donald Trump has rolled back those commitments, redirecting funds toward hardening the grid and shoring up centralized — mostly fossil-fueled — power production.
Energy experts and community leaders say that continued reliance on fossil-fuel power plants is harmful and that sending electricity on transmission lines across rugged mountains plagued by hurricanes is impractical. Distributed generation, they argue, is the best way to supply Puerto Ricans with reliable, affordable power that can withstand natural disasters.
A federal judge’s Oct. 2 ruling on hurricane recovery funds offers a measure of hope to those advocating for this latter vision in the archipelago, which includes the main island and two smaller inhabited islands: Vieques and Culebra.
In September 2017, Hurricanes Irma and Maria battered Puerto Rico in quick succession, devastating homes and infrastructure and causing the lengthiest blackout in U.S. history, leaving some households without power for over a year. The Federal Emergency Management Agency is tasked with rebuilding the island’s energy infrastructure, which still has frequent outages. In 2020, the first Trump administration awarded $9.6 billion for this purpose, and other federal grants bring the pot of FEMA recovery funds for the energy system to over $12 billion.
In its 2020 grid-rebuilding study, FEMA proposed to fix and harden the existing grid and repair fossil-fuel plants. The agency made only cursory mention of distributed solar as supplemental power at critical facilities.
Community groups argued in official comments that instead of rebuilding a grid that has proved vulnerable to disaster, the agency should use federal funds for distributed solar paired with batteries. That would give homes, businesses, hospitals, and schools dependable power even when the grid goes down. FEMA did not incorporate that feedback into its final proposal in 2021, so in April 2023 the community groups, plus the national conservation organization Center for Biological Diversity, filed a lawsuit alleging that FEMA had violated the law by failing to study the environmental impacts of its plan or to consider other alternatives.
Federal Judge Jay A. García-Gregory ruled in the plaintiffs’ favor this October, sending FEMA back to the drawing board to fully study the impacts of various grid-overhaul alternatives, including one based on distributed solar.
“This is a pretty good outcome, an order from a federal district judge requiring FEMA to consider distributed renewable energy for all of this historic amount of funding,” said Ruth Santiago, an environmental attorney who grew up and lives in Salinas, a coastal fishing town located near an oil-fired and a coal-burning power plant.
Under the National Environmental Policy Act (NEPA), before undertaking any project that could significantly affect the “human environment,” a federal agency must release an environmental impact statement after studying the direct and indirect effects the project would have, as well as its cumulative effects with other existing or planned developments. The agency also must take a “hard look” at alternative ways to achieve the same goals.
FEMA argued that its grid-rebuilding plans would not have a significant impact, therefore an in-depth study wasn’t required.
But in their lawsuit, the community groups argued that the impact of FEMA’s rebuilding plans would indeed be massive, and that the agency failed “to engage in meaningful analysis of the environmental effects” of its rebuilding plans.
The judge agreed and ordered FEMA to study the impacts of its plans as well as the alternatives the community groups had proposed: rooftop solar, microgrids that can be disconnected from the main grid in case of a larger outage, and incentives for energy efficiency and power use at times of lower demand.
It’s a measured victory though: FEMA can appeal the decision, take months or years to do the study, and even ignore its own environmental impact statement, as the agency isn’t required to take any action based on its findings.
“If they do an environmental impact statement, it doesn’t mean they will adopt distributed renewable energy options,” said Alfredo Vivioni, a member of the board of directors of the community organization Frente Unido Pro-Defensa del Valle de Lajas (United Front for the Defense of the Lajas Valley), one of the plaintiffs in the lawsuit. “But at least it requires them to make a deeper evaluation of the variables.”
Meanwhile, Trump has threatened to eliminate FEMA altogether, and he has long been skeptical of efforts to mitigate and prepare for climate change.
“When you have a president that says climate change is a hoax, this is going to be interesting,” Vivioni said. “It could also be sad. But you learn to fight and keep on going. You build stamina for this.”
Rebuilding Puerto Rico’s electricity system is a challenge with very high stakes.
More than 4,000 Puerto Ricans died as a result of Hurricane Maria. Lack of electricity was a contributing factor, since residents could not refrigerate medicine or run medical equipment, and ailing people sweltered in high heat and humidity without air conditioning. The Centro de Periodismo Investigativo (Center for Investigative Journalism) in Puerto Rico told the stories of 166 people who died specifically from a lack of electricity.
Advocates for distributed power warn that more fatalities are likely if residents aren’t equipped with solar and batteries to survive future natural disasters. Meanwhile, residents — particularly those on the south coast of the main island — suffer health effects from fossil-fuel generation, and the continued reliance on fossil fuels will contribute to the very climate change–related events that damage the grid and endanger electricity supply, as the community groups pointed out in their lawsuit.
Perpetuating the existing energy system would be an environmental injustice, they argue, since the coal and oil plants on the south coast are located amid some of the island’s poorest communities.
They point to studies showing it is possible to power Puerto Rico with distributed solar while phasing out centralized fossil-fuel plants.
The groups’ lawsuit cites a 2020 National Renewable Energy Laboratory report that found distributed solar could generate more power than the archipelago needs. And it notes that a 2021 Cambio PR and Institute for Energy Economics and Financial Analysis (IEEFA) study found that by 2035, operating a system relying on 75% distributed generation — including rooftop solar, batteries, and microgrids — would be less expensive than operating the current grid, measured in the price of energy per kilowatt-hour.
Rooftop solar paired with batteries, sometimes networked among houses and businesses into microgrids and virtual power plants, has already been invaluable for many Puerto Ricans. Grassroots organizations, tapping federal and philanthropic funds, have installed rooftop solar in communities across the island, as Canary Media chronicled in a 2022 special reporting project.
Biden Energy Secretary Jennifer Granholm touted distributed solar during multiple visits to Puerto Rico, and Biden EPA Administrator Michael Regan talked with residents about the burden of coal power. In December 2022, Biden signed a funding omnibus bill including $1 billion for rooftop solar for low-income households and households with disabilities in Puerto Rico.
As of June 2025, 1.2 gigawatts of grid-connected rooftop solar were installed on homes and businesses, according to the IEEFA, supplying more than 10% of the total energy used.
But the need for more distributed solar is still great. The IEEFA determined that at least 350,000 low- and moderate-income households are unlikely to install rooftop solar without financial assistance, based on 2021 data from the National Renewable Energy Laboratory, leaving them vulnerable during storms.
The Trump administration has gutted such assistance. Federal funding for solar in low-income areas nationwide was canceled, over $156 million of which was promised to Puerto Rico. On Oct. 1, the Department of Energy announced $365 million in Biden administration funds for rooftop solar and battery storage will be redirected to “strengthen grid stability and harden critical infrastructure.”
From his hillside porch on Puerto Rico’s south coast, retired sports medicine professor Miguel Rivera can see a coal-fired power plant, an oil-fired power plant, and an increasingly vast expanse of solar panels stretching across the otherwise lush, green landscape. He is among the residents and experts who say distributed generation is the only real solution for Puerto Rico.
As of spring 2024, 235 megawatts of utility-scale solar were deployed in Puerto Rico, and over 800 megawatts’ worth of such contracts were approved and executed by the federal fiscal control board, which oversees Puerto Rico’s financial affairs.
AES Puerto Rico, the company that owns the coal plant, has installed solar farms on the south coast near Rivera’s home, with the 200-megawatt solar project Marahú scheduled to go online this year. While the installations provide clean energy, they pose the same problem as fossil-fuel plants: The electricity they generate needs to be transported on vulnerable long-distance transmission lines. Meanwhile, the solar panels are being built on swaths of flat, fertile land ideal for farming, which is increasingly scarce on the island.
Though FEMA’s previous energy study did not delve into utility-scale solar, beyond backup power at critical facilities, Santiago said its pros and cons must be considered in the new study.
“What the utility-scale projects, whether renewable or fossil, have in common is that they’re very centralized, and they’re concentrated in one place and then depend a lot on high-voltage transmission lines and towers and substations,” said Santiago. “Distributed renewables on rooftops, parking lots, as close as possible to the point of use — avoid what happened with the existing system after Hurricane Maria. It’s so clear that this is a reasonable opportunity that needs to be considered. Otherwise, we will have more loss of life in the next storm.”
On an October Sunday afternoon a few weeks after the judge’s ruling, Rivera drove through the mountains with his wife, Maridalys Nieves, and friends including José Cora, leader of Acción Social y Protección Ambiental (Social Action and Environmental Protection), a grassroots local environmental justice organization.
They pointed out the broken power lines swinging from poles and lines drooping under curtains of green vines. The well-being and safety of residents in small mountain villages is threatened by the deteriorating power lines. Rooftop solar panels paired with batteries could make these locals largely energy self-sufficient.
But given the median household income of under $25,000 a year in the mountainous regions — Jayuya, Orocovis, and Utuado — that the friends drove through that day, it is nearly impossible for many residents to pay for solar. Cora, an IT professional who maintains computer servers, noted that despite his commitment to clean energy, his family can’t afford to install solar and batteries on their own home.
As the car descended down a mountain, Nieves received a social media alert on her phone that many would not have power because of a problem at the coal plant.
Rooftop solar and batteries are the only way to free residents from such frequent occurrences, the friends agreed. They hope FEMA follows the judge’s orders and does a thorough study, and then funds scores of distributed solar arrays as a result.
A first-of-a-kind project underway outside Portland, Oregon, could provide a model for data centers to connect to the grid without driving up utility bills and carbon emissions.
Silicon Valley startup Gridcare launched in May with a promise that its artificial intelligence–powered software can help actualize one of the hottest concepts in the electricity sector: data center flexibility. Last month, it announced the successful use of its software by utility Portland General Electric (PGE) to bring 80 megawatts of data center load online next year in Hillsboro, Oregon.
That’s not a ton of new computing load, considering the gigawatts’ of prospective data center expansions being planned across the country. But as a real-world example of a utility planning around a data center’s commitment to reduce power use during moments of high demand, the project may well be a breakthrough.
“We’ve moved from the theoretical to the practical,” said Larry Bekkedahl, Portland General Electric’s senior vice president of strategy and advanced energy delivery. “This is our first project where that flexibility really comes into play.”
Around the country, utilities are planning massive investments in fossil-fired power plants and grid capacity because of the boom in power demand from data centers. Those spending plans threaten to impose enormous costs on utility customers already struggling to keep up with rising electricity rates.
Data center flexibility agreements could be an elegant solution. If the facilities can ease off their massive power use during the handful of hours per year that they would otherwise overload the grid, they should be able to get connected to the grid sooner — and utilities could defer costly infrastructure upgrades that in some cases include more fossil-fuel power plants.
Other data centers are testing the use of batteries or flexible computing or a combination of both to reduce the burden placed on the grid. But public announcements of flexibility agreements between utilities and data center developers are few and far between — and the technologies that could allow them to become more common are still emerging.
Amit Narayan, Gridcare’s CEO and co-founder, believes PGE’s use of his company’s software may be the “first project of its kind where a utility has been able to accelerate data center expansion at this scale.”
Narayan said the startup also has projects underway with unnamed tech giants and data center developers, as well as with utilities including California’s Pacific Gas & Electric.
“We have these new tools of real-time visibility and dispatchability and control of distributed energy technologies,” Narayan said. “Why do we have to live with the old assumptions of designing around worst-case scenarios?”
In order to understand how PGE and Gridcare’s approach differs from that of other data center flexibility projects around the country, it’s important to grasp the complexity of the problem PGE is trying to solve for its Hillsboro data center cluster.
Hillsboro, a major hub for chipmaker Intel and a terminus for multiple fiber-optic cables connected to Asia, is experiencing “huge demand for data centers in the 50-megawatt to 500-megawatt range,” PGE’s Bekkedahl said. Those data centers are powered by the utility’s transmission grid, which is structured as a network that shares power across multiple interconnected nodes. And existing electricity demand is already pushing that grid close to its operating limits in the Hillsboro area.
Data centers seeking more power from that constrained grid have put PGE in a bind, he said. Under traditional utility planning, the network would have to be scaled up to provide enough power to serve every customer during times of peak demand.
“But there are only a few peak hours, during maybe five to 10 days a year, that we need to meet those peaks,” he said. Building enough transmission to serve them all would take years, cost hundreds of millions of dollars, and yield a grid that’s far bigger than what’s needed most of the time.
Flexibility projects aim to prevent the need to overbuild by reducing the demand peaks that new data centers cause. But PGE can’t make plans based on what a single data center might do. It has to consider the growth plans of all the customers connected to that part of the grid, during every hour of the year, for years into the future — and then also consider the impact on PGE’s regional transmission network and generation fleet.
Human grid planners simply can’t parse through all those variables at once, Bekkedahl said, even with the help of standard planning software.
“That’s where Gridcare came in and helped us model,” he said. Through Gridcare’s software, PGE identified a combination of flexibility opportunities that could allow data centers to add 80 megawatts of additional power use next year, instead of waiting years for traditional grid upgrades, he said.
Narayan is familiar with complex computing challenges. He founded, built, and sold a semiconductor design company called Berkeley Design Automation in the 2000s. Next, he launched Autogrid, a “virtual power plant” software provider that was sold to Schneider Electric, the French energy equipment and services giant, in 2022 and is now part of utility software company Uplight.
Gridcare applies similar computing techniques to model the interactions of lots of power-hungry customers across a dynamic, networked grid, he said.
“You have a major combinatorial-explosion issue here,” Narayan said. “Instead of analyzing one case and one dispatch scenario, which planning teams do — and which is itself very complicated — you have to analyze 200,000-plus scenarios and contingencies.”
Under traditional grid-modeling methods, “that’s typically done in a sequential way, one project and one scenario at a time,” he said. But that’s a highly impractical approach to finding solutions quickly enough to inform utility decision-making.
As Narayan noted, “We have to look at many different projects, each with its impact on ramp and load, over the next five to 10 years. We have to look at very many different scenarios of flexibility. And we have to do it for every hour of the year.”
Recent developments in AI and computing power have made this complex problem solvable: “We’re able to take all the sources of flexibility that may exist, and then examine all the combinations and permutations that exist, and find the lowest-cost way to manage those constraints.”
Not all utilities are ready to rely on flexibility as an alternative to hard grid upgrades. But PGE has been working for years on modernizing its grid operations to support distributed energy and flexibility and bring in real-time data from AI-enabled smart meters, which has given its grid operators confidence in understanding and managing customer-sited energy resources, Bekkedahl said.
With that expertise to back up Gridcare’s revelation of the options at hand, PGE has been able to approach data centers in the Hillsboro area to propose mutually beneficial commitments, he said.
“Those data centers that are willing to work with us, if they’re willing to be flexible, we’ll put them at the top of the queue” for additional power, Bekkedahl said. “For someone who says, ‘Nope, we’re going to want 100 percent,’ well then, we say, ‘You’ll wait for us to build the transmission.’”
At least one data center has already pulled the trigger on a project identified by the collaboration between Gridcare and PGE. Last month, Aligned Data Centers announced plans to work with energy-storage specialist Calibrant Energy to deploy a 31-megawatt/62-megawatt-hour battery across the street from its Hillsboro data center. It’s the first publicly revealed project that’s part of the scope of work enabling the 80 megawatts of additional capacity that PGE will be able to energize next year.
Once it’s turned on sometime next year, that battery will allow Aligned to expand its computing capacity at the data center years faster than it would have been able to by waiting for PGE to upgrade its grid to supply its peak power demand. Aligned didn’t disclose how many megawatts of increased power demand its expansion will cause, a sign of the highly competitive nature of today’s data center market.
Accelerating that “speed to power” has become an overweening obsession of data center operators seeking to meet tech giants’ AI ambitions, and flexibility is increasingly pointed to as the way forward.
A February report from a Duke University team led by researcher Tyler Norris found that the U.S. has nearly 100 gigawatts of existing capacity for data centers that can curtail less than half of their total power use during peak demand events, which occur about 100 hours of the year. Last month, Energy Secretary Chris Wright ordered the Federal Energy Regulatory Commission to fast-track a rulemaking process to prioritize such flexible interconnections on U.S. transmission grids.
But data centers can’t afford to invest in batteries like this without clear commitments from utilities that those investments will in fact resolve the grid constraints preventing them from getting online faster.
“This is where PGE was a fantastic partner with us,” said Michael Welch, Aligned’s CTO. “They were able to model these scenarios and understand them with a high degree of accuracy, and provide the greatest impact without wasting capacity. As that came into clarity for us, we were able to work within those constraints.”
Bekkedahl emphasized that PGE is taking its time in its work with Gridcare. While the utility hopes to interconnect 400 megawatts of expanded data center load in Hillsboro by 2029, “we’re not putting on 400 megawatts tomorrow,” he said. “There’s a stepping-stone process here. We want to see it in action before we believe it.”
Nor can PGE completely avoid building more transmission and generation to meet its fast-growing demand for power. “We’re going to have to build out. This is just a bridging strategy,” he said.
But any approach that can increase the amount of electricity that PGE sells without adding exorbitant grid costs should help reduce the impact on customers at large, Bekkedahl said. “Bringing down the peak, and bringing up the overall utilization of the system, makes it more affordable for all customers.”
President Donald Trump’s megalaw will soon slam the door on tax credits for homeowners who want to install heat pumps or make other energy-efficiency improvements.
But there’s still one way to tap federal assistance for cleaner heating.
The same law allows installers of geothermal heat pumps and systems that store thermal energy for later use to earn tax credits for years to come. Though individuals can’t tap the incentives directly, companies that retain ownership of the systems can lease them to customers at a cost that reflects the federal discount of 30% to 50%.
Already, some companies are adapting to the new state of play. Installers that didn’t previously have a leasing business are pivoting to take advantage of the incentives. For firms that already deploy thermal energy storage systems in multifamily buildings via commercial partners, the transition is especially straightforward.
It’s a rare and under-the-radar bright spot for home electrification in the One Big Beautiful Bill Act (OBBBA). The law is otherwise expected to slow down the shift from fossil-fueled buildings to heat pumps, which improve air quality and can save consumers money on top of reducing carbon emissions. But the pathway available to companies that lease geothermal and other clean-heat systems could help soften the blow.
Take Dandelion Energy, a startup specializing in home geothermal heat pumps that pull warmth from the ground rather than the air. Already, the firm has launched a leasing structure to take advantage of the changes.
If anything, the new law has made Dandelion’s approach to earning tax credits simpler, said CEO Dan Yates. That’s because the Google X spinout has in the past few years “focused on working with large-scale new homebuilders, where we do hundreds, even thousands of homes in new projects,” like its sizable partnership with homebuilder Lennar in Colorado.
Homebuilders didn’t have a clear way to capture the value of geothermal heat pumps under the Section 25D tax-credit program that’s going away at the end of this year, Yates explained. That tax credit was for households, not for companies that build homes with the eligible technology.
But under Dandelion’s new leasing structure, homebuilders can capture the baseline 30% tax credit, plus a 10% adder under domestic-content provisions that Dandelion’s U.S.-built systems qualify for. That enables them to save “thousands of dollars” up front, Yates said. “In many states, we’re seeing this lease as a real tipping point, where geothermal becomes less expensive than the status quo for the builders.”
The changes in the OBBBA also solved a key problem for third-party ownership of geothermal heat pumps, he said. Under previous tax-code language, those systems were considered “limited-use property,” meaning that the commercial owner couldn’t repossess them if the leaseholder failed to make payments, which complicated leasing structures.
But the Geothermal Exchange Organization, a geothermal-heat-pump trade group, successfully lobbied to change that language with the OBBBA. Now, leased geothermal systems can enjoy the same tax credits that have helped boost larger projects such as geothermal district-heating networks, which supply ground-source heat to buildings, campuses, or entire neighborhoods.
Dandelion’s leasing partner is Upstream Lease, a division of Carbon Solutions Group, which has previously specialized in monetizing tax credits for distributed energy systems like rooftop solar. Third-party lease and power purchase agreements make up roughly half of the U.S. residential rooftop-solar market to date, and remain available, at least in a truncated form, under the OBBBA.
Keith Martin, an attorney with law firm Norton Rose Fulbright and an expert on clean-energy tax equity, said his firm is working on geothermal-heat-pump leasing and tax-credit monetization strategies similar to those undertaken by Dandelion and Upstream, though he declined to name the companies involved.
“They’re looking at retaining ownership, just like the solar rooftop companies do, and then packaging large groups of heat pumps and arranging tax equity as a way of monetizing the tax benefits,” he said.
Companies can continue to claim geothermal-heat-pump tax credits for projects that start as late as 2034, Martin said.
As for the cost to homeowners, Yates said the typical payments add up to $150 to $200 per year, a “tiny” amount compared to typical rooftop-solar lease payments that can be as much every month. And the superefficient nature of ground-source geothermal can cut a home’s energy bills by $500 to $900 per year, or two to four times as much as they’re paying for a system that can last decades.
“That’s what we love about this — it really does align everybody’s interests,” he said.
The other class of household heating and cooling equipment that received a reprieve from Republicans in the OBBBA is thermal energy storage systems. The term typically describes large-scale systems that use energy to generate heat or cold, which is stored for later use — a class of technologies that range from industrial-scale heat batteries to massive chilled-liquid networks connected to multiple buildings.
But homes and apartments can also benefit from smaller-scale versions of these systems, which are eligible for full tax credits until 2033 and then for gradually reduced tax credits through 2035 under the OBBBA.
For Jane Melia, co-founder and chief revenue officer of Harvest Thermal, that opens up opportunities.
Her company makes the Harvest Pod, a device that uses a heat pump to warm both water and air, and also stores that heated water for later use. That allows households to use electricity when it’s cheap and plentiful to heat water, which can be tapped later when power prices are higher. Under the OBBBA, devices that can store enough energy to heat and cool a building for at least one hour qualify for tax credits.
Of course, those tax credits are also only available to companies, not consumers, under Section 48E of the tax code, she said. But lease structures for household heating, ventilation, and air-conditioning systems are relatively common, she said. “If they’re willing to lease the HVAC equipment, then the leaseholder captures the tax credit, and it flows through to making the lease payment lower than it would otherwise be.”
For single-family homes, “that’s something we’re actively working on to get it in place in 2026,” she said. “It’s not done yet. But I think that’s where the industry is going.”
Multifamily buildings are even better suited to capture tax credits for third-party-owned thermal storage systems, since the owners of properties are stand-ins for commercial leaseholders. In fact, Harvest Thermal has already seen some of its devices capture the 48E tax credit in a multifamily project in Truckee, California, a mountain town where efficient electric heating with storage can make a significant dent in energy costs.
“This project would not have happened without the tax credits,” said David Chanin, cofounder of FutureFit Partners, the company that managed the installation of eight Harvest Pods in a 72-unit low-income housing site in Truckee. The owner of the building was able to reimburse 40% of the project cost through tax credits, including the 30% base credit and a 10% adder available for projects in “energy communities” that have historically relied on fossil-fuel extraction and production.
The challenge with these large-scale projects is that companies might not have enough tax liability to capture the full value of the tax credits for the various projects they’re doing. Some firms are dealing with this constraint via a financial tactic called transferability, which lets them sell those tax credits to a bigger entity for cash.
In the case of the Truckee project, for example, the building owner sold its credits to a financial partner that wanted to offset its tax bills, Chanin noted.
Not all property owners are prepared to handle the legal and accounting tasks of turning tax credits into project finance, however. Those that fall into this bucket can turn to the commercial entities that aim to facilitate this process.
Take Kelvin, a New York City-based startup that has partnered with ClearGen, an energy-infrastructure investor owned by real-estate giant CBRE Investment Management, to structure some of its first tax-credit transactions.
The startup makes a device called the Cozy that fits over radiators that heat a lot of older buildings, captures the warmth they generate, and lets it out into rooms over time using software controls.
“We’re putting insulated radiator covers over 300 pounds of cast iron. When you heat that up, it’s actually an extraordinarily large thermal battery,” said Kelvin CEO Marshall Cox. That makes the Cozy eligible for tax credits under the OBBBA — as long as it’s owned by a third party.
Kelvin already offers its Cozy to building owners “on a subscription basis, just like solar finance,” Cox said. But ClearGen is helping it expand the scale of these kinds of agreements. “They have very large buyers” of tax credits “that they work with,” he said.
The startup has also monetized credits for a New York City project with the help of Giraffe, one of a growing number of companies that help owners of tax-credit-eligible projects find buyers for the incentives.
Identifying ways to turn the theoretical value of tax credits into real-world project financing isn’t simple, Melia said. But it’s important to expand the market for these technologies to households and buildings that would otherwise struggle to afford them.
“This is, first of all, a way for multifamily properties — low-income and high-income — to benefit,” she said. “But it’s also a way for the business model to evolve.”
A correction was made on Nov. 3, 2025: This story originally misstated Jane Melia’s title at Harvest Thermal. Melia stepped down as CEO to take on the role of chief revenue officer in April 2025.
Batteries have quickly become a crucial part of the U.S. electricity grid — and a whole lot more are about to come online.
Over the next five years, the country will build nearly 67 gigawatts’ worth of new utility-scale batteries, per data from research firm BloombergNEF, enough to send almost 284 gigawatt-hours of stored-up electricity back to the grid.
Those are massive figures. Should the forecast bear out, the U.S. will have roughly three times more battery capacity in 2030 than it does now. Such rapid growth is familiar territory for the sector, which jumped from just 1.5 GW of total capacity in 2020 to a whopping 27.3 GW by the end of last year.
The transition to renewable energy — particularly solar — relies on batteries. That’s because communities with lots of solar arrays often generate more power than the grid needs at a particular moment in time. Batteries let these solar-saturated states save that extra energy for later use.
California and Texas, the U.S.’s two leaders on solar, have built the vast majority of the country’s utility-scale storage. Already, the states are reaping the benefits. By spring of 2024, California’s battery fleet had grown large enough to begin displacing some natural-gas use in the evening. Meanwhile, batteries have helped Texas stave off summertime grid emergencies for two years running.
As battery developers propose more, bigger projects, the sector has started to run into some opposition. Just last week, news broke that plans to build New York’s biggest battery on Staten Island fell through following fervent protest from the local community. Fears of battery fires have spread around the country following the massive blaze at California’s Moss Landing facility in January, even though that disaster stemmed from the project’s outdated design.
Still, several broader trends suggest the sector’s growth will continue.
For one, President Donald Trump’s One Big Beautiful Bill Act left incentives for battery storage relatively untouched, even as it yanked away tax credits for solar and wind projects. Then there’s the fact that solar is growing steadily around the country, which will eventually create a need for storage in other states just as it has in California and Texas. Most important of all, demand for electricity is surging nationwide — and batteries are among the cheapest and quickest ways to get more capacity onto the grid.
It’s a known problem that onshore wind turbines kill bats. But it’s unclear whether the same issue applies to offshore wind installations — and the Trump administration just canceled groundbreaking research into the question.
Earlier this month, the nonprofit Electric Power Research Institute (EPRI) received a letter from the Department of Energy abruptly canceling its $1.6 million grant to study bat behavior in California waters earmarked for offshore wind development — a move that will hinder the nascent research effort. Christian Newman, EPRI’s program manager for the grant, said the organization is actively looking for other funding sources.
The researchers had been two years into a study of bats in the territory California plans to dot with floating offshore wind turbines over the coming decades. There’s so little information about how North American bats use the ocean environment that, in 2021, Newman and his colleagues determined in a peer-reviewed study that predicting the number of bats potentially killed by U.S. offshore wind development was “impossible” — at least until more data rolled in.
The bat project is one of 351 individual Energy Department awards, totalling nearly $16 billion in funding, that in early October appeared on a leaked list of potential grant terminations. News reports have since verified the cancellations of some awards on that list, including more than $700 million for batteries and manufacturing, according to Politico’s E&E News. The cancellation of EPRI’s bat research grant has not previously been reported.
The news comes as the Trump administration defunds other research investigating offshore wind’s impact on wildlife. In recent weeks, the Interior Department scuttled two programs, totalling over $5 million, that were actively monitoring the movement of whales in East Coast waters where five commercial-scale wind projects are currently being built.
The West Coast bat study, awarded federal funding in 2022, supported researchers from multiple organizations, including Bat Conservation International. The U.S.-based conservation group has been at the forefront of bat and wind-energy research for over two decades. Until recently, almost all of that work was devoted to onshore wind turbines.
“Wind energy is a really important component of our global energy transition. Unfortunately, wind turbines kill millions of bats globally every year,” said Winifred Frick, chief scientist at Bat Conservation International.
She contributed to a study last year that estimated onshore wind farms killed nearly 800,000 bats every year in just four countries that took annual tallies — Canada, Germany, the U.K., and the U.S.
It’s logical to expect fewer bat deaths might result from wind turbines spinning out in the ocean compared to ones operating on land. After all, according to Frick, even scientists like herself assumed that most species simply do not spend much time at sea.
But, at least on the West Coast, researchers had never scientifically checked. In fact, EPRI was collecting first-of-its-kind information on how the Mexican free-tailed bat interacts with the ocean, deepening scientists’ understanding of the species overall. The EPRI team detected the bats vocalizing while flying over a dozen miles off the coast of Southern California last year, thanks to an acoustic listening device attached to a small sailing drone they launched. Before this study, no one knew that this common and widespread species spent any time at sea.
“One of the things that we’re learning is that there are more bats flying out in the [ocean] environment than we might have otherwise expected,” said Frick.
And that means more bat species are potentially threatened by California’s future offshore turbines than previously thought. Frick added that a greater understanding of which species spend time at sea and when can inform the design of solutions that better minimize fatalities from wind farms.
One solution is called curtailment. Frick described this approach as changing the “cut-in speed,” which is the minimum wind speed at which operators allow turbine blades to begin spinning at certain times of day or year.
The modification does not typically lead to significant changes in energy generation for onshore wind farms but can make a big difference for bats, she said. For example, preventing turbine blades from spinning until the wind reaches 5 meters per second can reduce fatalities among many species by 62% on average, according to a study released last year by Frick and her colleagues.
Determining the best curtailment solutions for offshore wind turbines and North American bat species is still a work in progress. Energy Department-funded studies, like the EPRI effort, were seen as critical to determining which bat-saving modifications would work best for California’s unique vision to build floating turbines.
Frick called the grant’s termination “devastating” because the team may not get to finish the study. In the meantime, researchers are retrieving bat listening devices from spots along the West Coast.
Bat Conservation International continues its efforts to minimize bat deaths from turbines on land. It received a $2.4 million grant from the Energy Department last year to assess how new technology might help. That award also appeared on the leaked list of 351 DOE projects seemingly slated for cancellation. But, according to Frick, the federal government has yet to cut that research — “it’s not officially terminated” — and she remains optimistic that it might endure.
A clarification was made on Oct. 31, 2025: This story has been updated to more precisely reflect Christian Newman’s statements regarding the cancellation of EPRI’s award.
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