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Two years after slashing compensation for rooftop solar owners who send power back to the grid, California policymakers are once again looking for ways to contain high and rising electricity rates — which means the accusation that rooftop solar pushes costs onto other utility customers is once again rearing its head.
Last month, representatives of the California Public Utilities Commission testified in a state legislative hearing that California’s system for compensating owners of rooftop solar is a primary cause of the state’s rapidly rising utility rates.
That testimony is backed by a CPUC report, issued last month in response to an October order from Democratic Gov. Gavin Newsom to find ways to reduce utility-rate increases. Among other potential cost savings, the report proposes further reductions to rooftop solar compensation that the CPUC has already cut for homes, businesses, farms, and schools in the past two years.
The CPUC’s rationale is that solar programs shift costs onto customers who don’t have solar. Linda Serizawa, director of the CPUC’s Public Advocates Office, which is tasked with protecting utility customers, told lawmakers that the state’s rooftop solar regime has led to non-solar-equipped customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric paying $8.5 billion more than they otherwise would have in 2024. That increase accounts for up to a quarter of those customers’ monthly bills, on average, according to the Public Advocates Office.
Solar advocates and environmental justice groups have long said this “cost-shift” argument is false. In fact, they say, California utility customers would be paying even higher electric rates if the state hadn’t launched policies back in 2006 that have incentivized California homes, businesses, schools, and other utility customers to install more than 2 million rooftop solar systems since then.
Last week, several pro-solar groups shared new analysis, expanding on research released last year by energy and environmental consulting firm M.Cubed Consulting.
The latest round in the “cost-shift” debate comes as the CPUC’s December 2022 decision to cut compensation for newly installed rooftop solar systems has decimated the country’s leading rooftop solar market, potentially putting the state’s carbon-cutting goals out of reach. About 45% of the state’s solar power now comes from rooftop and distributed sources rather than utility-scale projects, but new rooftop solar installations have fallen dramatically since the CPUC’s new compensation system went into effect in mid-2023.
Without more rooftop solar, “we’re going to have increasing electricity costs, and we’re going to fall short of our clean energy goals,” said Ken Cook, president of the nonprofit Environmental Working Group. The challenge, he said, is to agree on regulatory structures that allow the state to “harness rooftop solar and distributed energy to solve both of these problems.”
But the cost-shift argument has short-circuited that kind of policy discussion, said Brad Heavner, policy director for the California Solar and Storage Association, a solar-industry trade group that funded M.Cubed’s cost-shift analyses. “It was devised by the utilities as a way to reframe what rooftop solar is and to put a negative light on it. And it has worked.”
Now, with mounting pressure to reduce utility rates, rooftop solar advocates fear the argument will be used once again to justify further cuts to an industry they view as crucial not only to climate goals but as a net benefit — not cost — to utility customers.
The cost-shift argument was initially put forward by the Edison Electric Institute, a trade group representing U.S. electric utilities. Utilities pay for building and maintaining the power grid through the rates they charge customers. The cost-shift thesis argues that paying some customers for their rooftop solar power unfairly shifts the burden of covering the costs of keeping utilities running onto other customers.
But Richard McCann, a founding partner at M.Cubed, argues that California’s nation-leading rooftop solar resource has saved customers as much as $1.5 billion in 2024 through savings accrued over the past two decades. The reason, in his view, is simple: More rooftop solar means utilities need to buy less energy from other resources and build less power lines and other grid infrastructure to meet customers’ power demand.
Back in 2005, the California Energy Commission forecasted that the state’s peak demand for electricity — the primary driver of utility costs for generation and grid capacity that are passed on to customers — would grow from about 45 gigawatts to more than 60 GW by 2022 or so, McCann said.
But peak electricity demand on the statewide grid operated by the California Independent System Operator (CAISO) has grown far more slowly. The system has instead topped out at a record-setting peak of 52 GW in September 2022 — only about 2 GW over the previous record set in 2006.
Over that same time, the state’s net-metering policies have incentivized millions of customers of the state’s three big utilities to install solar panels, he said. Much of the state’s peak grid demand coincides with hot summer afternoons — the same time that rooftop solar produces the most electricity.
CAISO does not directly track how much power rooftop solar generates across millions of California homes and businesses, McCann noted. But the simultaneous trends of lower-than-forecasted peak demand and growing rooftop solar resource indicate that “rooftop solar has displaced the peak load demand in the CAISO system and kept the CAISO load flat over that same time period,” he argued.
If that’s the case, customers investing in rooftop solar have helped the state’s utilities avoid investing in new generation, transmission, and distribution, potentially saving ratepayers billions of dollars, he said. “Rates would be even higher than what they are now if rooftop solar had not been present.”
McCann’s view, supported by most environmental advocates, the solar industry, and some energy analysts, is hotly contested by utilities as well as independent analysts who have championed the cost-shift thesis.
In the latter group’s view, rooftop solar is a more expensive and less efficient alternative to building utility-scale solar power plants and transmission grids. Shifting money from those larger-scale alternatives not only pulls money from customers without solar to those with solar, they argue, but represents a lost opportunity for utilities to invest in more cost-effective clean power.
Severin Borenstein, head of the Energy Institute at the University of California, Berkeley’s Haas School of Business, is a key proponent of the cost-shift theory. In January, Borenstein published a paper challenging McCann’s take on the value of rooftop solar, citing “fundamental conceptual errors that undermine most of its points.”
Borenstein said that a proper analysis finds that in 2024 solar net-metering pushed about $4 billion in costs onto utility customers who don’t have solar. That’s not nearly as high as the $8.5 billion figure from the CPUC’s Public Advocates Office, but it’s still a net cost rather than a benefit to customers at large.
In February, McCann published a reply to Borenstein’s critique, delving into his point-by-point differences of opinion on how these costs should be calculated. Much of the dispute is highly technical in nature. And because these analyses rely on heavily varied assumptions — including what would have happened if the past 20 years of rooftop solar policy hadn’t played out the way they have — many of the conflicts between the two sides on precise numbers can’t be answered definitively.
That uncertainty has led both sides to accuse the other of using intentionally misleading data and methods. McCann acknowledged that his initial analysis last year miscalculated the benefits that he believes rooftop solar has delivered to customers of the state’s three big utilities. He originally calculated $2.3 billion worth of benefits in 2024, rather than the $1.5 billion that emerged from his latest analysis.
The in-the-weeds exchange between McCann and Borenstein reveals a deeper disagreement at the heart of their vastly different estimates — one that cost-shift foes say California regulators have failed to fully acknowledge. It centers on a simple question: When a household generates solar power at the same time as it’s using electricity from the grid, who owns that solar?
According to McCann, who cited legal precedents and the fundamental physics that determine the flow of electrons, solar power that customers generate and consume at their own homes and buildings is theirs by right. They paid for the solar systems, and they’re directly using the electricity those systems generate.
But according to both Borenstein and the Public Advocates Office’s analysis, solar power simultaneously generated at the time that power is being consumed on site should be considered as a cost to other utility customers.
As Borenstein states in his January rebuttal, “So long as a solar system is connected to the grid, there is no real distinction between self-consumption and grid supply. Despite this fact, if a customer’s aggregate rooftop solar production during an hour is equal to the household’s consumption, then some argue that the customer is ‘self-consuming’ and their consumption in that hour should not be obligated to make any contribution to grid costs or other costs that are part of the retail price.”
In other words, according to this logic, allowing solar-equipped customers to count the power they generate as offsetting their use of grid power undermines the fundamental structure of utility rates, which recover the costs of electricity delivery by charging customers for their hour-by-hour energy use.
These two different interpretations go a long way in explaining the chasm between McCann’s analysis and those from Borenstein and the Public Advocates Office. According to McCann’s analysis, this category of “cost” — self-generated solar power considered as the property of the utility and ratepayers at large, rather than belonging to the individual households using it — accounts for nearly $4 billion of the Public Advocates Office’s $8.5 billion cost-shift calculation.
But McCann believes that Borenstein and the Public Advocates Office’s perspective runs afoul of standing legal and regulatory precedent on such matters.
He cited a 2015 paper in which Jon Wellinghoff, former chairman of the Federal Energy Regulatory Commission, and Steven Weissman, a former CPUC administrative law judge and a founder of the energy law program at the UC Berkeley School of Law, state that “[p]roperty owners in the United States have the right to generate electricity onsite, for their own use. This understanding is so fundamental that legislatures have not bothered to spell it out.”
FERC has dismissed arguments that solar generated at homes and other buildings should be regulated by the federal authorities governing the bulk-electricity grid.
The bigger problem with the cost-shift numbers from CPUC and the Public Advocates Office is that they have never been subjected to the kind of regulatory process that could allow regulators, lawmakers, and the public at large to fully grasp and argue over the validity of the assumptions that have gone into them, Loretta Lynch, an attorney and energy policy expert who served as CPUC president from 2000 to 2002, said during a webinar led by M.Cubed last week.
Instead, the Public Advocates Office published a paper in August 2024 asserting its cost-shift figure, which has since been used to justify a range of policy decisions, she said. That’s not how regulators are supposed to do things, Lynch added.
“Before the CPUC goes and touts an unvetted report of dubious calculation and worth, perhaps it should put that report in an evidentiary hearing in a proceeding, along with Richard’s analysis,” she said, referencing M.Cubed’s latest paper.
Then, the CPUC could “have the expert analysts go toe-to-toe, under oath, with questions and cross-examination, so we can see the assumptions made, the data used, and whether or not the conclusions are valid.”
It’s important to note that these cost-shift analyses are looking at California’s rooftop solar past, not its future. In more recent years, as solar has grown to make up an increasing portion of California’s electricity-generation mix, peak grid demands have shifted from late afternoons when the sun is still shining to hot evenings after the sun goes down. Every new increment of solar power added to the grid is less and less useful on its own in reducing these new “net peak” demands.
Batteries that store power for use during these post-sundown peaks have thus become a vital addition to new solar installations, both at the utility scale and at homes and businesses.
The net-billing tariff the CPUC approved in late 2022 to replace its previous net-metering regime offers far lower payments for the electricity that newly installed rooftop solar systems inject onto the grid, except for a few hours per year when peak power is in dire need. That structure rewards customers who add batteries that can store and inject power during those valuable hours — a service that should reduce how much energy utilities need to secure and how much grid infrastructure they need to build to serve those peak moments.
But solar advocates are now worried that the CPUC’s report on containing rate increases calls for reducing the value of solar power for “legacy” net-metering customers as well.
Under the CPUC’s previous net-metering regimes, customers are paid full retail rates for solar power they send back to the grid for 20 years. In its February report, the CPUC proposes shortening those legacy periods, which could reduce costs for utilities but also undermine the economic calculations that made rooftop solar worthwhile to customers who installed it with the assumption that those rules wouldn’t change.
The CPUC report also proposes adding a “grid-benefits charge” to the bills of existing rooftop solar owners — in essence, charging them extra for having solar panels. Utilities have previously proposed this concept and shortening legacy net-metering periods, but regulators rejected them after significant pushback.
The CPUC’s new report doesn’t advocate for these or any other particular changes to utility regulations or policy. But it does propose that state lawmakers consider finding “non-ratepayer sources” to compensate customers with rooftop solar.
The CPUC didn’t specify which alternative sources could fill that gap. Prior proposals to use state tax revenues or California’s cap-and-trade program could be part of the mix, said Mark Toney, executive director of The Utility Reform Network, a ratepayer-advocacy group.
But even supporters of those concepts like Toney don’t see much hope of lawmakers fielding bills that would ask taxpayers to shoulder costs now borne by utilities. “It is wishful thinking that we could shift rooftop subsidies to taxpayers,” he said. “I’m not holding my breath here.”
Given the unlikely prospects of using taxpayer funds to pay rooftop solar customers, solar advocates fear that the CPUC’s proposal is an opening shot in a battle to weaken rooftop solar even further.
Cook of the Environmental Working Group described the potential ramifications of such a move: “If people come to believe that any agreement they thought was going to be good for, say, 20 years means nothing to the state and to the utility regulators — if it can be wiped away — that’s going to make it even harder to convince people to think that their own investments and rooftop solar are going to pencil out.”
Ascend Elements, a leading contender in advanced battery recycling, canceled a portion of its planned battery-materials plant last week. The company still aspires to expand a fully domestic battery supply chain but has had to adapt to tumultuous policy and market conditions.
China controls most of the world’s processing capacity for key battery inputs. Under the Biden administration, the U.S. began a concerted effort to build up those resources — like lithium mines, lithium-processing plants, and advanced facilities that make cathode active materials (CAM) that go into batteries.
A cohort of battery-recycling startups joined the cause, pledging to safely and economically disassemble old batteries and funnel their pieces back into the supply chain. Ascend is one of them: The Massachusetts-based company opened a plant in Covington, Georgia, in March 2023 that grinds up used batteries into the powder known as black mass. Ascend is currently building a plant in Hopkinsville, Kentucky, where it will refine that black mass into battery materials.
That project, called Apex 1, is still happening, but Ascend has narrowed its scope: The startup announced last week that it is scrapping plans to produce CAM there and agreed to cancel the $164 million grant that the project won from the Department of Energy. Ascend intends to convert the space that would have made CAM into a lithium carbonate production line, using a proprietary technology the company rolled out at its Covington plant early this year.
Apex 1 will still produce the precursors to CAM known as pCAM, an effort aided by a separate $316 million grant from the DOE. These powders include cathode materials like nickel, manganese, and cobalt; manufacturers add lithium to those ingredients and fine-tune the recipe to generate finished CAM.
Between the previously planned pCAM and the newly announced lithium carbonate lines, Ascend still plans to invest about $1 billion in the Kentucky project, spokesperson Thomas Frey told Canary Media on Tuesday.
The companies that buy CAM already have supplies lined up, and demand isn’t growing fast in the near-term, Frey said. But the companies that make that CAM need to obtain the precursor materials from somewhere, and that’s where Ascend still sees an opportunity.
“By getting out of CAM, we’re essentially turning potential competitors into potential customers,” he said.
Ascend can sell its pCAM to specialized CAM manufacturers or to electric-vehicle and battery manufacturers who want their suppliers to use that particular material, Frey noted.
“We’re still really highly committed to creating a domestic, closed-loop battery ecosystem in the U.S.,” Frey said. “We will be the only large-scale manufacturer of pCAM in America. With tariffs at play and things like that, that makes us pretty appealing.”
Another benefit to focusing on pCAM is that it’s a more generalizable product than CAM, which has to be tailored intricately to each battery manufacturer’s proprietary designs. Since batteries are such a precisely calibrated technology, prospective buyers scrutinize CAM samples for a year or more before clearing producers for a large commercial order. The sales cycle for pCAM is quicker and easier, Frey said.
Ascend’s timeline has also been influenced by a broader slowdown in the U.S. electric-vehicle manufacturing buildout. Detroit automakers have pulled back on their earlier enthusiasm for EV production, which has pushed back timelines for the battery supply chain, including CAM and pCAM.
Some companies have canceled battery factories in just the last few weeks, like Freyr Battery (now T1 Energy), which had aspired to build one in Georgia, and U.S. startup Kore Power, which ditched plans for a facility near Phoenix.
Ascend has extended its timeline for Apex 1 from the end of 2025 to the third quarter of 2026, which Frey said allows for a more cost-effective construction process. Commissioning is underway for the new lithium carbonate line at Ascend’s Covington factory, which should begin commercial production in the next few months, he added.
The Covington plant has also struggled with a more fundamental problem: The old batteries the facility grinds up keep catching fire.
Firefighters responded to a Feb. 20 conflagration in a tractor trailer delivering used batteries to the site. The fire consumed the trailer but did not jump to the adjacent building, per local news reports from the scene.
Jarringly, that was the 14th time Ascend’s Covington plant called in emergency teams. Not all those calls included outright fires, and nobody was injured in any of them, plant manager Andrew Gardner told WSB-TV. But the track record has the city’s mayor worried about the safety of hosting such a facility in the community.
Some of those calls involved workplace injuries and concerns unrelated to lithium-ion batteries, Frey noted to Canary Media. Nonetheless, the latest incident was the biggest thermal event so far; it destroyed the trailer and left some burn marks on the exterior of the nearby building but did not enter the structure. The cause seems to have been batteries that were not properly packed or discharged prior to shipping.
“Since then we have gone on a blitz with all of our customers to redo training on how to pack end-of-life batteries and scrap,” Frey said. “We’ve stopped operations for 10 days to work really closely with the Fire Department and the mayor to show them we’re doing everything we can to ensure safety.”
Maine’s solar incentive program has become a political scapegoat for rising electricity prices in the state, but clean-energy advocates say the numbers don’t add up.
Maine utility customers pay some of the country’s highest electricity prices, but the portion of their monthly bills that goes toward buying surplus power from neighbors’ solar panels has actually decreased in recent months, according to one analysis.
Meanwhile, the amount of money utilities are paying for power from fossil fuel–fired plants and transmission represents a far bigger share of the electricity-bill bottom line.
“It’s an easy narrative to say ‘Solar panels are being built in this field, and electricity prices are going up,’” said Lindsay Bourgoine, director of policy and government affairs at solar company ReVision Energy. “But that’s not actually what’s happening when you look at the data.”
Maine Republican lawmakers this session have introduced four different bills calling for the repeal of net energy billing, the system that compensates utility customers for unused electricity they generate and share on the grid. Supporters of the bills have called the program a “job-stealing solar energy tax,” though it’s not a tax: Utilities compensate the owners of solar panels for excess energy sent to the grid, then spread the cost out among ratepayers.
“What’s really troubling in Maine is that there is this growing narrative that the rise in utility bills is directly attributable to solar,” said Eliza Donoghue, executive director of the Maine Renewable Energy Association. “It’s not true.”
The hostility toward Maine’s net energy billing rules is part of a wave of efforts to blame rising power prices on clean-energy and energy-efficiency programs, particularly in New England. In Rhode Island and Maryland, legislators have called for cuts to fees supporting energy-efficiency and clean-energy programs. And Massachusetts regulators last week ordered $500 million to be cut from the state’s energy-efficiency plan, following utilities’ claims that these money-saving programs have been a major driver of rising energy bills.
At a legislative committee hearing last week, Maine legislators testified that small-business owners will be forced to close their doors and low-income households put in dire financial straits by wealthy solar-panel owners imposing the cost of their renewable-energy choices onto everyone else. It is “a nefarious scheme,” said Sen. Trey Stewart, a Republican and the sponsor of one of the bills. “We risk collapsing our entire economy,” said Republican Sen. Stacey Guerin, the sponsor of another.
The numbers tell a very different story, beginning with the actual dollars-and-cents impact of net energy billing on the average consumer.
Maine’s net energy billing program was expanded in 2019, increasing its cost but also spurring new solar development. By the end of 2024, the state had more than 1,500 MW of solar capacity, up from less than 100 MW in 2019.
Statewide, costs attributed to net energy billing now make up a slightly smaller percentage of the average bill than they did in the latter half of 2024, according to calculations ReVision made using information from utility filings. For Versant Power residential customers using 500 kilowatt-hours per month, net energy billing adds between $6.40 and $7.62 to the monthly bill depending on their exact location, according to a spokesperson for the utility. Central Maine Power residential customers pay on average $7.06 per month for costs related to net energy billing, a spokesperson for the company said.
So if it’s not the solar program, then what is causing utility bills to rise? One of the main forces driving electricity prices is the cost of energy supply in New England, more than half of which comes from natural gas–fired power plants. Volatility in the natural gas market, therefore, translates directly into higher electricity rates for consumers. Prices spiked in 2022 and 2023, for example, as the war in Ukraine pushed the cost of natural gas up worldwide. This year, energy supply accounts for 39% of a typical Maine household’s monthly bill — roughly nine times the cost of net energy billing — according to ReVision’s numbers.
“Solar isn’t the problem. Fossil-fuel volatility really is,” Bourgoine said.
The other major contributor is rising transmission costs, which on average make up 51% of electricity bills, up from 37% in the second half of 2023.
There are some commercial cases in which the cost for net energy billing does have an outsized impact on energy bills, supporters of the incentive agree. Commercial power customers are charged a fixed rate based on the specific rate classification their business falls under. This system means some businesses end up with a much larger percentage of their bill paying for net energy billing.
At last week’s hearing, Sen. Stewart testified that potato processor Penobscot McCrum will pay close to $700,000 in public-policy charges this year. Roughly 55% of this charge reflects the costs of net energy billing, according to utility Versant.
Supporters of net energy billing agree that situations such as these are unfair and unsustainable, and a docket is already underway with the state Public Utilities Commission to address that specific issue without repealing the entire net energy billing program, Donoghue said.
“There is a certain amount of customers that, we agree, should be complaining,” she said.
Net energy billing also provides benefits that are hard to see but which offset the costs, supporters said. In 2023, the program cost ratepayers $130 million but delivered $160 million in benefits to the state, according to an independent analysis prepared for the Public Utilities Commission. By adding solar power to the grid, the program helps suppress wholesale electricity prices, for example, and it improves reliability because there cannot be a shortage of “fuel” for solar generation.
More solar generation in the state means more Maine households are getting power produced in or near their communities, lowering the strain on the transmission and distribution systems — and the associated costs. Solar developers also pay for any infrastructure upgrades needed to accommodate their projects.
“Those are investments that utilities don’t have to put on ratepayers,” said Jack Shapiro, climate and clean energy director for the Natural Resources Council of Maine.
Furthermore, eliminating net energy billing would have its own financial consequences for the roughly 110,000 customers enrolled in the program. The abrupt end of all net energy billing would leave these participants — including residents, businesses, and schools – without promised and planned-for savings, Shapiro said.
Opponents in the legislature have passed three rounds of rollbacks to the program. Now they want to go even further.
“If [these bills] were passed, they would actually have some truly disastrous consequences for a lot of people and schools and municipalities,” Shapiro said.
Sunnova, one of the country’s largest residential-solar companies, has warned investors that it may run out of money within the next 12 months. It’s a snapshot of a company struggling to maintain financial viability amid a punishing economic climate for rooftop solar installers and financiers.
The “going concern” warning came during Sunnova’s fourth-quarter and fiscal-year earnings statement on Monday. The news sank the Houston-based company’s stock price from about $1.60 per share on Friday evening to a low of 56 cents per share on Monday morning. (Sunnova shares were trading at about 60 cents as of market close on Monday.)
Sunnova’s revenue grew to about $840 million in 2024, up from nearly $721 million in the prior year. But the company’s net losses before income taxes of almost $448 million last year were little improved from just over $502 million in 2023. The losses stemmed from declining sales of solar energy systems and products alongside rising operating expenses.
Over the course of the year, Sunnova was unable to increase the amount of unrestricted cash and commitments under existing financing arrangements to fund its business. The company, which finances rooftop-solar and battery installations conducted by independent installers, laid off about 300 employees, or about 15% of its workforce, in February.
As of Friday, these unrestricted funds were “not sufficient to meet obligations and fund operations for a period of at least one year from the date we issue our consolidated financial statements without implementing additional measures,” the company stated.
A Sunnova spokesperson told Canary Media on Monday that the company is “confident in our ability to manage our obligations and position Sunnova for long-term success.”
The bad news from Sunnova comes amidst a tough economic picture for U.S. rooftop solar overall. The nation’s residential-solar installations were forecast to decline by roughly 26% in 2024 compared to 2023 in a December report from analytics firm Wood Mackenzie and the Solar Energy Industries Association trade group — the market’s first annual drop in at least four years.
“When interest rates began to really escalate, more than two years ago, it put a damper on demand for residential solar across the United States,” said Pavel Molchanov, investment strategy analyst at financial services firm Raymond James. “The cost of capital for residential solar correlates with what’s happening with the broader interest-rate environment.”
The Federal Reserve started cutting rates last fall. But the economic and trade policies instituted by President Donald Trump have raised fears of a potential economic downturn and increasing inflation, tamping down expectations of near-term interest rate cuts.
Among different types of solar power, “residential solar is near the high end of the spectrum” in terms of its sensitivity to interest rates, Molchanov added.
That’s in part because residential rates tend to be higher from the start. Unlike utility-scale solar projects, which are backed by power purchase agreements from utilities or large corporate customers, residential projects are “ultimately tied to individual homeowners,” Molchanov explained, increasing the perceived risk of default — and raising the interest rates they are offered as a result.
Sunnova CEO John Berger said in a Monday statement that the company has “acted on several initiatives” to improve its financial picture, including “raising price, simplifying our business to reduce costs, and changing dealer payment terms,” which are intended to “support positive cash in 2025 and beyond.”
But Sunnova’s financial position may make it difficult for the company to raise the capital it needs, at least at reasonable terms. The company stated on Friday that it had secured a $185 million loan at a 15% interest rate, which is well above typical corporate borrowing rates, to use for “general working capital purposes.”
The interest-rate environment has helped drive a number of residential-solar companies into bankruptcy in the past two years, including SunPower, one of the country’s oldest solar companies. Some of SunPower’s assets have been bought by residential installer Complete Solaria.
Sunrun, the country’s largest residential solar and battery installer, also reported declining revenue and increasing losses in 2024 compared to the previous year in an earnings statement last week.
Beyond interest rates, Sunnova and other residential-solar installers have had to contend with a dramatic shift in California’s residential-solar policy, Molchanov said. The state is by far the largest rooftop-solar market in the country.
In April 2023, California regulators sharply reduced the net-metering rates that owners of rooftop solar systems can earn for the electricity they feed back to the power grids operated by the state’s three large investor-owned utilities. Residential solar installations have dropped sharply since that change, and many solar companies in the state have laid off workers or closed their doors.
California’s cutback on net metering “put a damper on demand, compounding the effect of high interest rates,” Molchanov said. Residential-solar sales in the state have grown slightly in recent quarters but remain far from their pre-2023 highs, according to the California Solar and Storage Association trade group.
Residential solar could be hampered further by the Trump administration and Republican-controlled Congress.
After Trump’s election, publicly traded clean-energy companies including Sunrun and Sunnova took hits in the market due to fears that the president’s antipathy to climate and clean-energy policy could drive Congress to undo or weaken federal tax credits that play a central role in boosting the economics of solar power. Trump’s decisions on tariffs could also raise the cost of solar systems.
Sunnova has itself previously been targeted by Republicans in Congress. In 2023, the company won a $3 billion loan guarantee from the U.S. Department of Energy to support its effort to lower consumer costs for financing “virtual power plants” — solar systems bolstered by batteries that can help reduce peak energy.
Rising electricity costs are one of the few tailwinds for residential solar, Molchanov said. Utility rates have been climbing in many parts of the country, which can make generating one’s own electricity more attractive by comparison. More households are also looking to residential systems for reliability purposes, choosing to pair batteries with solar to provide power during grid outages.
“But the No. 1 variable we need to watch is interest rates,” Molchanov said. “The higher they go, the more difficult it will be for residential solar in the aggregate in this country.”
A number of Connecticut cities and towns want to secure more clean electricity for residents using a program that has already saved millions of dollars for consumers in other states.
Community choice aggregation allows cities and towns — or, in some cases, multiple municipalities working together — to negotiate with electricity suppliers on behalf of their residents. The goal is to achieve lower rates than those offered by utilities, often with a higher percentage of renewable energy in the mix.
“Municipalities can play a bigger role in using less electricity, using it more efficiently, and reducing the cost,” said Peter Millman, vice president of People’s Action for Clean Energy, a Connecticut nonprofit that supports community choice aggregation. “I hate to see an opportunity wasted.”
Nationally, community choice aggregation, also known as municipal aggregation, is authorized by ten states, including Northeast neighbors Massachusetts, New Hampshire, New Jersey, New York, and Rhode Island. Connecticut could become the eleventh: The state legislature is now considering a bill, HB 6928, that would allow municipalities to create these programs. The measure has wide support from environmental groups and municipal leaders.
Data suggest there are opportunities for meaningful savings. In Massachusetts, 225 of the state’s 351 cities and towns had approved municipal aggregation programs as of July 2024, and many include a higher percentage of renewable energy than required by law. In one group of communities, households realized an average of $200 to $237 in annual savings while receiving electricity with 5% to 11% more renewable power content than state requirements, according to an analysis from the Green Energy Consumers Alliance, a nonprofit that helps municipalities create aggregation programs.
“History shows that when a community aggregates consumers for the supplier side, good things happen,” said Larry Chretien, executive director of the organization. “It’s a fallacy that you can’t have greener power without paying more.”
Connecticut’s version of aggregation could be particularly ambitious, following a model used in California and New Hampshire. This approach allows cities and towns to choose between a basic aggregation program, in which a hired energy broker negotiates for electricity on behalf of residents, and a system in which multiple municipalities band together to form a larger aggregator that could handle the process of procuring power itself.
The multi-community approach allows these aggregation groups to retain the revenues that would have gone to an outside broker and use these reserve funds to develop and manage their own programs aimed at producing renewable energy, supporting energy efficiency, or reducing demand. In its first year, New Hampshire’s aggregation program saved ratepayers in participating communities about $14 million and created revenue of $10 million for reinvestment.
In California, this strategy has helped fund dozens of programs including battery rebates, electric vehicle charging infrastructure, and discounts on solar power for low-income households.
Some skeptics of community choice aggregation have raised concerns about Connecticut’s proposed model, which would make a city or town’s negotiated rate the default for residents but allow them to opt out if they’d rather stick with utility service or an alternate supplier. Consumers, they say, should not be placed in a new program without choosing to make the move.
Supporters, however, argue that the successes in states where municipal aggregation has already been deployed demonstrate the model works with little risk to consumers.
“The opt-in model simply doesn’t work,” Millman said at a legislative committee hearing last week. “If these aggregations were not meeting or beating utility rates most of the time, there would be lots and lots of defections — and there are not.”
The numbers are in, and clean energy is set to sweep U.S. power plant construction yet again this year.
The U.S. is expected to build 63 gigawatts of power plant capacity this year, more than it has in decades, as new AI computing and domestic manufacturing projects cause a surge in energy demand. At this crucial juncture, plants that don’t burn fossil fuels are set to deliver 93% of all the new capacity joining the U.S. grid in 2025, per new estimates from the federal Energy Information Administration.
The new prediction is no fluke — carbon-free sources delivered nearly all the new capacity last year, too. And the trend was building for years before that.
This year, utility-scale solar is expected to continue its winning streak as the largest source of new electricity generation. More than half of new power plant capacity built this year will be solar, followed by batteries, with 29% of total capacity. That’s a step up for batteries from last year. Meanwhile, solar’s share is forecast to fall, but EIA expects more construction in absolute terms — 32.5 gigawatts compared to 30 last year.
Wind will add 12% of the new capacity, burnished by two major offshore wind projects the EIA still expects to come online despite political headwinds: Massachusetts’ 800-megawatt Vineyard Wind 1 and Rhode Island’s 715-megawatt Revolution Wind. The Trump administration unilaterally halted federal permitting for new offshore wind projects, but these are among the five that were already under construction, with necessary permits in hand.
This dominant showing from clean energy developers leaves natural gas with just 7% of new power capacity. That fossil fuel still leads in total U.S. electricity generation with about 42% of the mix but has entered a multi-year slump in terms of new construction.
The EIA predicts total gas-fired generation — the actual electricity produced — will fall 3% this year while solar generation rises by more than one-third.
This dataset offers a snapshot of where the U.S. power industry is heading — and the direction is toward cleaner, cheaper energy that mainly comes from solar and batteries.
But beyond the climate metrics, these clean power plants are proving vital in meeting the needs of an increasingly power-hungry economy. Data centers, AI hubs, and the domestic manufacturing that grew during the Biden administration all need more electricity. Renewables and batteries are the source of energy that can meet this demand most quickly and cost-effectively, though they still need to work alongside other resources to ensure 24/7 service.
A 67-person Finnish startup called Hycamite has just completed a facility it hopes will revolutionize production of low-carbon hydrogen.
The plant, in the industrial port city of Kokkola, on Finland’s west coast, will soon receive gas shipments from a nearby liquefied natural gas import terminal and turn the fossil fuel into hydrogen. That in itself is not novel — pretty much all of the world’s commercially produced hydrogen comes from methane, the main ingredient in natural gas. But all those legacy hydrogen producers end up with carbon dioxide as a byproduct, and they vent it into the atmosphere, exacerbating climate change. Hycamite will make hydrogen without releasing CO2, using a little-known process called methane pyrolysis.
“We split the methane with the help of catalysts and heat — there’s no oxygen present in the reactor, so that there’s no CO2 emissions at all,” founder and Chairman Matti Malkamäki told Canary Media in a December interview. “We are now entering industrial-scale production.”
Hycamite’s Customer Sample Facility in Kokkola can produce 5.5 tons of clean hydrogen per day, or 2,000 tons per year, Malkamäki said. Instead of creating carbon dioxide as an inconvenient gaseous byproduct, pyrolysis yields solid carbon. Hycamite uses catalysts developed over 20 years by professor Ulla Lassi at the University of Oulu, which transform the methane into “carbon nanofibers with graphitic areas.” This solid carbon can be processed further to produce graphite that Malkamäki plans to sell to battery manufacturers and other high-tech industries.
Hycamite closed a $45 million Series A investment in January to fund operations at the hydrogen plant. But it’s just one of a growing cluster of climatetech startups betting that the dual revenue stream of hydrogen and useful carbon products gives them an edge in the nascent marketplace for clean hydrogen, a much-hyped, little-produced wonder fuel for solving tricky climate problems.
Low-carbon hydrogen theoretically could clean up emissions-heavy activities like long-distance trucking, shipping, steel making, and refining — if anyone can manage to make it, at volume, at prices that compete with the dirty stuff that’s already available. In the U.S., some hydrogen producers and fossil fuel majors have talked about retrofitting carbon-capture machinery onto existing hydrogen plants, but nobody’s built a full-scale “blue hydrogen” operation so far. Renewables developers have evangelized “green hydrogen,” which is made by running clean electricity through water to isolate hydrogen, but they need electrolyzers and the production of clean electrons to get considerably cheaper. Until then, they’ll depend heavily on government policy support.
Now President Donald Trump is treating Joe Biden’s suite of clean energy policies like a piñata, and it’s hard to tell if incentives for producing green hydrogen will even survive. That’s already scaring off investors from large, capital-intensive green hydrogen projects. But the up-and-coming pyrolysis crew could find a niche: Their projects are smaller and nimbler, and they consume natural gas, one sector that Trump has ordered his government to encourage.
Methane pyrolysis entrepreneurs like Malkamäki are heeding the call of fundamental chemistry.
“Thermodynamically, it’s far more energy-favorable to split methane than to split water,” said Raivat Singhania, a materials scientist who scrutinizes hydrogen startups at Third Derivative, a clean energy deep-tech accelerator. Water’s chemical bonds hold together more fiercely than methane. That means companies trying to make clean hydrogen by splitting water need huge amounts of electricity to overcome the strength of its bonds; sourcing that electricity creates a daunting cost and a logistical hurdle.
Not only does methane-splitting require less energy, it can be done with a simpler plant design than water electrolysis, using fewer moving parts or fragile pieces of equipment, Singhania noted. This analysis informed Third Derivative’s investment in Aurora Hydrogen, which breaks methane using microwaves.
Those thermodynamic advantages come with tradeoffs. Namely, would-be methane pyrolyzers need a ready source of methane, which in practical terms means a pipe delivering fossil gas. That inevitably entails some level of upstream emissions.
Methane pyrolyzers also need to be located where gas is abundant. It’d be hard to scale up in places like Europe, post Russia’s invasion of Ukraine, or Massachusetts when winter rolls around. But supply is ample across much of the U.S., which is producing more fossil gas than any country ever. Hycamite is building its commercial test facility in its home base of Finland, but the company is looking to the U.S. to deploy its technology, Malkamäki said.
Right after taking office in January, Trump responded to world records in U.S. fossil fuel production by declaring an “energy emergency” and ordering his administration to clear the way for even more fossil fuel extraction.
It’s not clear whether the fossil fuel industry can or wishes to increase production dramatically; in market-based systems, excess supply tends to deflate prices. Whether production stays at current record highs or pushes further skyward, the U.S. will have plenty of gas to go around, and methane pyrolysis companies could generate the kind of new demand that the industry desperately needs. Moreover, they would be using American fossil fuel abundance to create materials useful for the transition to clean energy.
For that to happen, though, pyrolysis startups need to break through early technical demonstrations and start producing at scale.
Hycamite is not the only company chasing the pyrolysis dream.
The American startup Monolith is arguably furthest along in the quest to turn laboratory science into industrial-scale production. It uses high-heat pyrolysis to produce hydrogen and a dark powdery substance called carbon black, an additive used in tire and rubber manufacturing.
Monolith received a conditional $1 billion loan from the Department of Energy in late 2021 to build out its facility in Nebraska, which would deliver clean hydrogen to decarbonize fertilizer production. Monolith had to run a gauntlet to prove to DOE’s Loan Programs Office that it deserved such a loan. It has the rare distinction among pyrolysis startups of having actually sold its carbon products: Goodyear makes a tire for electric vehicles using Monolith’s carbon black.
However, Monolith did not finalize the loan before the Trump administration came to office and froze new disbursements for clean energy. The company was running short on cash while struggling to get its high-heat process to work reliably around the clock, per a Wall Street Journal article published in September. Monolith secured additional financing from its investors just before that story published.
Several other startups want to boost their revenues by turning methane into higher-value forms of carbon than carbon black, a relatively inexpensive commodity — if they can achieve the quality and consistency necessary to sell into those specialized and demanding markets.
A group of Cambridge University scientists founded Levidian in 2012 to create reliable, large-scale production of graphene, a carbon-based supermaterial discovered in Manchester, England, in 2004. After another eight years of research and development under the moniker Cambridge Nanosystems, the company was acquired and brought to market by a British entrepreneur.
Levidian eschews the catalysts, heat, and pressure that other startups use to split methane. Instead, the team ended up building a nozzle that sucks in methane gas, then uses electricity to generate microwave energy, which in turn creates a cold plasma torch that shaves carbon atoms from hydrogen atoms.
This yields hydrogen and graphene, which can be used in semiconductors, electronics, and batteries. Levidian can sell graphene for hundreds of dollars per kilogram, far more than carbon black, CEO John Hartley told Canary Media in January. Indeed, the company will host its first graphene auction on March 24. To install its technology, though, Levidian has focused on customers who want to clean up their fossil gas emissions.
“It’s really an onsite carbon-capture unit at its core: It catches carbon, makes hydrogen, and decarbonizes methane gas,” Hartley said. The first customers include Worthy Farm, which hosts the Glastonbury music festival; a wastewater treatment plant in Manchester; and the Habshan gas processing facility in Abu Dhabi.
U.S.-based Etch builds on research by founder Jonah Erlebacher, a materials science professor at Johns Hopkins University. The startup splits methane with what it describes as a recyclable catalyst that contains no rare minerals; it produces graphite and other forms of carbon.
The Etch team is wrapping up commissioning for its first “commercial-scale pilot” in Baltimore, a spokesperson told Canary Media. Last fall, the startup brought in a new CEO with commercial chops: Katie Ellet previously served as president of hydrogen energy and mobility for North America at Air Liquide, one of the few companies actually producing low-carbon hydrogen at scale, and a key player in six of the seven hydrogen hubs funded by the Department of Energy.
All these companies need to hit their stride just as the clean hydrogen market has entered a period of tumult.
The Biden administration hoped to jump-start a clean hydrogen economy with two major policies: A suite of billion-dollar grants to seven “hydrogen hubs” strategically chosen around the country, which are intended to link up production with entities that could use the fuel to clean up transportation and heavy industry, and a production tax credit to effectively lower the market price of hydrogen produced using low-carbon methods.
Now, the Trump administration has frozen payments on clean energy grants and loans. Prospective hydrogen producers had been waiting breathlessly for the final IRS guidance on the 45V tax credit; now that the lawyers have finally produced that guidance, the nascent hydrogen industry has to plead with the new administration to preserve those credits as it overhauls federal spending this year.
Given this swirling uncertainty, pyrolysis startups can take some solace in the fact that their business is not entirely dependent on the vagaries of hydrogen policy. At least they can sell carbon materials, which have clear value and established buyers who use the stuff in a non-theoretical way.
I asked Malkamäki if Hycamite identifies as a carbon company that also makes hydrogen or a hydrogen company that also makes carbon. He pointed out that the company name itself is a mashup of “Hy-” for hydrogen and “ca-” for carbon (and the -mite is a reference to a fanciful super-fuel that Donald Duck invented in a vintage comic strip). The revenues from the carbon products are “elementary for us to be profitable,” he said. “A couple of investors have said to us that hydrogen makes you sexy, carbon makes you money.”
That’s not to suggest breaking into the battery supply chain will be easy. It requires passing rigorous, multi-year testing by the battery makers that might buy Hycamite’s carbon products. But this kind of revenue can bolster a young business as it rides out the storm in Washington.
When solar developers look to build big projects on farmland, the same arguments tend to come up: The array will waste useful agricultural tracts, ruin views, and sully the pastoral character of the rural community, public commenters say.
In Ohio, a state where these debates have long played out, comments like that have even led the state’s power siting board to block projects. These sentiments, in Ohio and beyond, are sometimes motivated by misinformation from anti-solar groups, including organizations with fossil fuel industry ties.
But as one solar developer recently found, hundreds of negative comments don’t necessarily mean hundreds of people oppose a project, Kathiann Kowalski reported this week for Canary Media.
The Ohio Power Siting Board received more than 2,500 comments about the Grange Solar Grazing Center, which aims to bring solar and sheep together on a 2,570-acre plot in the state’s Logan County. When the project’s developer took a closer look at the feedback, it found 16 individuals had collectively submitted more than 140 of those comments, most of them opposing the project. When accounting for repeats, the company found that 80% of individual commenters actually back the solar array.
Supportive commenters said they expect the Grange project to bring jobs and public funding to the county. A 2023 report from the Purdue Center for Regional Development verified that solar projects typically create short-term construction jobs, bring in tax revenue, and help raise farmers’ land values.
Taking a step back, it’s worth noting that more than three-quarters of Americans support expanding solar, per a May 2024 survey from Pew Research Center. That includes 64% of Republicans — though the group has soured on the energy source in recent years.
Mass layoffs hit the Energy Department
The Trump administration closed last week with a big — but not totally unexpected — blow to the U.S. Energy Department workforce. As many as 2,000 probationary DOE employees were laid off, ending what one staffer described to Latitude Media as a “weird, quiet limbo” following President Donald Trump’s inauguration.
But the layoff didn’t last long for a group of employees at the Bonneville Power Administration. About 30 workers who maintain power lines and other infrastructure at the Pacific Northwest grid operator were asked back just days later, a union leader told Politico.
Clean energy smashed a record last year
The U.S. added a whopping 48.2 GW of new utility-scale solar, wind, and battery storage capacity in 2024, an increase of 47% from the year before, according to new research by energy data firm Cleanview. Texas led the way on solar and wind and was the runner-up on battery installations after California. Still, fossil fuels remain responsible for more than half of the country’s electricity generation — and the Trump presidency is likely to slow clean energy development this year. Akielly Hu breaks down the whole report for Canary Media here.
Green bank clawback: The new head of the U.S. Environmental Protection Agency wants to claw back $20 billion in federal green bank funding that was meant to help low-income communities build solar arrays, deploy electric school buses, and otherwise implement clean energy. (Canary Media)
Electric truck breakdown: Electric and fuel-cell truck startup Nikola, once valued more than Ford at $30 billion, files for bankruptcy protection after failing to raise money or find a buyer. (CNBC)
Rural clean energy freeze: Farmers across the country are taking a hit from the federal funding freeze as money stops flowing to a program supporting clean energy installations and energy-efficiency upgrades for agricultural and rural businesses. (Associated Press)
Sustainable jet fuel resumes takeoff: The Trump administration finalized a $1.44 billion loan for a sustainable aviation fuel refinery in Montana, a first since it paused all deals made by the Energy Department’s Loan Programs Office under Biden. (Canary Media)
Derailing environmental justice: Advocates call out the Trump administration for shutting down the federal government’s environmental justice departments, saying the decision will“create challenges and impacts that will last well beyond the current administration.” (Inside Climate News)
Cutting carbon in construction: As the federal government drops its commitment to buying lower-carbon building materials, several states are forming coalitions and ramping up their efforts. (Canary Media)
Offshore wind blowback: President Trump’s executive order halting offshore wind permitting could make it difficult or impossible for several Northeastern states to reach their ambitious climate goals. (Washington Post)
Dive deeper: A conservative group that once opposed Dominion Energy’s major Virginia offshore wind farm is now encouraging the project to go ahead, saying that halting it could put ratepayers on the hook for $6 billion already spent. (Canary Media)
Can tariffs clean up steel? A U.S. steel industry advocate cheers Trump’s 25% tariff on imports, saying those imposed during the last Trump administration spurred $20 billion in investment to modernize, decarbonize, and electrify the industry. (E&E News)
The city of Minneapolis is retooling a decade-old partnership with its gas and electric utilities in response to criticism that it hasn’t done enough to help the city reach its climate goals.
The Clean Energy Partnership was established in 2014 as part of the city’s last round of utility franchise agreements with Xcel Energy and CenterPoint Energy. The agreements authorize utilities’ use of public right-of-way, often in exchange for fees or meeting other terms or conditions from the city.
A little over a decade ago, Minneapolis was among the first U.S. cities to view utility franchise agreements as a potential tool to leverage for climate action. Some advocates at the time had been pressuring the city to study creating a municipal utility to accelerate clean energy, and the partnership emerged as a compromise to give the city more say in the utilities’ operations.
Former City Council member Cam Gordon, who represented southeast Minneapolis in 2014 when the council approved the partnership, is one of the critics who say the initiative “never realized its potential.” Instead, it mainly served as “a government relations and promotional PR tool to allow [elected officials] and the utilities to feel like we’re doing something,” he said.
The City Council is set to approve new franchise agreements this week, and they include an updated memorandum of understanding for the Clean Energy Partnership that will require regular reporting on key performance indicators, new utility-specific emission goals, energy conservation, and service reliability in disadvantaged neighborhoods.
Spokespeople for both companies said they welcome the planned changes and that the agreement reflects their interest in working with city leaders on shared clean energy goals.
Since the partnership went into effect in 2015, it has brought together representatives of the utilities, the City Council, and the mayor’s office once per quarter to talk about efforts to reduce emissions in the city. Clean energy advocates and other stakeholders sit on an advisory committee but do not have a formal seat on the partnership’s governing board.
Minneapolis City Council Vice President Aisha Chughtai, who represents the council on the partnership board, expressed frustration about the lack of follow-through from utilities. “Sitting in a meeting and nodding along is one thing. Changing your actions is another,” she said.
By the partnership’s own measures, it has failed to make significant progress on five out of the city’s seven major climate goals. The city is on track with its target to eliminate greenhouse gas emissions from municipal operations but behind pace with its goals related to citywide, residential, commercial, or industrial emissions.
Going forward, the partnership board will continue to meet quarterly, but instead of revolving around city climate goals, each utility will be expected to hit specific targets within Minneapolis’s borders. CenterPoint will commit to reducing emissions from natural gas use by at least 20% by 2035 compared with 2021.
“I think it’s progress,” said council member Katie Cashman, who represents an area west of downtown. The gas utility’s target is “a very meager, insufficient goal, but it is a goal nonetheless, and they haven’t done this in any other city.”
CenterPoint agreed to send a more senior executive to attend the quarterly partnership meetings, though Xcel did not. The utilities also rejected the city’s proposal to hire an outside administrator to manage the partnership.
City leaders believe the new agreement does a better job of setting expectations, but Minneapolis will still lack formal leverage over the utilities if they fail to make progress. The agreement does not contain any penalties for failure to follow through, and the next window to renegotiate isn’t until 2035 when the franchise agreement comes back up for renewal.
Luke Hollenkamp, the city’s sustainability program coordinator, said data reported through the partnership allows the city to make course corrections in its climate work.
“We can see what’s working, what’s not working, and also see where we need to invest more time,” he said.
Xcel Energy’s spokesperson said the partnership has led to successes, noting that citywide emissions from electricity have declined and that Minneapolis met its goal of powering city operations with 100% renewable electricity in 2023 by participating in Xcel’s Renewable*Connect program.
CenterPoint said it has invested nearly $61 million in energy efficiency programs in Minneapolis since 2017, saving residents $25 million in energy costs while reducing 245,000 metric tons of emissions. The utility also developed an on-bill financing program advocated by clean energy activists and others.
Despite the partnership’s imperfections, current and former city officials said it’s better to keep it in place as part of the new franchise agreements than to let it dissolve.
“We’re ramping up our trajectory [to cut emissions],” Cashman said. “We’re setting an example of how other cities can lead on climate action.”
The City Council’s climate and infrastructure committee approved the new agreements on Feb. 6; the full council is set to vote on them Feb. 13.
Clean energy installations in the U.S. reached a record high last year, with the country adding 47% more capacity than in 2023, according to new research by energy data firm Cleanview.
Boosted by tax credits under the Inflation Reduction Act and the plummeting costs of renewable technologies, developers added 48.2 gigawatts of utility-scale solar, wind, and battery storage capacity in 2024. In total, carbon-free sources including nuclear accounted for 95% of new power capacity built in the U.S. last year; solar and batteries alone made up 83%.
The report finds that developers are not only building more projects but bigger ones, too. In 2024, companies built 135 solar, wind, and storage facilities with 100 megawatts or more of capacity, continuing a trend of clean energy megaprojects around the country.
Despite the growth of renewables, fossil fuels — mostly gas — still generated more than half of the U.S.’s electricity last year. Carbon-free sources including nuclear produced just over 40% of power.
This year, renewables will continue growing but at a slower pace, the report says. Based on developer projections, the U.S. could add 60 GW of large-scale clean power capacity in 2025. That would be a 26% jump from the previous year, but it’s only possible if the industry can maintain momentum despite headwinds from the Trump administration.
Solar led the way last year and is expected to do the same this year.
In 2024, the U.S. added a new record of 32.1 GW worth of utility-scale solar capacity. That’s a 65% increase from 2023, when the country added 19.5 GW of utility-scale solar. Most new solar was built in Texas, which added 8.9 GW worth of the clean energy source, followed by Florida, which built 3 GW and outpaced California for the first time. Arkansas, Missouri, and Louisiana each saw rapid growth in solar, adding hundreds of MW of capacity where relatively little existed before.
Developers expect to add 33 GW of utility-scale solar to the grid in 2025, which would represent a 3% year-on-year growth, the report finds. The U.S. Energy Information Administration, meanwhile, said in late January that it expects solar installations to decline to 26 GW this year.
Continued progress for solar — and for any clean energy deployments — will depend heavily on the Trump administration.
President Donald Trump has already stalled clean energy and infrastructure projects nationwide by attempting to halt hundreds of billions of dollars in congressionally authorized funding — a move that experts say is illegal and has been struck down by federal courts. Some Republican members of Congress have also threatened to roll back clean energy tax credits under the Inflation Reduction Act that are key to enduring growth in the renewables sector.
For utility-scale solar, “uncertainty around the Trump administration’s energy agenda and the future of the IRA will cause the segment to stagnate, despite extremely high demand from data centers,” analysts at Wood Mackenzie wrote in January.
The political picture is even more grim for the U.S. wind sector, which has already seen years of declining installations and now faces relentless attacks from Trump.
For several years now, the wind industry has faced challenges including a lack of long-distance transmission lines to transport electricity from far-flung areas in the middle of the country to urban centers. Supply chain woes and inflation have also led to a spate of canceled offshore wind projects in the Northeast.
In 2024, the U.S. added 5.1 GW of utility-scale wind, including its first commercial offshore wind farm, marking a 23% drop from 2023 and the fourth year in a row of falling annual installations. Texas alone accounted for 42% of the country’s new wind capacity in 2024, bringing 2.1 GW online.
Developers expect to add 9.2 GW of wind capacity this year, and 6.1 GW are already under construction or waiting to come online, according to the Cleanview report. If that happens, wind capacity additions would increase by 79% this year.
But that’s a big if. Trump has vowed that “no new windmills” will be built during his presidency and has taken aim at offshore wind in particular — a sector that on paper is set to give wind installations a big boost this year. It remains to be seen whether these under-construction projects will be able to forge ahead as planned despite political headwinds.
Battery storage could be more of a bright spot. Its growth, already fast, is set to accelerate this year.
Last year, the U.S. added 10.9 GW of battery storage capacity, a 65% year-on-year increase that surpassed the previous 56% leap in 2023. California and Texas brought the most grid storage online, building 3,152 MW and 2,832 MW of capacity respectively.
In 2025, storage developers expect to add 18.1 GW of capacity, which would equal a 68% jump from 2024. Based on projections, Texas will overtake California as the nation’s leading energy storage market by adding 7 GW of capacity this year, Cleanview found.
The battery buildout has been propelled in part by declining prices, but even energy storage hasn’t escaped Trump’s assault on renewables. The administration’s tariffs on Chinese imports are expected to negatively impact the industry, which relies on batteries manufactured in China.
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