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After Republicans voted to undo much of the Inflation Reduction Act, a few cleantech professionals set out to exact electoral revenge. So far, it seems to be working.
Last summer, when the Republican-controlled Congress took a wrecking ball to the Inflation Reduction Act, Tom Matzzie was pissed. Though some Republican members of Congress had written letters trying to save wind and solar tax credits, when it came time to vote, they nearly all fell in line behind President Donald Trump. The One Big Beautiful Bill Act passed with widespread Republican support, canceling a decade-long tax incentive meant to accelerate America’s transition to cheaper, cleaner energy.
Politicians have long lived in fear of certain powerful lobbies — the National Rifle Association, Big Oil, Big Pharma — knowing that if they voted against those interest groups it could cost them their seats. But as the votes came down for the OBBBA, nobody in Congress, Matzzie couldn’t help noticing, seemed scared of antagonizing the clean energy industry.
Matzzie, who founded electricity retailer CleanChoice Energy and previously led campaigns for progressive groups and the Democratic National Committee, resolved to try to strengthen clean energy’s political clout by taking down the industry’s most prominent foes seeking elected office.
This strategy attracted the interest of Chris Larsen, a major clean energy investor who made a fortune in cryptocurrency, and Michael Brune, former head of the Sierra Club. Together, Matzzie, Larsen, and Brune formed the Invest in Tomorrow Coalition — a forgettable name that sounds like those of the other shadowy groups blanketing the airwaves during election season, but that happens to share an acronym with the now-defunct investment tax credit for solar installations. As primary season got underway, the super PAC cobbled together commitments for $20 million from Larsen, Matzzie, and other donors to spend on races this election cycle. Their targets: the far-right House Freedom Caucus members who pushed hardest to undo the IRA.
“Are we strong or weak? Are we someone that people can hurt without consequences?” Matzzie said of the clean energy industry.
Freedom Caucus Vice Chair Rep. Ralph Norman of South Carolina got a fresh taste of those consequences last week, when he lost the Republican primary race to replace the late Sen. Lindsey Graham. ITC had hit Norman with $1 million in attack ads accusing him of insufficient loyalty to Trump. The president happened to corroborate the message by enthusiastically endorsing Norman’s opponent, Graham’s sister, Darline, who went on to beat Norman by 5 points.
https://vimeo.com/1218123668?fl=pl&fe=vl
An Invest in Tomorrow Coalition ad against Ralph Norman
In his concession speech, Norman lamented that he couldn’t keep up with the outside spending against him.
“All of our money came from South Carolina and from my personal account,” Norman said. “My opponents, the money came from outside PACs. It’s a fact; I’m not being critical. The PACs that were against, to me, freedom — as Democrats, they got what they wanted.”
ITC got what it wanted in all five Republican races it intervened in this primary season. The results suggest that even a small amount of strategic spending and targeted messaging can have an outsize impact on the foes of clean energy. If Matzzie and his team keep dealing vengeance to their enemies, they could deliver some of the political firepower needed to create more durable pro-renewable policies.
ITC kicked off election season by funding attack ads against Rep. Chip Roy in his May primary runoff for Texas attorney general. The ads did not mention Roy’s antipathy to clean energy subsidies. Instead, they blasted Roy for not being loyal enough to Trump. ITC rigorously tests different messages to find what’s most effective, Matzzie explained: “We’re going to use whatever works.” Roy lost by 10.4%.
Matzzie, jumping into Republican primary races for the first time, found that each dollar spent on them goes a surprisingly long way. Conservative audiences get their news from a relatively small number of ideologically aligned media spaces, which means ITC can buy ads on Fox News, Truth Social, Rumble, and a few others and have a good shot at reaching a lot of motivated Republican voters, at which point it can cater to those voters’ deeply held beliefs rather than challenging them.
After tackling Roy, ITC put out ads supporting the reelection bid of Iowa Rep. Mariannette Miller-Meeks, a pro-renewable Republican running in a primary against an anti-renewable challenger. “Stand with Trump, support MAGA, vote Miller-Meeks,” one of the TV spots declared, alongside photos of the candidate posing with Trump. She won her primary on June 2.
Then, ITC launched its first offensive against Ralph Norman. At that point, he was running in the June 9 primary for South Carolina governor and needed to place in the top two to advance to a runoff. The PAC funded a wave of attack ads against him, and he finished in a distant third.
ITC’s clearest flex thus far has been to take on Tennessee Rep. Andy Ogles, who faced a primary challenge from former state Agriculture Commissioner Charlie Hatcher. Each campaign had spent nearly $600,000; ITC dropped $2 million on a two-pronged strategy to attack Ogles and elevate Hatcher.
The PAC sought to label Ogles as “Lyin’ Andy” by calling attention to instances in which he missed votes in Congress and triggered an FBI investigation over campaign finance irregularities.
At the same time, since incumbent Ogles had much better name recognition, ITC paid for ads to raise Hatcher’s profile and ran tracking polls to test their efficacy. Over three weeks, the portion of Republican primary voters who had never heard of Hatcher fell from around half to one-quarter, Matzzie said.
Despite an endorsement from Trump and an infusion of more than $700,000 from the Freedom Caucus Fund, Ogles lost the August 6 primary by more than 6 points.
The upset proved sufficiently embarrassing that Trump disavowed Ogles in a subsequent Truth Social post, calling him “a person who I remained loyal to even though he had virtually no chance of winning.”
Of course, there’s no way to prove that ITC’s money played a decisive role in these races. The group operates in a noisy political landscape with many variables at play. Ogles, for instance, was reportedly in hot water with voters over Islamophobic and homophobic remarks, per Politico, and needed to reach new voters due to redistricting. Graham had Trump stumping for her in the state, and his PAC funded a barrage of get-out-the-vote texts for her.
Still, each race turned out the way ITC wanted.
As Matzzie sees it, scientifically proving a causal link is beside the point; what matters is that politicians fear the possibility of this happening to them. That narrative gains strength with each candidate who’s knocked out.
It would be hard to find better testimony to the effectiveness of that strategy than the words of the defeated candidates themselves. Norman railed against ITC during his final minutes in the public spotlight as a candidate. Ogles, before he lost, called out the group during a radio interview: “They literally are trying to make an example out of me to try to strike fear in other Republicans. Which is why, if they prevail, this will have a chilling effect to the conservatives in Congress.”
Even if politicians think they can survive an assault from a scrappy team of clean energy enthusiasts, the PAC’s interventions increase the cost of running a campaign, pushing candidates to raise more money to counter the spending. “If you make enemies, your next election will be more expensive for you,” Matzzie said.
ITC hopes to keep raising money to spend up to $30 million in this cycle, he said. The PAC is now targeting its first Democratic primary, attacking Rhode Island Gov. Dan McKee for scapegoating clean energy as the cause of the state’s affordability problems. McKee was trailing his challenger in an Emerson College poll released last week.
The general election season will draw a much broader electorate than the races ITC has participated in so far. Matzzie declined to comment in detail on what the PAC’s general election strategy will be.
ITC’s efforts may have delivered a visceral satisfaction to clean energy pros chafing from last year’s defeats, but these actions aren’t likely to yield a more renewable-friendly Congress. Two of the candidates it attacked — Norman and Roy — were running for offices outside of Congress. Hatcher was never a champion of wind and solar. Some Republicans may think twice before loudly attacking the clean energy industry in the future, but that doesn’t mean they’re more likely to sign legislation that’s good for the industry.
Meanwhile, the major clean energy trade groups are not exactly embracing the PAC’s approach.
“We’re in the business of making more friends, not more enemies,” Tim Pawlenty, president and CEO of the Solar Energy Industries Association, said in an email. (Matzzie, for his part, allowed that the trade group has “to stay friends with everybody so they can walk into every office.”)
Another clean energy leader, cleantech executive and investor Steve McBee, sees ITC’s work on “enforcing accountability” as a valuable effort in a broader campaign to expand clean energy’s political power, even as he himself focuses on coalition building.
In May, McBee launched Amped, an effort to mobilize clean energy professionals and executives to engage more in public discourse, in order to build sustainable bipartisan support for their industry.
Though solar, wind, and batteries have taken over the power sector, representing an estimated 93% of all new power plant capacity getting built this year, the industry doesn’t yet wield the political power to match that success.
“We don’t show up with any swagger,” McBee said. “We continue to call ourselves ‘alternative.’ … We find ourselves a bit outside the cultural zeitgeist, and that’s not a good place to be.”
McBee believes that the IRA was a “beautifully designed piece of legislation,” but that not enough work was done to tell voters and their representatives about the jobs and economic opportunities flowing to their districts. He wants to spur energy professionals to flood the political arena with the degree of money and effort that the fossil fuel industry has invested over the decades — but without the “lying and distortion.”
“The good news is, as an industry, we have all the facts on our side,” McBee said. “We just have to prosecute the case.”
Since starting Amped, McBee said he has received hundreds of inbound messages from people who want to help the industry put up more of a fight, noting the “organic unstructured energy that can be harnessed.”
That’s a bigger project than the upcoming midterms: to turn the IRA defeat into a political awakening for the clean energy sector.
As an anchor tenant for several off-site arrays in development, the center will help spur investment and educate residents on the benefits of shared solar.
The Obama Presidential Center, which opened on Chicago’s South Side in June, features a museum full of mementos to democracy and the famous family, native prairie landscaping, an indoor basketball court, and other amenities. It will also be powered entirely by clean energy. Solar panels sit on the roof and on a garden pavilion, and a geothermal system heats and cools the complex. But the bulk of its power will be produced by community solar — the center will pay a set “subscription” fee to arrays located off-site.
The Obama Presidential Center will be the anchor tenant for several community solar projects that the Chicago-based company Reactivate is in the process of developing, slated to go online in 2027. Reliable anchor tenants are crucial to the success of community solar: They pay for large amounts — often 40% to 50% — of a project’s output, and can be key to persuading banks or other lenders to help finance a community solar array. The center’s subscription will cover about 6 gigawatt-hours of solar power annually, enough, along with its rooftop panels, for the entire campus.
The Obama Foundation, which runs the center, says community solar is a way to make clean energy accessible to renters, residents in multifamily housing, and those who aren’t able to afford or install solar panels on their own properties. That includes many people who live on Chicago’s South Side, where Obama cut his teeth as a community organizer decades ago.
Community solar delivers significant bill savings to households, especially in Illinois, where a state program guarantees robust benefits to low-income participants.
But in order to reap these savings, residents need to sign up. And too few of the people in marginalized neighborhoods who could benefit most do so, many solar advocates say.
Obama Foundation CEO Valerie Jarrett and Reactivate CEO Utopia Hill hope the Obama Presidential Center’s foray into community solar will raise awareness of, and trust in, the model so that it can help more residents struggling with their energy bills on the South Side and beyond.
They also expect the Obama Presidential Center will set an example for other mission-driven nonprofit organizations and companies to become anchor tenants.
“The foundation sought to use its buying power to catalyze the development of new renewable-energy generation sources,” Jarrett said.
“It is the foundation’s hope that this partnership with Reactivate will encourage other equity-focused organizations to consider community solar as a cost-effective way of procuring renewable energy.”
While Reactivate and other community solar developers in Illinois have signed up thousands of subscribers for their projects, they agree that people are often skeptical of the concept — especially in low-income and Black communities that have sometimes been targeted by predatory lenders and other unscrupulous businesses. Illinois lawmakers and consumer watchdogs, for example, have long struggled to rein in retail electric suppliers that offer residents energy plans under terms that end up being exploitative.
Hill, who grew up in a working-class Chicago suburb, said that people often respond to an offer of guaranteed savings with “What’s the catch?”
“There is no catch. It’s just an opportunity,” Hill said. “Having a well-established name [with the Obama Presidential Center] will hopefully help people understand that community solar is a real program that will provide savings.”
A series of Illinois state clean energy laws created robust incentives for community solar development, with particularly generous support for low-income residents and those in environmental justice communities, who are guaranteed savings equal to at least half of the value of the energy generated from their solar subscription.
The program has spurred the installation of community solar arrays located in and serving communities like Waukegan in northern Illinois, a heavily industrial area where community solar built on a landfill provides clean energy and savings to about 1,000 households and the local school district.
A community solar project developed by Reactivate — which focuses on marginalized and underserved communities — in a Chicago suburb provided a total of $186,000 in savings last year to its 650 subscribers, 44% of whom earn less than $20,000 a year.
Mercy Housing, a national nonprofit affordable housing developer, is the anchor tenant for two Reactivate community solar projects that went online in 2024.
The benefits go to two Chicago-area Mercy buildings, with 96 and 65 living units. Mercy Housing senior environmental analyst Max Stewart said they’ve seen significant savings on energy bills, money that can be reinvested into energy efficiency or resident services, and help keep affordable housing projects sustainable. He noted that it can be hard to find organizations willing to make such a big commitment to community solar.
The opportunities available to anchor tenants should get “more awareness,” Stewart said. “It always helps to have someone leading the way.”
Interior is using tax dollars to pay firms to ditch offshore wind leases and invest in fossil fuels instead. California just became the eighth state to sue to stop it.
The Trump administration has agreed to fork over nearly $4 billion since the spring to get major energy firms to abandon a dozen leases for U.S. offshore wind projects.
The controversial maneuver to return lease payments to developers — often in exchange for their investing in fossil fuels — is part of President Donald Trump’s broader strategy to stymie the clean energy resource, which coastal states have been depending on to meet their growing need for reliable and affordable electricity. The buyouts began as Trump’s earlier efforts to halt in-progress offshore wind farms largely failed under scrutiny from federal judges.
Now the unprecedented lease-refund approach is increasingly facing legal blowback of its own. Late last week, California became the eighth state to challenge the practice, arguing that it jeopardizes the state’s investments and resulting jobs in offshore wind.
The U.S. offshore wind industry had already been struggling before Trump began issuing stop-work orders, freezing permitting, and rolling back tax credits. High inflation, rising interest rates, and supply-chain constraints in recent years threatened to derail a handful of projects along America’s coastlines.
That’s why it’s all the more bizarre that the federal government is proactively paying developers to walk away from beleaguered, undeveloped projects, James Sallee, a business professor at the University of California, Berkeley, recently argued in the Energy Institute Blog. He likened the buyouts to spending billions in taxpayer dollars “to shoot a corpse.”
But for states that were banking on gigawatts of offshore wind power to shore up their grids and hoping the industry could rebound after Trump leaves office in 2029, the agreements are like salt in their wounds — particularly given the deals’ legally questionable nature. Here’s the latest on states’ legal challenges and congressional pushback.
California’s new lawsuit focuses on the agreement between the U.S. Department of the Interior and the company Golden State Wind, which paid $120 million in 2022 to lease waters along California’s Central Coast through a competitive bidding process.
Golden State Wind had planned to develop a 2-gigawatt offshore wind farm using floating turbine technologies in a large swath near Morro Bay. The company is owned by Ocean Winds North America — a joint venture of the European firms Engie and EDP Renewables — and the U.K. offshore wind developer Reventus Power.
In late April, Interior said it would return the $120 million to Golden State Wind. In exchange, the developer agreed to invest the same amount of money in U.S. liquified natural gas facilities and other fossil-fuel projects. Ocean Winds also struck a similar deal that month to get back the $765 million it paid to lease water for Bluepoint Wind, a fixed-bottom project near New York and New Jersey.
California’s challenge — filed by state Attorney General Rob Bonta (D) and the California Energy Commission — asks a federal court to strike down the agreement with Golden State Wind, saying the deal is “blatantly unlawful.”
Offshore wind experts and former Interior officials have previously questioned whether Interior’s Bureau of Ocean Energy Management has the legal authority to return the funds it collects from leasing federally controlled waters. They noted that when oil major Royal Dutch Shell relinquished its offshore leases near Alaska in 2022, the company simply ate the $2.1 billion loss.
California raises the same concerns in its lawsuit and claims Interior improperly tapped the federal Judgment Fund, which Congress intended to be used to settle lawsuits, not to pay for voluntary agreements like this one.
“Offshore wind presents an opportunity for our state to scale up an innovative new clean energy industry that reduces pollution while providing new jobs and investment for the people of our state,” David Hochschild, chair of the California Energy Commission, said in an Aug. 28 news release. “We will not let the Trump administration’s reckless actions turn back the clock.”
Interior has separately moved to cancel and refund two other offshore wind leases in California, with the developers Invenergy and RWE, though neither were named in the lawsuit.
In announcing the legal challenge last week, California Attorney General Bonta accused the Trump administration of using the buyouts to “line the pockets of their Big Oil donors.”
A day earlier, The Washington Post broke the news that another offshore-wind deal with German energy firm RWE will generate a giant payday for one of Trump’s neighbors near Mar-a-Lago.
In early August, Interior agreed to hand over $1.22 billion to RWE to give up its leases off the coasts of California, Louisiana, and New York. As part of the deal, RWE said it would spend $900 million on a stake in a huge Louisiana liquefied natural gas terminal — a stake it’s buying from a private equity fund run by Michael Dorrell, one of Trump’s million-dollar donors, who owns a mansion near the president’s Florida estate.
The administration told the newspaper that it had no involvement in the decision to pick the Louisiana gas project, and RWE said it made its investment plans independently. But for critics of the lease agreements, the revelation only solidified their suspicions. California Rep. Jared Huffman, the top Democrat on the House Natural Resources Committee, said he would expand an ongoing probe of the deals to include the ties to Dorrell’s firm.
“In writing and to their faces when I meet with these energy company CEOs, I am telling them, ‘You better tell your shareholders we are coming for that money,’” he told The Washington Post. “I would not even cash the check.”
As the legal fight heats up in California, an ongoing challenge on the East Coast continues to play out in court.
Earlier this summer, New York and six other Democratic-led states sued Interior over its $795 million agreement with the French energy giant TotalEnergies. In March, the company became the first developer to reach such an arrangement with the government — creating a “blueprint” for other offshore wind leaseholders to follow, according to the lawsuit.
Under the deal, TotalEnergies agreed to forfeit its lease for a large area near New York and New Jersey, where it had aimed to develop over 3 GW of offshore wind power to provide clean electricity for more than a million homes across the two states. Five New England states were also slated to benefit from the wind farm, since they regularly import energy from New York.
In exchange for ditching the project, Interior said it would “reimburse” the developer for the $795 million it paid in a 2022 auction, funds that TotalEnergies promised to invest in fossil fuel projects. At the same time, the company signed a similar, separate deal to cancel the $133 million lease for its planned 1-GW Carolina Long Bay project near North Carolina.
Similar to California, the seven East Coast states argued the New York–New Jersey lease cancellation was “arbitrary and capricious,” since the administration didn’t follow proper procedures or provide a clear reason for striking the agreement, along with violating the Judgment Fund Act. The challenge is still moving through the early procedural stages in a D.C. federal court.
While the eastern states are hoping for a much larger expansion of offshore wind, the few projects they do have are already benefiting the region’s grid — including during recent heat waves and brutal cold snaps. Even with the Trump administration’s attacks, at least a few more gigawatts are slated to come online in the coming years.
Some city residents went two weeks without power following storms. The federal program, ended by Trump, would have enabled many to access solar and batteries.
Stephen Mays was left without power for 12 days after violent storms and tornadoes struck northwest Indiana this month. Lori Latham for 13. Thousands of other residents of Gary, Indiana, where both Mays and Latham live and work, went without power for as long as two full weeks following the storms, in what has become one of the longest power outages in modern U.S. history.
Mays, an insurance agent and president of the NAACP chapter in Gary, scrambled to serve clients who had trees fall on their roofs or smashed-out windows. Latham, a member of the Gary City Council, also struggled to care for her constituents and her family — including her kids and 91-year-old father.
“We were without refrigeration, without lights, leading a community that was suffering collectively,” Latham recalled. “Many of the homes were underinsured or uninsured, many people in the community had underlying health issues. Trying to get through that was extremely difficult.”
Mays and Latham agree that things could have been easier with a simple solution: solar panels and batteries spread throughout Gary, which could have allowed people to charge their phones and computers, chill their food and medicine, operate their medical devices, and simply turn on the lights while they dealt with all the other damage and turmoil.
Just last year, Mays and Latham were among a group of city officials and other community leaders working to bring that exact vision to life. They aimed to use federal funding to outfit Gary with hundreds of rooftop solar arrays, battery storage, community solar, and microgrids. Plans also called for at least one resiliency hub at a downtown community center, where people could come for power and support.
The effort was put on hold when President Donald Trump canceled the federal Solar for All program last August. EPA Administrator Lee Zeldin called the larger program it was a part of a “boondoggle.”
Indiana had been awarded a total of $117 million for solar, battery, and microgrid installations for marginalized communities under the program, which was created by the Inflation Reduction Act. Tens of millions of those dollars had been earmarked to pay for the Gary projects, which would have also brought 100 jobs to the once-thriving industrial city now notorious for disinvestment.
The cancellation filled Latham with a deep sense of grief, one that had been building as she watched environmental justice and equity initiatives get eliminated one after another following the start of Trump’s second term.
The Solar for All funds granted to Indiana were administered by the nonprofit Indiana Community Action Association and doled out to seven subrecipients, including the cities of Gary, Fort Wayne, and Indianapolis and multiple nonprofits.
Denise Abdul-Rahman, founder and CEO of the nonprofit Black Sun Light Sustainability, said the organization was awarded almost $30 million to deploy 200 residential solar plus storage systems, 50 resiliency hubs with energy storage, and five community solar arrays statewide.
One of the community solar projects and about a dozen residential systems were planned for Gary, where poverty, crumbling infrastructure, unstable housing stock, and high rates of health problems exacerbate the damage and danger caused by power outages.
“If they had received those resources, being a year later now, how much resiliency could have been deployed?” Abdul-Rahman asked. “Lives are at stake, people’s health is at stake. There could have been a lot of economic benefits and work created.”
The main focus of Indiana’s Solar for All funding was not just promoting resilience but bringing down energy costs — a particularly acute problem in Gary.
“When the power went out, that made things difficult. But also keeping the power on for many people in my community is equally if not more difficult with NIPSCO’s rate increases,” Latham said, referring to the utility that serves northwest Indiana.
Gary residents bear a steep energy burden, and electric rates for a typical household rose by around $83 a month between 2023 and 2025, according to NIPSCO.
Solar for All would have given lower-income households in Gary the opportunity to reduce their bills with clean energy, at no out-of-pocket cost.
Though the plan for Gary involved installing batteries and the construction of resilience hubs, many of the planned projects would have been solar alone — no storage. But the prolonged power outage, which affected not only Gary but more than 300,000 other customers across the region, has now driven home the value of storage systems.
“Before all this, there was a lot of skepticism that battery systems were needed, since we’re not in a hurricane area,” said Alison Becker, program director for the Indiana Community Action Association. “This showed we need to be resilient for whenever these events occur.”
The Aug. 11 storms were not an isolated event; Indiana has now seen 84 tornadoes in 2026, breaking the annual record of 72 set in 2014, not to mention the derechos, floods, and other storms that have battered the state in recent months.
“Obviously, the climate is not going to get any better,” Mays said. “Northwest Indiana is now a new Kansas” — a state infamous for tornadoes.
But without Solar for All or similar incentives, the upfront cost of solar-plus-storage can be cost-prohibitive for low- and moderate-income families — especially in a city like Gary, where the median household income is $38,700.
Black Sun Light Sustainability is among eight plaintiffs that sued the U.S. EPA last fall over the cancellation of Solar for All. No ruling has been made yet, but Abdul-Rahman is hopeful that the court or, longer term, a change in federal administration could restore funding for the program. She and other leaders also say they wish the state would step in to fund solar for underserved communities, as Illinois has done with its own state Solar for All program.
“Indiana has a rainy day fund. I hear it’s really huge,” she said — in fact, the fund holds $1.14 billion. “They could easily fund Solar for All.”
The restoration of the funding, whether at the federal or the state level, would let work resume on projects that would be “transformational” for Gary, according to Latham.
“After the storm, our neighbors learned to lean on each other in a way that came quite naturally,” she said. “How much more could we have done if there had been investments [from Solar for All] and those commitments had been kept?”
Teaming up to buy solar can get residents deep discounts. Virginia is the first to try a statewide campaign as utility bills rise and data centers stress the grid.
Last month, Virginia became the first state in the country to launch a bulk-purchasing campaign for rooftop solar — a move that promises to bring down the cost of installing panels for households across Old Dominion.
The idea behind the program, called Switch Together, is simple: Solar panels come cheaper by the dozen. Trusted solar installers can pool demand to purchase equipment in bulk and pass the discounts on to participants.
Solar United Neighbors, the nonprofit running the initiative, has for years used this model on a local scale in communities around the U.S. But it’s now expanding statewide in Virginia at the urging of the office of Gov. Abigail Spanberger, a Democrat, who is looking for ways to lower energy bills as utilities jack up rates in the world’s data center capital. Rooftop solar both slashes power costs for homes that install it and can drive down expenses for utility customers at large.
“If more people go solar, that’s less strain on the grid, and there’s less need to build costly infrastructure that the entire rate base would actually pay for,” said Brandon Praileau, SUN’s Virginia program director, who joined the group in 2023 after rooftop solar helped his church in Norfolk cut utility bills by a quarter.
The state is not providing any funding for Switch Together, though its partnership promises to amplify the reach of the bulk-purchasing effort, which is focused on solar but also offers residents access to cheaper home batteries, EV chargers, and, in some locations, heat pumps.
Since Spanberger announced the initiative in July, more than 4,300 residents, small businesses, and nonprofits have put their names down to receive more details, and 120 have signed contracts, according to SUN.
The campaign is set to end Oct. 15. By the time the bulk-purchasing drive is over, Praileau expects those figures will swell to 5,000 requests for info and about 500 signed contracts. “We’re talking about a utility-scale amount of solar with those numbers,” he said. “Almost 4 megawatts.”
The rooftop panels are expected to cut $2,200 off the average annual utility bill. Exactly how much households save on installation varies across the state, but it ranges from 20% to 30% off — vital discounts after the Trump administration and Republicans in Congress killed the 30% federal tax credit for households investing in renewable energy.
Over the years, SUN has backed a variety of bulk-purchase models, including recruiting potential participants on its own. But lately, SUN’s secret sauce involves a partnership with local governments, whose seal of approval lends credibility and whose outreach encourages more would-be solar owners.
In Richmond, for instance, a SUN-only campaign resulted in about 20 new solar rooftops. A second push for bulk sign-ups that included mailers from the local government led to about three times as many households adding rooftop panels.
“That level of direct marketing has proved to be the whole difference-maker,” Praileau said.
The success of SUN’s efforts in the D.C. metro area, which includes northern Virginia, drew the attention of Josephus Allmond, a longtime environmental lawyer in the state who now serves as Spanberger’s chief energy officer. “We thought we could drive deeper savings if we opened up the whole state,” Allmond said at an event in Charlottesville last month. “So that’s what we did.”
While the governor’s endorsement is crucial, the expansion is easier said than done: Finding enough trusted rooftop solar companies in every nook and cranny of the state is one limiting factor. For now, only “extreme southwest Virginia” is left out of the campaign that spans 100 counties and cities, Praileau said, since SUN couldn’t vet installers there in time for this year’s rollout. But he believes that will change by next year, when Switch Together hopes to conduct another drive in partnership with the state.
Helping residents go solar through bulk purchasing is just one piece of SUN’s mission; the group also works to bring solar owners together to fight for clean energy policies. That’s part of why Praileau is encouraged by the breadth of sign-ups.
“We’re seeing interest across the entire commonwealth, from places where you would not expect people to be looking for solar,” he said, such as the politically conservative Shenandoah Valley and the New River Valley. “That wide spectrum just goes to show how interested Virginians are at lowering their energy costs.”
While Virginia is unique in some ways, plenty of other states face similar challenges of rising electricity costs and crushing demand from data centers. They, too, could roll out voluntary bulk-purchasing efforts.
“We’re definitely taking note of what works best, of best practices, so that we can offer a road map for others to be able to duplicate networks like this,” Praileau said. “I think this is ultimately a model for any state.”
Analysts are trying to measure the damage President Trump has done to the energy transition so far — and determine where federal climate policy should go from here.
Glass half-empty or glass half-full?
The classic question is now gripping the policy wonks who are trying to measure the damage President Donald Trump has inflicted on the U.S. energy transition — and to figure out what direction to take climate policy from here.
In July, the MIT Center for Energy and Environmental Policy Research released a report arguing that, when it comes to cutting emissions from the electricity sector, the glass remains half full despite Trump’s policies. Report author Lily Bermel found that U.S. power sector emissions are still on track to decline substantially by 2035.
Other analysts and energy modelers are more pessimistic. Amanda Levin of the Natural Resources Defense Council published a rebuttal in Heatmap this week, highlighting a recent peer-reviewed study and modeling from Energy Innovation that finds the U.S. will achieve less than half of the emissions reductions it would have under Biden-era policies. (To be clear: Those are economywide figures, while Bermel is focused on the power sector.)
Let’s state the obvious: No one really knows how full or empty the glass is. The factors that will make or break the next decade of the energy transition are incredibly hard to model.
Right now, clean energy is booming. Yes, Trump eliminated tax credits for wind and solar, but lots of projects were able to grandfather in their incentives so long as they finish construction in four years. Most modelers expect clean-energy deployment to look pretty healthy until 2030, though it’s possible Trump’s persistent efforts to stymie permitting for solar and especially wind will lead to more cancellations.
But after 2030, as Canary Media’s Julian Spector put it in a July article on the Rhodium Group’s analysis of this question, all bets are off.
The range of possibilities in Rhodium’s report is astonishing: In the most optimistic of its three scenarios, the U.S. continues building clean power at the blazing speed of roughly 53 gigawatts per year from 2030 to 2040. In the most pessimistic scenario, in which Rhodium assumes lower natural gas prices and higher clean energy costs, renewable additions drop to an average of just 3 GW per year. There’s also the wild card of data centers, which are driving big but uncertain demand for new gas power plants.
The early 2030s are the hinge years. And their outcomes depend on a medley of unknowable future market forces — and on the results of the 2028 U.S. presidential election.
That brings us to the second leg of this debate: Given where the energy transition is at, what should Democrats do if they regain power in 2029?
Bermel argues that the Dems should forget about reinstating the tax credits for mature wind and solar tech. In her view, it’s time to move on and prioritize permitting reform as well as efforts to boost earlier-stage “clean firm” tech like geothermal and advanced nuclear.
Levin at NRDC agrees that permitting reform should be a priority. But she makes the case that wind and solar tax credits are still important because they guarantee that these carbon-free technologies will beat fossil fuels — namely gas — on price. Plus, tax credits mean utility customers pay less for large-scale clean energy projects, which is crucial as bills rise and Trump’s policies make renewables more expensive.
That last point about affordability has been echoed by some in the industry. Kevin Smith, CEO of the clean energy developer Cypress Creek Renewables, made a similar case during a recent conference. “We can compete without tax credits right now,” he said of clean energy companies. “The issue is affordability. And I think the Democrats will start pushing tax credits as an affordability issue, and they may have a point.”
Tesla’s solar roof shingles are officially toast
Nearly a decade ago, Elon Musk borrowed the set of “Desperate Housewives” to show off Tesla’s newest product: solar-generating tiles that cover a rooftop like shingles. Tesla would be putting the solar tiles on 1,000 roofs a week by 2020, Musk predicted at the time. But by the time 2022 rolled around, Tesla had only installed about 3,000 solar roofs, and the tiles only made up 0.17% of residential solar capacity installed in the U.S. that year.
Now, as Julian Spector and Dan McCarthy report, Tesla is discontinuing its solar shingles, and will instead double down on traditional solar panels. The company recently announced plans to build a $10.1 billion solar cell factory in Texas that it says will be able to churn out 100 GW of integrated solar panels each year.
That would be a huge deal — if it happens. Altogether, every solar factory in the U.S. can only make a combined 65 GW of panels each year, so Tesla would have to take its manufacturing capacity through the roof to make that happen.
Clean energy is on track for a war-spurred milestone
Despite stagnant investment, renewables are still on track to hit a global milestone in 2026.
According to a fresh BloombergNEF analysis, the world invested about $327.5 billion into solar, wind, and other renewable energy sources in the first six months of 2026 — about the same amount as in the second half of 2025. Investment in standalone utility-scale solar power actually shrank to its lowest level in years, but investment in solar-plus-storage hit a record of more than $25 billion, while residential solar investment also skyrocketed.
While coal power generation has rebounded this year amid oil and gas shortages spurred by the war in Iran, clean power sources are expected to produce more electricity than coal for the first time ever this year, the International Energy Agency estimates — and surging demand for rooftop solar is a big reason why.
Trump’s electrical blackout: President Donald Trump bans the “acquisition, importation, transfer, or installation” of foreign-made bulk-power electrical equipment from certain countries, though the DOE will first have to determine targeted equipment’s risk before the order can bar their import. (Project Finance)
The Army goes nuclear: The U.S. Army plans to award up to $2.2 billion to five companies to build small nuclear reactors at military bases around the country, with Antares Nuclear, General Atomics, and Westinghouse among the awardees. (New York Times, Axios)
Canada fights back: Ontario Premier Doug Ford threatens to slow or halt power exports to the U.S. in response to the Trump administration’s new tariffs on a range of Canadian goods. (Utility Dive)
Data-center gas-plant update: Around 189 gigawatts of natural gas capacity to power data centers has been announced, entered pre-construction, or started being built, up from 97 GW at the end of last year. (Heatmap, Global Energy Monitor)
Wind’s Maine event: After nearly two decades spent trying to build utility-scale wind power in its far northern reaches, Maine has finally approved an 800-MW array and a 1.2-GW transmission line that will be built near the Canadian border. (Canary Media)
Not-so-public comment: The U.S. EPA looks to eliminate a federal requirement that states seek public input on applications for air pollution permits for data centers and other industrial facilities. (New York Times)
Solar saves Europe’s summer: Europe has seen record heat and drought this year that has jeopardized power production from nuclear, fossil fuel, and wind sources, but solar performed better than normal and helped keep ACs running amid sky-high temperatures. (Grist)
Hot water and low river levels have hampered nuclear power in Europe this summer, forcing a reckoning over plant preparedness.
Europe’s increasingly hot summers come with a worrying trend. The air conditioning that the continent long eschewed as an American indulgence is becoming a necessity, and some of the nuclear reactors needed to run those cooling units are tapping out right as thermometers spike. This summer was especially bad: The series of extreme heat waves that roasted Europe, killing thousands and fueling historic wildfires, also severely impacted the rivers that provide water to cool thermal power plants such as nuclear stations.
In France and Switzerland, nuclear plants went offline as river temperatures rose, to prevent the discharge of warm water into sensitive aquatic ecosystems. In Romania, Hungary, and Bulgaria, nuclear plants built along the Danube River either shut down or reduced output as drought dropped the water levels below intake pumps.
Critics of nuclear power have seized on the moment to challenge whether nuclear energy is as reliable and efficient as its supporters claim.
“Strange that anyone would support new nuclear, which depends on cooling, in the face of an ongoing superlinear global temperature rise,” Mark Z. Jacobson, a Stanford University professor who has long advocated for replacing atomic energy with renewables such as wind, solar, and hydropower, wrote in a post on X after France took 6.3 gigawatts of nuclear plants offline amid the heat wave.
At the heart of the issue is the large supply of water that nuclear plants need to cool their reactors. The problem is most acute in Europe, where many plants rely on rivers — unlike in Asia, where most stations are built near the ocean, or in North America, where reactors more often have cooling towers that help avoid problems with overheated water supplies. Experts say that Europe’s situation has more to do with how its individual plants are engineered and that the flaws are fixable.
“There are multiple solutions to this,” said Madison Hilly, managing director of the nuclear consultancy Radiant Energy Group. But “if you don’t like nuclear, this is the annual occurrence that basically allows you to try … and say, ‘No, actually nuclear is not reliable and it can’t be built for a changing climate.’”
The climate challenge for Europe’s nuclear plants is twofold. First, above-average river temperatures trigger environmental regulations barring the release of water that’s too warm. Second, drought conditions mean that the water levels are too low for the plants’ intake pumps to work. Along the Danube, the intake pumps that pull cooling water into the plant weren’t constructed to handle the low water levels reached this summer. When these plants were designed and built between the 1970s and 1990s, “there was no awareness of the dramatic changes in river flow rates and temperatures that we are witnessing now,” said Jacopo Buongiorno, the director of science and technology at the Massachusetts Institute of Technology’s Nuclear Reactor Laboratory.
Still, he said, “moving the intake is technically feasible, albeit expensive.”
“One has to put things in perspective. Even a severe heat wave like the one experienced by Europe this summer reduces the average capacity factor of these plants by only a few percent on an annual basis,” Buongiorno said. “And while all the attention goes to a handful of struggling facilities located on problematic rivers, the vast majority of nuclear power plants go through the summer heat without any issue. Nuclear plants remain the most reliable power generators on the planet.”
The most obvious solution to water levels dropping below the intake pump is, as Buongiorno described, to lower the equipment. It’s difficult to say exactly how much that would cost, since the renovation of the relevant components would amount to a bespoke engineering project.
But virtually every structure at a nuclear plant is expensive, and renovating part of an existing plant typically costs more than building that section from the ground up. Case in point: Most nuclear plants in the U.S. and Asia were built with cooling towers, the hyperboloid structures that are often the most visible component of a nuclear plant and which prevent the discharge of too-hot water. The towers also allow a plant to recirculate and reuse water in a closed-loop cycle. In 2009, a study that Tetra Tech prepared for California’s Ocean Protection Council found that adding a cooling tower to a built plant would cost about $87 million. Accounting for inflation, that would be roughly $135 million today. Such renovations also take years.
The recent disruptions “call for an upgrade in Europe’s nuclear preparedness for extreme climate events that sadly are now a new norm,” said Adam Błażowski, the Poland-based chair of the pro-nuclear climate group WePlanet.
As a short-term solution to the water-level problem, the Hungarian government sank two barges near the Paks nuclear power station, Hungary’s only such plant, to artificially hike the river levels enough to keep water flowing into the plant’s two units.
While “numerous ideas and technical solutions for securing the cooling water needed for operation have appeared in the press and on social media,” cautioned the HUN-REN Centre for Energy Research, a government laboratory for studying nuclear and renewable energy, “reaching a final, well-founded decision requires the professional evaluation of nuclear safety and electricity generation alongside a number of other considerations — navigation, water and agricultural management, flood protection, and so on.”
“However tempting these proposals may seem from the standpoint of security of supply, economic efficiency — and, should the water level later rise on a sustained basis, the restart of the other units — they conflict with the fundamental principles of nuclear safety and are therefore unacceptable under any circumstances,” the organization said in the statement.
Still, the HUN-REN Centre noted, the problems with specific nuclear plants in France, Romania, and Hungary shouldn’t detract from the critical role nuclear has played in keeping the lights on across the region.
“In these very days, avoiding a collapse of the electricity system owes much to the nuclear power plants operating in the Czech Republic and Slovakia — which are almost entirely identical to Paks NPP but use cooling towers instead of fresh water cooling,” the HUN-REN Centre said. “This also demonstrates that nuclear power plants with different cooling solutions respond differently to extreme hydrological conditions.”
For proof that nuclear plants can be designed to operate in extreme heat and drought, simply look to Arizona.
The three-reactor Palo Verde nuclear plant provides more than one-quarter of Arizona’s electricity. Perennially drought afflicted, the Copper State — now facing fresh cuts to its allotment from the Colorado River under the Trump administration’s plan to ration the region’s dwindling freshwater source — built the plant to run on recycled wastewater from Phoenix, 50 miles away. It could serve as a model for future plants.
“Palo Verde uses recycled water from the city of Phoenix, so it’s pretty much self-sustaining. It’s also an example of brilliant engineering,” Buongiorno said. “They managed to build and successfully operate a three-reactor nuclear power plant in the middle of the desert, without becoming a burden on the city water supplies.”
For next-gen geothermal to scale, drilling costs must drop. Startup Hephae says its novel tech can make that happen — and developers like Fervo are giving it a try.
Thousands of feet beneath the desert valley of southwest Utah, a slender tool tucked inside a drill pipe is barreling through hot granite. The rod-shaped device, built by the startup Hephae Energy Technology, is a tracker of sorts, wirelessly sending data to help operators above steer the drill below and to measure rock conditions.
The work is underway at Fervo Energy’s Cape Station, the largest project in the nation using nascent techniques to tap earth’s heat for clean energy. The 500-megawatt endeavor could usher in an era of next-generation geothermal development — but only if the industry can bring down drilling costs.
That’s where tools like Hephae’s can help.
Oil and gas firms have long used similar “measurement-while-drilling systems” to bore holes underground. But off-the-shelf parts aren’t designed to withstand the higher rock temperatures that geothermal companies aim to reach, which makes the equipment less efficient and costlier to operate.
Hephae’s founders, veterans of the fossil fuel industry, saw an opportunity to create a more advanced version for the burgeoning next-gen geothermal market. “We realized that companies like Fervo need the same exact tools that we’ve been working on for the last 45 years,” Steve Krase, Hephae’s CEO, recently recalled.
“They just need to work a hell of a lot hotter,” he added.
Hephae deployed its high-temperature device for the first time commercially at Cape Station earlier this year and has since used it there it additional times, Krase said. His firm will soon ship another of its high-tech rods to the startup Mazama Energy, which has started drilling its commercial pilot facility near the Newberry Volcano in central Oregon.
These and other next-generation geothermal projects are poised to become a significant source of on-demand electricity in the western U.S. over the coming decades. Unlike traditional geothermal plants, the newer systems don’t rely on finding natural hot-water pockets to generate heat; they can go wherever rocks are sufficiently scalding.
Yet the fledgling sector will struggle to scale unless companies dramatically reduce the time and money it takes to drill new wells — each of which can require millions of dollars, and together represent as much as half the expense of building new geothermal plants.
“Any way that you can get geothermal to be [cost] competitive with other sources of energy, like nuclear, solar, and wind, … will be pretty crucial,” said Zainab Gilani, an energy and power research associate at Cleantech Group, a consulting firm.
Houston-based Hephae is among a growing number of drilling-focused firms working to reach that goal. The company — whose name evokes the ancient Greek god of fire, Hephaestus — raised nearly $18 million in venture capital funding in July to build more tools to rent to geothermal developers.
All told, seven startups have secured $393 million in total venture investment since 2021 to develop cutting-edge drilling systems and components for geothermal power, according to Cleantech Group. That includes Quaise Energy’s recent $134 million fundraise to advance its rock-melting technology and build its first geothermal plant, also near Oregon’s Newberry Volcano.
Geothermal firms “are basically trying to get underground as cheaply as possible,” said Stephanie Díaz, a senior associate for technology and innovation at BloombergNEF. She said the pursuit is a “rising tide that lifts all boats,” given how innovation spreads.
Investors are backing firms along the supply chain as a way to get exposure to the geothermal market, but without taking on the risk of building a first-of-a-kind project. “Instead of having to figure out an entire power plant, you just need to figure out one component that is essential to creating the power plant,” Díaz said.
Krase and his co-founder, John Clegg, launched Hephae in 2020 to adapt their oil and gas expertise for geothermal wells.
Their measurement-while-drilling system fits into a thick steel tube that connects to the rock-cutting drill bit. Sensors and rounded circuit boards — stacked like chips in a Pringles can — gather subsurface data and transmit it through a sequence of pressure pulses, enabling engineers to steer the drill through the challenging environment.
Conventional versions of the tool are built to operate at relatively lower temperatures — around 175 degrees Celsius (347 degrees Fahrenheit) — where oil and gas reserves are typically found. But for geothermal firms, the higher the rock temperature, the more energy they can wring out of the system, making each well more cost-effective and productive.
Right now, that means geothermal developers must occasionally pause for extended periods to cool the drilling fluid inside the wells to avoid overheating the electronics. This “nonproductive time” can cost operators roughly $500,000 to $1 million per well, since they’re still paying to rent a drilling rig they’re not using, according to Krase.
Hephae says its unique design can withstand temperatures up to 210℃, reducing work delays by directing heat away from the sensors and circuits as they operate. Before shipping the tool to Cape Station, the company put the technology through its paces at an Oklahoma test facility and in Texas at a high-temperature gas well — another possible market for Hephae.
“Fervo has been really supportive, because they know their success depends on being able to get to the good rock,” Krase said.
Fervo, for its part, has already made significant strides in recent years to reduce drilling times and access deeper resources in Utah. In May, the startup became the first next-gen geothermal firm to go public, and Cape Station is expected to be the largest project of its kind in the world when it comes fully online by 2028.
The company declined to comment for this story, but it shared an earlier statement from Elliot Howard, Fervo’s director of drilling and completions.
“Fervo is encouraged by the early progress of our collaboration with Hephae, whose novel high-temperature innovations have the potential to contribute positively to [enhanced-geothermal-system] economics, unlock higher-energy geothermal resources, and further cement the competitiveness of next-generation geothermal power,” Howard said in a July press release announcing Hephae’s fundraise.
With its new funding, Hephae plans to triple the number of tools in its arsenal, from six to 18 by the second quarter of next year. That total could reach 40 tools by the end of 2027 as Fervo, Mazama, and future partners advance their geothermal projects.
Hephae is also investing in R&D to design systems for temperatures above 300℃, which it hopes to launch by 2030.
Gilani of Cleantech Group said that Hephae’s partnerships with Fervo and Mazama make it well positioned to grow with the wider next-gen geothermal industry. If Hephae can play a part in bringing the projects online, “that will both help Hephae to scale and will also help the industry overall,” she said.
Last year, Gov. Newsom vetoed bills promoting home batteries, smart thermostats, and EV chargers to curb energy costs. Will he do the same this year?
Last year, California Gov. Gavin Newsom vetoed a slate of bills meant to expand virtual power plants that could offset the state’s fast-rising electricity costs. Will he do the same this year?
Earlier this month, two virtual power plant bills made it through a key legislative hurdle. Lawmakers must vote on the bills by Aug. 31. Should they pass, Newsom, a Democrat, would have until the end of September to sign or veto them.
Californians pay some of the most expensive electricity rates in the continental U.S., an issue of increasing political salience. Climate advocates, clean energy groups, and supportive lawmakers say the state can curb these costs by tapping into its nation-leading fleet of rooftop solar–charged batteries, remote-controllable EV chargers, and other household devices — in other words, the collective components of virtual power plants.
The bills propose two different approaches for using VPPs to bring down costs: Senate Bill 913 would harness them to blunt the edge of costly grid peaks, while Senate Bill 905 could encourage California’s major utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — to use VPPs to reduce costly grid investment.
“If we can call on these resources, it is a massive win-win. People get paid, and it also saves everybody in California money,” Sen. Josh Becker, a Democrat who authored both bills, said at a Monday press conference in Sacramento promoting “local, affordable” clean energy policies.
SB 913 would give the California Public Utilities Commission until mid-2028 to craft regulations that allow VPPs to play a role in providing resource adequacy. That’s the term for the increasingly costly services that every utility and community energy provider must secure from gas-fired power plants, battery banks, and other dispatchable resources to keep the grid running when demand for power peaks.
VPPs could cover more than 15% of the state’s peak grid demand and deliver $550 million in annual utility customer savings by 2035, according to a 2024 analysis by consultancy The Brattle Group for GridLab.
“Many of these resources are sitting on the sideline because our rules have not kept up with technology,” said Becker, who also penned one of last year’s vetoed VPP bills.
VPPs face multiple barriers to being counted toward resource adequacy, from measurement protocols that erode their value during heat waves to rules that ban home batteries from getting credit for power they inject back onto the grid.
Meanwhile, Californians are paying roughly $1 billion per year to extend the lives of fossil-fueled “peaker” gas plants needed for only a handful of hours per year, he said. “We can get rid of those if we take better advantage of what’s already in people’s homes.”
SB 913 has won backing from dozens of environmental groups, trade organizations, and companies that manufacture, install, and manage the devices that constitute VPPs. Utilities Pacific Gas & Electric and Southern California Edison withdrew their opposition to the bill after amendments were added to it in late June.
California leads the country in home batteries and electric vehicles, and has millions of homes that could adjust the power usage of smart thermostats, water heaters, and other devices during the handful of hours per year when the grid is under the greatest strain.
Distributed batteries could be a particularly powerful tool. A July 2025 utility test of home batteries delivered more than 500 megawatts of grid relief over a two-hour period corresponding to when California’s grid tends to face its greatest stress during summertime heat waves.
The state currently has 2.5 gigawatts of residential batteries and more than 600 megawatts of batteries at commercial properties, according to the California Energy Commission.
SB 913 could make it more lucrative for households with these “behind-the-meter batteries” to commit their spare power to the grid. That could encourage more participation in VPP programs, said Brandon García, California policy director at trade group Advanced Energy United.
It’s particularly important to create new incentives for households with batteries to participate in VPPs given that California’s largest such program faces the threat of being defunded and disbanded, he said.
That program is called Demand Side Grid Support, and it has grown to one of the largest VPPs in the country, including nearly 75,000 homes with smart thermostats and flexible load devices, and nearly 130,000 homes with batteries. But DSGS is operated by the California Energy Commission using state taxpayer funds — and under a budget proposal from Newsom’s administration, that funding could be cut and the program shut down next year.
Many of the groups supporting SB 913 are also calling on Newsom and lawmakers to extend DSGS for a few more years, to avoid stranding the companies that have invested and the households that have enrolled in it.
“If there’s not a program to keep these resources online with some level of compensation until a resource adequacy pathway is created, those resources will go somewhere else,” García said.
In an echo of debates over rooftop solar in California, the state’s Public Utilities Commission and utilities have argued that it’s unfair to pay households for VPP participation, because it shifts the costs of running the grid onto utility customers who don’t have batteries, EV chargers, or other eligible devices.
García said that allowing VPPs to compete with gas plants, utility-scale batteries, and other providers of resource adequacy could help resolve these concerns. That’s because VPPs competing in those markets “only get enrolled if they’re lowest-cost resources — and we are confident that they will be the lowest-cost resources.”
SB 905, meanwhile, targets an even bigger cost driver in California: utility grid investments.
Among the bill’s wide array of utility affordability measures is a provision that would require the Public Utilities Commission to establish “grid utilization” metrics for the state’s three big utilities. That data could reveal where utilities are using their existing grids more or less efficiently, and potentially encourage them to employ batteries, flexible-load controls, and other VPP-style approaches to smooth out the peaks in electricity demand that drive much of the need for new grid infrastructure.
California’s utilities are planning tens of billions of dollars of investments on their sprawling distribution grids to keep up with growing power demand and mitigate wildfire risks. Using VPPs to reduce peak loads on those circuits and substations could allow them to defer billions of dollars of those investments, reducing upward pressure on rates, Becker said.
“We’re not saying we’re not going to build anything new,” Becker told Canary Media in a Monday interview. “But let’s make the best use of the existing resources that are already out there, that we’ve already paid for, before we go off spending a lot of money on new resources.”
It’s unclear whether Newsom will respond to this year’s VPP policies differently than he did last year’s. The three bills he vetoed in 2025 were passed by large majorities and proposed relatively minor changes in state VPP policy. Newsom’s veto statements cited the risk that they could disrupt existing grid reliability and planning methods.
Those arguments haven’t sat well with lawmakers pushing for VPP reforms. “We should be leaning in a lot more to innovation, especially on clean energy,” state Assemblymember John Harabedian, a Democrat who authored one of the VPP bills vetoed last year, said at an event in Sacramento earlier this month. “How do we utilize the grid in a more efficient way? I think technological innovation will help us do that.”
Becker declined to predict if Newsom would sign his VPP bills. “We’re focused on getting it passed,” he told Canary Media. “Then we’ll focus on the governor’s team and the governor’s reply.”
Unless Gov. Newsom blocks the bill, it will legalize plug-in solar in one of the world’s biggest economies. But the rules are more restrictive than some hoped for.
Californians could soon put solar panel kits on balconies and in backyards to lower their electric bills — without utility approval.
On Wednesday, state lawmakers passed the Plug and Play Solar Act (Senate Bill 868) to legalize balcony solar, a form of DIY clean energy that’s taken off in Germany. The bill, which garnered bipartisan support, now heads to the desk of Democratic Gov. Gavin Newsom. His office declined to say if he’ll sign or veto it within the 30-day deadline; if he does neither, it would still become law and take effect Jan. 1, 2027.
“Imagine being able to reduce your annual electric bill by $400, which is what is estimated here, simply by plugging in one of these devices and leaving it in the sun,” state Sen. Scott Wiener (D), who wrote the bill, said at a Monday press conference on the legislation. “This is a level of convenience in terms of installation and energy savings that we have not seen before.”
Balcony solar kits, already sold by a few businesses in the U.S., put home solar in the hands of millions of renters and homeowners who can’t have panels installed on their roofs. The portable panels push power into a standard 120-volt wall outlet; that electricity then flows to the nearest power-hungry devices, such as the fridge, computer, Wi-Fi router, lights, and air conditioner.
If enacted, California’s legislation would allow households to install plug-in solar systems sized up to 1,200 watts per residence without the costly and potentially time-consuming utility interconnection process that’s required for larger rooftop arrays. Even a 400-watt system can cover roughly 14% of an apartment’s energy use, according to the Environmental Working Group, a nonprofit that advocated for the bill.
The Golden State’s embrace of balcony solar follows a tsunami of support nationwide. More than half of states have considered plug-in solar legislation in the last year, and so far, eight have adopted balcony solar laws: Colorado, Connecticut, Maine, Maryland, New Hampshire, Utah, Vermont, and Virginia. New York passed a bill in June, but boosters are still on tenterhooks as to whether Gov. Kathy Hochul (D) will sign it.
“California is going to have a huge impact on this market,” said Cora Stryker, co-founder of plug-in solar nonprofit Bright Saver. The state’s economy is the largest and among the fastest growing in the nation. “Manufacturers are going to see this and seize upon the opportunity.”
The bad news: Households won’t be able to get plug-in solar that meets the bill’s requirements right away. The state would allow only balcony solar kits that have been certified safe to use by a nationally recognized testing laboratory. One of these organizations, safety company UL Solutions, began testing plug-in systems this year under its new standard, UL 3700, but no product has yet earned certification.
The rule is more restrictive than those adopted by some other states. For example, Utah and Maryland require that the individual kit components pass safety standards, rather than the entire system, according to Stryker.
Stryker said she’s worried that California’s stringent approach could put a damper on balcony solar’s growth in the state in the near term, especially for renters. In its current form, the UL 3700 standard still requires an electrician to get involved, the opposite of plug and play. Still, Bernadette Del Chiaro, the Environmental Working Group’s senior vice president for California, said she expects the standard to evolve to include DIY systems as soon as next year.
Another wrinkle: The legislation includes an expiration date, which the state’s largest utility, Pacific Gas and Electric, appears to have lobbied for. On Jan. 1, 2030, Californians will no longer be able to install plug-in solar without first getting their utility’s sign off.
“We would expect the Legislature to reconsider that sunset in 2028 and at the latest 2029,” Del Chiaro said.
Wiener believes, despite its challenges, the plug-in solar bill will be transformative for Californians. “Balcony solar is incredibly important,” Wiener told Canary Media. “This is a way to lower people’s cost of living when people need relief. … I’m glad that we’re finally making it happen.”
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