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After years of failing to rein in rapidly rising electricity rates, California lawmakers are hoping a radical new approach — and billions of dollars in state financing — can offer a solution.
Bills moving through the California Senate and Assembly would use money raised from state bonds to help pay for the hugely expensive process of expanding the power grid and making it less vulnerable to wildfires. This path would relieve some pressure on utility customers in California, because funding grid upgrades through bonds is cheaper than doing so through energy bills.
Utility costs have reached a boiling point in California, with customers of the state’s three biggest utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — now paying almost twice the U.S. average for their power. Nearly one in five customers of these utilities is behind on paying their electric bills, according to a May report from state regulators.
The bills — Senate Bill 254, sponsored by Sen. Josh Becker, and Assembly Bill 825, sponsored by Assemblymember Cottie Petrie-Norris, both Democrats — aim to lower electricity costs for Californians. Both include provisions that would force the big three utilities to accept public financing for a portion of the tens of billions they plan to spend on their power grids.
The two bills have been passed by their respective legislative chambers. That’s despite opposition from the big investor-owned utilities, which object to using public funding for grid infrastructure projects because they earn guaranteed profits if they invest in infrastructure themselves. The utilities have defeated previous legislative efforts that would have crimped those future profits by having the state assume a portion of the expenses.
But the electricity cost crisis has made rate reform “a top-tier issue in California,” said Matthew Freedman, senior attorney at The Utility Reform Network (TURN), a consumer advocacy group that has joined other consumer and environmental justice groups in supporting SB 254.
“This is different from what we’ve seen in the past — and the solutions being sought by the legislature are more ambitious than what we’ve seen in recent years,” he said. TURN is hoping these dynamics will allow the public-financing portions of the bills to secure support from Gov. Gavin Newsom (D) and remain in whatever electricity-affordability legislation emerges before the end of the state legislative session in September.
TURN’s analysis indicates that pulling $15 billion out of the rate base of California’s three big utilities, as SB 254 and AB 825 propose to do, could save about $8 billion over 30 years, with $7.5 billion of that savings coming in the first 10 years. That equates to about 2–3% of an average residential customer’s bill, or about $4–$5 a month, Freedman said.
“Does this solve the affordability crisis? No. There’s no silver bullet. That’s the biggest frustration we have and that many policymakers have,” he said. But it does offer a straightforward path to a quick reduction in rates, and “we’re trying to get some near-term benefits here.”
SB 254 is an omnibus of electricity-affordability policies, ranging from streamlining permitting for grid and energy projects to forcing utilities to propose investment plans that limit their spending to the broader rate of inflation. AB 825 is more limited in scope, but the two bills share a couple of key concepts for state financing of utility infrastructure.
First, both bills would shift $15 billion in grid spending from utility capital expenditures to financing via bonds — a process known as securitization. Regulated utilities have commonly used securitization to help reduce the cost of closing aging power plants and rebuilding their grids after storms, by foregoing the return on equity that utilities typically earn for capital investments and tapping the lower cost of debt available to states or state agencies.
But there’s “little precedent for securitizing future productive utility capital spending,” Julien Dumoulin-Smith, an analyst at investment firm Jefferies, wrote in a June research note. The prospect that lawmakers might force California’s major utilities to securitize some of their highly profitable grid investments has in recent months weighed down investor expectations for the firms, he wrote.
The lawmakers pushing these bills argue that it’s more important to protect Californians from unchecked rate increases than to protect utility profits.
The state’s three big utilities are collectively planning about $90 billion in new capital expenditures from 2025 to 2028, Becker noted in a June press release after SB 254’s passage by the state Senate. Securitizing $15 billion of those investments would “reduce financing costs by eliminating profit margins and lowering interest rates,” Becker said.
In particular, the bills aim to rein in the biggest driver of rate increases — the tens of billions of dollars California’s utilities are investing in hardening their grids against the risk of sparking deadly wildfires.
“We’ve asked the investor-owned utilities to do a lot of that work, and we have to make sure it’s done as efficiently as possible,” Becker said during a virtual town-hall event in June. “I think we can have a discussion today about whether that’s something that should be in rates going forward.”
A March report from the Natural Resources Defense Council, a supporter of SB 254, examined wildfire-mitigation costs at PG&E, the state’s largest utility, which has doubled rates on average over the past decade and increased them 40% above inflation since 2018. According to that analysis, about 60% of PG&E’s rate increase stemmed from wildfire-related expenses, Merrian Borgeson, NRDC’s California policy director for climate and energy, said during the June town hall.
PG&E, which was forced into bankruptcy in 2019 after its power lines sparked the state’s deadliest wildfire, is under state mandate to invest in preventing its grid from causing more conflagrations. But the utility has also notched record-breaking profits in the midst of its record-breaking rate increases — in large part because of the guaranteed return it’s earning on that wildfire-prevention work.
Customers need quick relief from bearing those costs, and “the things that you can do the fastest to reduce electric rates are to take things out of rates,” Borgeson said.
Freedman of TURN highlighted differences between the securitization approaches of SB 254 and AB 825. AB 825 would apply only to the costs of burying power lines to prevent them from sparking wildfires. These “undergrounding” projects make up a big chunk of the broader wildfire-mitigation spending, particularly for PG&E. SB 254, by contrast, would apply to wildfire mitigation more broadly, as well as to spending to expand utility grids to serve fast-growing demand for electricity from big new loads like data centers and electric-vehicle charging hubs.
But in both cases, replacing utility spending with state borrowing would significantly lower costs to utility customers, he said. First, California can borrow money at lower rates of interest than utilities can. Second, the state can spread out the costs over a longer period of time, and reduce the portion of costs borne in earlier years, compared to how utilities pass on the cost of capital investments to their customers, he said.
It’s also been done before in California. In 2019, lawmakers passed a $21 billion wildfire bill to backstop California utilities’ financial stability in the face of PG&E’s bankruptcy. That bill forbade utilities from recovering a return on $5 billion in investments in wildfire-mitigation spending, but offered them the option of securitizing that spending instead, which they accepted. That’s expected to reduce ratepayer costs by as much as $2 billion over the lifetime of those assets.
The $15 billion securitization plan in SB 254 and AB 825 is targeted at reducing utility costs and rates in the shorter term. But both bills also propose a longer-term public-financing option aimed at the state’s high-voltage transmission grid.
“The idea here is to establish a state infrastructure authority that would have the capacity to finance and own these lines,” Freedman said.
That’s not a completely novel concept. The state-run New York Power Authority has owned and managed transmission grids since the 1930s, as have federal power-marketing entities such as the Bonneville Power Administration and the Tennessee Valley Authority. More recently, New Mexico and Colorado have created transmission authorities to facilitate grid buildouts.
The California Independent System Operator, which manages the state’s grid, estimates that California must spend between $46 billion and $63 billion over the next 20 years to meet its goal of achieving a carbon-free grid by 2045. An October report from Net-Zero California and Clean Air Task Force found that “traditional investor-owned utility financing and development” of those projects “could substantially increase consumer rates,” but that a public-private partnership model could reduce those costs by up to 57%, saving utility customers as much as $3 billion per year compared to a status-quo approach.
“There are lots of institutional changes, and changes to authorities that operate in California, needed to operationalize the full range of those savings,” said Nicole Pavia, Clean Air Task Force’s director of clean energy infrastructure deployment. SB 254 and AB 825 don’t specify what form any future public-private ownership or public-financing structures for transmission might take, she noted. But both “are picking up pieces of the institutional changes that might be needed to advance some of these savings.”
The two bills take different approaches to this issue, Freedman said. SB 254 would establish a new Clean Infrastructure Authority to take on the work, while AB 825 would revitalize the California Consumer Power and Conservation Financing Authority, a now-defunct entity created after the state’s 2001 energy crisis to finance new power generation, he said.
The move to increase state authority over transmission development would not offer immediate relief to ratepayers, said Vivian Yang, an analyst at the nonprofit Union of Concerned Scientists.
“These are big projects that are regardless going to take five to 10 years,” she said. “It’s not like we can pass those public-financing bills and then the next year our rates will go down.”
Instead, it would help the state position itself to avoid yet another cost crisis in the years to come. Given the massive amount of transmission California will need over the coming decades, “having all these tools to get us there — one of which is public financing for projects — is really important,” she said. California needs to get to work now to “have these structures up and running already and use them more nimbly, and not discover 10 years out that we’re stuck using what we’ve got.”
The Trump administration has officially announced it is killing the $7 billion Solar for All program. The program had awarded grants to 60 state agencies, municipalities, tribal governments, and nonprofits across the country to help low-income households access solar power. Supporters of Solar for All are vowing to fight the move in court.
On Thursday, Environmental Protection Agency Administrator Lee Zeldin posted a video on the X social media platform stating that he was terminating the program. Solar for All was created as part of the Inflation Reduction Act’s $27 billion Greenhouse Gas Reduction Fund (GGRF), which has also been under attack by the Trump administration.
Zeldin stated that the mega-law passed by Republicans in Congress last month “eliminates billions of green slush-fund dollars by repealing the Greenhouse Gas Reduction Fund.”
Referring specifically to Solar for All, Zeldin said, “EPA no longer has the authority to administer the program, or the appropriated funds to keep this boondoggle alive. With clear language and intent from Congress in the One Big Beautiful Bill, EPA is taking action to end this program for good.”
Defenders of Solar for All challenge Zeldin’s interpretation of the One Big Beautiful Bill, or HR 1, and the intent of its provisions.
“It is absolutely ludicrous to suggest that HR 1 rescinded these funds, because they were all under legally obligated grant awards when the bill was signed,” said Jillian Blanchard, vice president of climate change and environmental justice at Lawyers for Good Government, a nonprofit coalition of attorneys, law students, and activists that’s challenging other EPA funding cuts. “HR 1 only rescinded unobligated grant funds,” she told Canary Media on Thursday.
That’s an important distinction, she said. Those unobligated grant funds amounted to only $19 million, as determined by the Congressional Budget Office (CBO) when it conducted its analysis of the pending legislation’s overall financial impact. The vast majority of the funds, the office found, were already committed under legally binding contracts to the parties awarded grants during the Biden administration.
But in a court case challenging the EPA’s effort to claw back $20 billion in funds for other GGRF programs, administration officials have claimed that HR 1 terminates the government’s obligation to meet any of its contractual obligations.
Attorneys for nonprofit groups fighting EPA’s attempt to claw back their grants argued that the law clearly states that only “unobligated balances of amounts made available to carry out that section … are rescinded.”
The attorneys also noted that Sen. Shelley Moore Capito, the West Virginia Republican and chair of the Senate Committee on Environment and Public Works, stated during a congressional debate before the bill passed that funding “that’s already been obligated and out the door, that’s a decision that’s final,” and that arguing the law would claw back obligated funding is “a ridiculous thought.”
Sen. Sheldon Whitehouse (D-R.I.) pointed out this same discrepancy in a July press release attacking EPA’s characterization of the law. “Trump’s DOJ is continuing its mischief by falsely claiming Republicans’ Big Beautiful-for-Billionaires Bill claws back $17 billion from GGRF, even though the CBO score for the unobligated funds was $19 million — what was left to oversee the program after the grant funds had been obligated — and Republicans made clear that their rescissions only touched unobligated funding,” Whitehouse wrote.
The Solar for All program is meant to deliver energy-bill savings of $350 million over the next five years to 900,000 low-income and disadvantaged households and deploy 4 gigawatts of solar generation capacity. In the past few months, a handful of grantees had begun issuing awards to low-income housing projects, municipal facilities, nonprofits, and low-income homeowners.
“Communities promised relief from punishing energy costs are now left in the dark,” Zealan Hoover, a former EPA senior advisor under the Biden administration, told Canary Media. “Nearly a million families will pay hundreds of dollars more each year for their electricity bill because the Trump administration killed a program that would have more than paid for itself.”
Michelle Moore, CEO of Groundswell, a Washington D.C.-based nonprofit that is administering a $156 million Solar for All grant aimed at developing large-scale solar and battery projects in Southeastern states, said that ending the program would run counter to President Donald Trump’s pledge to lower energy prices.
“I would hope [the Office of Management and Budget] could find the funding to cover EPA staff time to help keep President Trump’s campaign promise to cut bills in half and keep energy affordable for American families, which this program does,” she told Canary Media.
President Donald Trump’s new budget law repeals a key federal tax incentive for residential solar — and rooftop solar installations are about to plunge as a result.
Americans are expected to install 33% less rooftop solar next year than they would if federal incentives were still in place, per an updated analysis from Ohm Analytics. That’s a better outcome than the research firm’s earlier, gloomier forecast, which was based on a version of the law that would have also scrapped a separate tax credit that applies to leased systems.
The repeal of the 25D tax credit, which knocks 30% off the price of home solar and storage, will make the technology significantly more expensive. The incentive was originally available until 2035 but now disappears at the end of this year.
Already, residential solar is far more expensive in the U.S. than elsewhere, and high interest rates as well as recent state-level policy developments are eating further into the economics of buying panels. Even before the repeal, rooftop solar installations were declining year over year because of these trends.
In 2025, though homeowners are expected to fast-track solar purchases before the tax credit expires, Ohm expects an 8% decline in installations compared with last year. In 2026, the total gigawatts installed will shrink by 26%, it forecasts.
Rooftop solar is an important piece of the energy transition. In California, photovoltaic panels on roofs produce almost as much power as the sprawling large-scale arrays found in fields and desert areas.
But it’s also a critical way for people to hedge against utility rates, which have climbed high in recent years and are expected to rise even further as data centers demand more energy and the Trump administration stymies cheap wind and solar power. Most households that install rooftop solar see their energy bills drop. Poorer households benefit most.
Still, there are things within the industry’s control, from reining in “soft costs” to developing more virtual power plants, that can help it weather the storm — and make rooftop solar more affordable to Americans even without long-standing tax credits in place.
CALISTOGA, Calif. — A quaint northerly outpost of Napa Valley wine country, Calistoga has struggled to keep the lights on when wildfires strike the region. Now it’s got a brand-new microgrid to run the whole town for days on end without any onsite fossil fuels, just batteries and liquid hydrogen.
After disastrous conflagrations in 2017 and 2018, utility Pacific Gas & Electric began preemptively shutting off power lines to avoid sparking fires amid dangerously dry, windy conditions.
“We were the first community in all of PG&E’s network that was getting our power shut off to protect us,” said Calistoga City Council member Lisa Gift. “By 2019 we were one of the first communities to have a microgrid in all of PG&E’s network, and that was being powered by diesel generators.”
PG&E arranged a bank of truck-based diesel generators to sit in the town during fire season. When the utility cut grid power, the generators kicked on, belching smoke in a particularly beloved pocket of the 5,000-person community.
“We’re a small town, so they would come up and they’d be polluting the environment, taking up our dog park — loud, gross, noisy,” Gift recalled.
Now the diesel generators are gone and the park has been turned back over to Calistoga’s canine companions.
On a slim parcel of city land next door, publicly traded energy-storage company Energy Vault installed lithium-ion batteries and a 234-foot, reinforced-steel tank for liquid hydrogen (designed to withstand a roaring fire, should it ever come to that) that runs a bank of hydrogen fuel cells. Altogether, this compound should be able to meet Calistoga’s electricity needs without any power from the broader grid. It’s contracted to produce up to 8.5 megawatts for 48 hours, whenever PG&E shuts off grid power due to fire concerns. Refilling the hydrogen tank could let it run for several days more.
“Even though we’re taking elements — fuel cells, batteries, liquid hydrogen storage and distribution — that have been used before in commercial settings, they’re coming together for the first time as resiliency,” said Craig Horne, Energy Vault’s senior vice president for advanced energy solutions, in an interview before the project’s unveiling in early August.
Fans of hydrogen hail it as a solution to just about any entrenched decarbonization challenge, from heavy transport to steelmaking to on-demand power. But how hydrogen is produced makes a huge difference in its climate impact; seemingly clean sources can actually rack up major carbon emissions for negligible benefit. For now, the clean hydrogen economy remains largely speculative, with hardly any truly clean hydrogen being produced or any real projects using it. Many planned clean hydrogen projects have vanished without a trace, following a short-lived boom fueled by Biden-era support.
In Calistoga, Energy Vault has tapped hydrogen to deal with a very specific set of constraints — delivering energy without local emissions, over multiple days, in a tight footprint — but the cleanliness of that hydrogen is a more complicated issue than public descriptions of the microgrid suggest.
The key players all have a lot riding on the project.
Energy Vault, which previously raised several hundred million dollars in a singular bid to store energy with multi-story robotic cranes that stack blocks, wants to build a new long-duration storage business around this hydrogen microgrid showcase. Plug Power, the financially challenged hydrogen company, points to Calistoga as its largest deployment of hydrogen fuel cells (a beefy 8 megawatts, after 28 years of hard work). And PG&E has orders from regulators to add more clean energy microgrids in communities where it regularly cuts off power — Calistoga was its first delivery on that directive, after a few years of soliciting proposals and a couple more years of permitting and construction.
“Community microgrids are the future of the energy system,” said Craig Lewis, who advocates for such projects as executive director of the Clean Coalition nonprofit. The Calistoga microgrid is “a commercial-scale experiment, and I’m grateful for it.”
The results of that experiment will take time to analyze. It could unleash a new, replicable model for premium-priced community-level backup power. Or the quirkiness of the design and the murkiness of hydrogen’s supply chain and emissions could make it a quixotic outlier of questionable climate value.
The Calistoga microgrid poses an answer to the question of how to provide a few days of backup power to a small town in a small space, without worrying too much about cost. The limitations drove the design, which turned out quite unlike anything built thus far.
Energy Vault had to figure out how to pack 293 megawatt-hours of storage into just two-thirds of an acre. The lot used to hold debris from city works, like old bits of sidewalk and pipes, Horne said.
Lithium-ion batteries have proven themselves capable of storing power, be it as a Powerwall in someone’s garage or as a large-scale grid storage facility. But to store nearly 300 megawatt-hours, grid battery enclosures need more acreage than was available to lease from the city. Even if enough batteries could fit, the auxiliary power consumption for keeping them safely cooled would pose a challenge for a project that’s supposed to mostly sit around waiting for an emergency event.
Hydrogen gas can be liquefied by cooling it to ultra-low temperatures, which unlocks greater energy density. When converted back to gas and run through fuel cells, it produces a stream of electricity and no byproduct besides water vapor. That core technology powers hydrogen vehicles, though their cost and inconvenience make for a widely derided car-ownership experience. At Calistoga, the hydrogen flows directly to six Plug Power GenSure 1540 fuel cells, boxy containers with cooling units stacked on top, making them about two stories tall.
The engineers added a small lithium-ion battery (7.7 MW/11.6 MWh) to perform “black start,” the complicated and crucial task of rebooting an electrical system after a complete blackout, Horne noted. The battery also buffers the output of the system while the hydrogen gets up and running. Then the power flows to Calistoga’s grid, which, when PG&E shuts off the transmission lines, will be fully islanded from the surrounding network.
The hydrogen is stored onsite in an 80,000-gallon tank, manufactured in Minnesota by Chart Industries. The tank holds enough to power the fuel cells for about two days, but Energy Vault will try its best to keep the lights on beyond the contracted timeframe, Horne said. So the company made sure the tank can be refueled while it’s in active use.
“The task is to squeeze toothpaste into a toothpaste tube that was being squeezed,” Horne said. “That’s what we proved in our acceptance testing, running for multiple hours while the fuel cells were running and a tank trailer here in the driveway is pushing liquid hydrogen into the tank itself.”
The microgrid’s promise as a clean energy breakthrough, of course, hinges on the supply of clean hydrogen, but supply chains are barely getting started. Almost all commercial hydrogen is currently made from methane gas, a fossil fuel, through a procedure called steam methane reforming that sends the carbon dioxide byproduct straight into the atmosphere.
For hydrogen to stake any claim as a climate solution, it needs to be made without massive carbon emissions. That usually involves an alternative production method called electrolysis, which separates hydrogen from water using electricity. But this method can produce even more emissions than the dirty methane version if the electrolyzers are drawing power from the grid rather than dedicated renewable sources like solar and wind (see this previous Canary Media coverage for a detailed account of why that’s the case).
Energy Vault describes the hydrogen it’s using in Calistoga as “clean,” which Horne clarified as meeting the federal standard of no more than four kilograms of carbon dioxide emitted per kilogram of hydrogen produced. But he declined to name the source. Notably, California has subsidized hydrogen fueling stations for over a decade but still hasn’t managed to develop a clean hydrogen supply in-state. So for Calistoga’s hydrogen to be clean, it must be coming from somewhere else.
During a tour of the microgrid, Deepesh Goyal, vice president of stationary power at Plug Power, told Canary Media that Plug Power currently supplies hydrogen from its electrolyzer site in Georgia, which runs on grid power. More than half of Georgia’s electricity comes from fossil fuels, so that electrolysis incurs substantial power-plant emissions. Plug Power buys credits for clean energy supply to compensate for this, Goyal said.
To meet the highest federal standard for clean hydrogen, producers need to obtain clean power matched to their consumption on an hourly basis in the areas where they operate. Plug Power did not respond in time for publication to questions clarifying what type of credits it buys. But a spokesperson for Energy Vault told Canary Media that currently there aren’t any facilities that could supply Calistoga with liquid hydrogen from electrolysis powered by time-matched, dedicated clean electricity, and the earliest such facility is targeting completion in 2026.
Goyal also said some of Calistoga’s hydrogen comes from an unnamed partner in Las Vegas that uses renewable natural gas (RNG) as its feedstock. As it happens, legacy gas supplier Air Liquide opened a steam methane reformer in that area a few years ago to serve California’s demand. Air Liquide says it can substitute RNG for the usual methane, which would make the resulting hydrogen carbon-negative according to the convoluted calculations of California’s clean fuels bureaucracy. It’s still hydrogen made by splitting methane and releasing carbon dioxide, but it looks good on paper thanks to controversial rules that privilege certain politically connected providers of RNG.
If someone were to design a climate solution from a blank slate, they probably wouldn’t run electrolyzers on grid power in Georgia in order to load the super-cooled hydrogen onto diesel-powered tankers and haul it more than 2,800 miles to Northern California, where it will sit around almost every day awaiting a utility power outage.
“We still have to truck in that hydrogen,” said Gift. “That’s not ideal, but we were trucking in the diesel, and we were trucking in the diesel sometimes three times a day and burning that diesel.”
One incontrovertible fact is that the microgrid doesn’t combust anything onsite, so the operations within the fenceline emit almost no carbon emissions and don’t impact air quality. But it will be hard to gauge the real climate impacts of such a project until a more verifiably clean and geographically localized hydrogen supply chain develops. Several companies have said they will build truly green hydrogen production in the coming years. That task has only grown more difficult with the Trump administration’s efforts to thwart renewables development and vastly curtail clean hydrogen tax credits.
The other make-or-break variable for hydrogen-backed resilience is how much it costs. Liquid hydrogen is an expensive, specialty fuel only produced by a handful of suppliers in the U.S., and clean liquid hydrogen is even rarer.
For this first project, Energy Vault didn’t need to worry about consumer price sensitivity. The city of Calistoga isn’t paying Energy Vault for backup power: PG&E is paying the company to provide this service, out of funds socialized across the utility customer base. In fact, Calistoga is making some money, since Energy Vault leased the land from the municipality for 10 years.
The project’s total price tag has not been made public. Regulators allocated up to $46.3 million for PG&E to spend on the endeavor. Energy Vault closed $28 million in project financing this spring to support construction. (The company also said on Thursday that it has raised $300 million to launch Asset Vault, a subsidiary that will build, own, and operate storage projects, with Calistoga as one of two anchor properties.) Horne allowed that the hydrogen microgrid costs more than diesel generators up front, but argued it can be competitive in terms of operating costs, given all the hassles associated with diesel.
“We can do more and waste less, and so that’s how we can be more cost effective,” he said.
The regulatory authorization paints a different picture. The California Public Utilities Commission explicitly allowed PG&E to spend more money than the diesel generators cost in order to test a new model for cleaner resilience.
“This project was supported by a CPUC plan that said we could build a solution that costs no more than twice what it would cost to deploy diesel generation over 10 years,” said Jeremy Donnell, a senior manager for microgrid strategy and implementation at PG&E. “It’s a bit of an arbitrary marker, but that’s what was laid out, and this project did come in under that threshold.”
“But still, we have a ways to go to bring the cost down,” Donnell added. “So hopefully, through implementation of this first project, Energy Vault learned a lot, the industry learned a lot on how to integrate these solutions in future projects.”
Energy Vault hopes to improve the project economics by upgrading the site to allow regular power exports to the grid. Currently, the system is configured to only push out power when PG&E has scheduled a shutoff event; that means the microgrid sits idle almost every day of the year (and is unavailable for unforeseen outages, like if a tree falls on a key line). But with the right permissions and technical tweaks in place, Energy Vault expects to use the battery, and potentially even the hydrogen, to send power to California’s grid at particularly lucrative times.
“We can now have a viable second revenue stream outside of providing that resiliency service, without compromising our ability to provide the resiliency service,” Horne said. PG&E amended its contract this summer to clarify that Energy Vault is allowed to pursue this, provided it does not interrupt delivery of the required resilience services.
Going forward, Calistoga will serve as a showcase for Energy Vault’s new “H-Vault” product line, marketed as a high-tech option for long-duration clean energy needs. Hydrogen tanks will join gravity-based block stacking and conventional lithium-ion batteries as the company’s core offerings.
For the people of Calistoga, the project softens the upheavals of living through climate change–induced extreme weather, without all the downsides of onsite fossil fuel combustion.
“Is it absolutely perfect? No,” Gift said. “But as a society, it is about making that next best right step. And for us in our community, this was that next best right step.”
For Energy Vault and the budding hydrogen industry, the next right step will be expanding hydrogen production that’s definitively low-emissions, and closing the 2,800-mile gap between supply and demand.
Wendy Becktold contributed reporting from Calistoga.
See more from Canary Media’s “Chart of the week” column.
Just under three years ago, the Inflation Reduction Act went into law and generated tens of billions of dollars’ worth of investment in domestic manufacturing of clean energy technologies. President Donald Trump has turned that wave into a ripple.
Since Trump took office in late January, companies have paused, canceled, or shuttered 26 different manufacturing projects that would have brought $27.6 billion in investment and nearly 19,000 jobs to communities across America, according to new data from The Big Green Machine, a project from Wellesley College.
Over that same time period, 29 new projects were announced for a total of just $3 billion.
Under the Biden administration, companies pledged well over $100 billion in factory investment, thanks to the Inflation Reduction Act’s incentives for manufacturers and for project developers and people to buy American-made solar panels, batteries, electric vehicles, and more. The cleantech manufacturing surge was so significant that it pushed overall manufacturing construction to heights not seen in decades.
Areas represented by Republicans in Congress stand to gain the most from this factory boom. More than 80% of the clean-energy manufacturing investment announced as of February would flow to Republican-led districts; over 70% of the jobs would go to these places.
But under Trump’s new “big, beautiful” law, the future of those projects is less certain.
The law did not repeal tax credits for most clean-energy manufacturers, but it will eat away at their customer base by scrapping subsidies for wind and solar developers. It also introduced strict anti-China stipulations to the manufacturing tax credit, which could be a headache for companies to comply with, depending on how the Treasury Department decides to enforce the rules.
These factors, in addition to the increasingly volatile business environment in the U.S., do not bode well for the clean-energy manufacturing boom regaining momentum in the near term. Nor do Trump’s beloved tariffs hold much promise as a way forward. Previous attempts to boost domestic solar-panel manufacturing via tariffs alone have failed, and experts say Trump’s measures will actually drive costs up for U.S.-based producers.
That’s not to say cleantech manufacturing is now a lost cause in the U.S. — some solar producers, for example, are feeling optimistic. But what’s increasingly clear is that the short-lived boom times are over, and any manufacturing success stories from this point on will be in spite of the federal government rather than because of its generous support.
Offshore wind leasing is effectively dead in the U.S. following a Trump administration order issued this week.
Large swaths of U.S. waters that had been identified by federal agencies as ideal for offshore wind are no longer eligible for such developments under an Interior Department statement released Wednesday.
In the four-sentence statement, Interior’s Bureau of Ocean Energy Management (BOEM) said the U.S. government is “de-designating over 3.5 million acres of unleased federal waters previously targeted for offshore wind development across the Gulf of America, Gulf of Maine, the New York Bight, California, Oregon, and the Central Atlantic.”
The move comes just a day after Interior Secretary Doug Burgum ordered his staff to stop “preferential treatment for wind projects” and falsely called wind energy “unreliable.” Analysts say that offshore wind power can be a reliable form of carbon-free energy, especially in New England, where the region’s grid operator has called it critical to grid stability. It also follows the Trump administration’s monthslong assault on the industry, which has included multiple attacks on in-progress projects.
The outlook was already grim for new offshore wind leasing activity following President Donald Trump’s executive order in January that introduced a temporary ban on the practice. Wednesday’s announcement makes that policy more definitive. Wind power advocates say it will erase several years of work from federal agencies and local communities to determine the best possible areas for wind development.
“My read on this is that there is not going to be any leasing for offshore wind in the near future,” said a career employee at the Interior Department, who Canary Media granted anonymity so they could speak freely without fear of retribution.
Figuring out the best spot to place offshore wind is an involved undertaking. The proposed areas start off enormous and, according to the Interior staffer, undergo a careful, multiyear winnowing process to settle on the official “wind energy area.” Smaller lease areas are later carved out of these broader expanses.
Take the process for designating the wind energy area known as “Central Atlantic 2,” which started back in 2023 and is now dead in the water.
The draft area — or “call area” — started out as a thick belt roughly 40 miles wide and reached from the southernmost tip of New Jersey to the northern border of South Carolina, according to maps on BOEM’s website. Multiple agencies, including the Department of Commerce, the Department of Defense, and NASA, then provided input on where that initial area might have been problematic. NASA, for example, maintains a launch site on Virginia’s Wallops Island and in 2024 found that nearby wind turbines could interfere with the agency’s instrumentation and radio frequencies.
The winnowing didn’t stop there. By 2024, according to BOEM’s website, its staff was hosting in-person public meetings from Atlantic City, New Jersey, to Morehead City, North Carolina, to gather input from fishermen, tourism outfitters, and other stakeholders. Under a wind-friendly administration, a final designation and lease sale notice would have likely been released this year or by 2026, based on a timeline posted to BOEM’s website.
But the Trump administration is no friend to offshore wind.
Trump officials have repeatedly targeted wind projects by pulling permits and even halting one wind farm during construction. Last month, Trump’s “big, beautiful bill” sent federal tax credits to an early grave, requiring wind developers who want to use the incentives to either start construction by July 2026 or place turbines in service by the end of 2027. The move is particularly devastating for offshore projects not already underway. Currently, five major offshore wind farms are under construction in the U.S., and when they come online, they will help states from Virginia to Massachusetts meet their rising energy demand with carbon-free power.
Wednesday’s order halts all work on Central Atlantic 2 and similar areas, like one near Guam, and also revokes completely finalized wind energy areas with strong state support. One example is in the Gulf of Maine, where Gov. Janet Mills, a Democrat, has been a fierce advocate for the emerging renewable sector.
These wind energy areas could hypothetically be re-designated by a future administration or the policy reversed, according to the Interior Department employee. Still, in the best case, that means developers will have to wait several more years for new lease areas to become available, further slowing down an industry whose projects already take many years to go through permitting and construction.
Kamloops, British Columbia, is a radiant place, receiving over 3,100 hours of sunshine a year. So it’s no wonder that in 2016, Thompson Rivers University (TRU) decided to harness all that luminescence and convert it to electricity.
If the university’s solar array had been installed on a roof or mounted above ground in a corner of a soccer field, that probably would have been the end of the story. Instead, TRU didn’t follow trends — it set one: It became the first place in Canada to embed solar panels into the ground. By 2017, a 12-meter walkway with 16 solar modules near the campus daycare, together with a compass (sunburst) design of 62 modules in front of the arts and education building, were producing power. By its second summer of operation, the compass produced enough electricity to power an entire classroom of computers at TRU’s arts and education building for the day.
For Amie Schellenberg, an electrical instructor at TRU and part of the team that spearheaded the sidewalks, ground-mounted solar arrays just make sense.
“Why wouldn’t we use the space we already have?” she asks. “We don’t need to create new space, or repurpose anything. We don’t need to plow fields or redo rooftops — the ground is there.” Historically, solar panels have been mounted above ground, typically on roofs or in gigantic solar parks. But wide-open spaces and sunlit rooftops aren’t always an option in cities.
“It’s hard to integrate traditional rooftop solar into urban centers,” says Gilbert Michaud, chair of the American Solar Energy Society’s policy division. “Buildings shade each other and condo buildings may have restricted HOA policies. It makes it really hard for people in urban environments to install solar, even though population centers have a demand for cool energy and want to see it.”
This is where in-ground solar shines. In 2021, the city of Barcelona installed Spain’s first photovoltaic (PV) pavement as part of the city’s goal to become climate neutral by 2030. In the Netherlands, an embedded 400-meter solar sidewalk in front of Groningen Town Hall is powering the building as part of that city’s ambition of becoming CO2 neutral by 2035. The project is part of the European Union’s Making City project, which aims to develop positive energy districts (PEDs) that demonstrate innovative solutions to tackle climate-neutral goals. The 400-square-meter installation is projected to offset approximately 18 tons of CO2 annually. “It is an example of how to use space in the city in a smart and sustainable way,” Philip Broeksma, councilor of energy from the Municipality of Groningen said when the sidewalks were revealed in 2023.
With places around the world looking to produce more solar energy, the question is: Can in-ground solar be scaled to meet demand?
Most solar installs are fixed tilts at a 45-degree angle, Michaud explains. “Larger installations [such as solar farms] move with the sun to capture as much light as possible. A horizontal sidewalk is much less efficient,” he says.
Not everyone agrees. Pavegen, a U.K.-based company, has combined the concept of in-ground solar tiles with the kinetic energy generated by people’s footsteps. When someone walks across the tile, a mechanism underneath it triggers an electric current that generates power.
“An example of kinetic [foot power] alone in Yosemite National Park has exceeded 35 million joules of energy. That’s equivalent to around 9,000 kilometers on an e-bike, or 10,000 hours of talk-time on a standard smartphone,” says Paul Price, head of marketing and communications for Pavegen. “When the tiles capture solar energy, they generate 30 times more.”
Pavegen’s Solar+ system, which uses the combined power of solar energy and kinetic energy, is poised for large-scale distribution this fall. Suited for integration into school campuses and city promenades, it will be able to power everything from LED streetlights to digital devices.
But how durable is the surface of a solar panel? The solar paths at TRU were covered with an epoxy and finished with a gritty, anti-slip surface that felt spongy to walk on, but this still wasn’t enough to protect the array from a Canadian winter.
“We do get snow every winter,” Schellenberg says. “And to be honest, every year, something new happened, whether it was a piece of rail that lifted off, or a couple of fasteners, or there was some water seepage underneath.”
Since the installation of TRU’s sidewalks, technology has advanced, and according to Price, companies such as Pavegen now design installations with integrated drainage channels beneath the sub-frame, ensuring water flows away efficiently and doesn’t compromise performance or safety. But despite this, installing inground solar tiles is no easy feat.
At TRU, troughs had to be cut into the concrete for wires that connect the array to the university’s electrical grid. Solar panels generate DC (direct current) electricity, so an inverter cabinet, to convert the current to usable AC (alternating current), was installed inside the arts and education building. These infrastructure changes aren’t cheap. A sustainability grant of $35,000 Canadian from the university covered the cost, not including the panels, which were donated. Schellenberg says the power generated from the sidewalks has offset this cost and it all has broken even financially. Still, she and Michaud concur that, as things stand now, in-ground solar in North America can be expensive and may lack electrical efficiency. The good news is that they both see change on the horizon.
“As the technology gets better, costs go down, and as policies are adopted, including tax credits, it becomes much more feasible,” Michaud says. Schellenberg imagines unlimited possibilities for the technology, both big and small. “An unused corner of a Walmart parking lot could become a solar-generating hub,” she muses.
In fact, this is an idea that has already reaped dividends in Moult, France. The Lidl supermarket has installed 50 square meters of in-ground solar panels in a back corner of its parking lot to reduce its energy bill. In one year, the panels produced the equivalent of 7,000 hours of use for five cash registers.
As fossil fuel-powered vehicles become antiquated and EVs increase in popularity, Schellenberg sees wireless in-ground solar EV charging stations becoming commonplace. “This could be the boost that those EVs need to make it the next 100 kilometers,” she notes.
In Amsterdam and Paris, this is already proving successful. Select bus stops and terminals are embedded with solar panels that collect energy and store it in batteries below the surface. As an electric bus pulls into the stop to pick up passengers, it’s able to draw power from the embedded system and top up its charge without needing to return to the central depot. A single charging point can produce 15 to 20 kilowatt-hours per day, enough to power a bus for several kilometers. At TRU, the in-ground solar arrays were a prototype and never meant to produce a lot of power. In the six years they were operational (2016 to 2022), they generated just enough electricity to power a single home for half a year. To put this into perspective, Topaz Solar Farm in San Luis Obispo County, California, is the largest in the U.S., spanning 4,700 acres. Over nine million above-ground mounted solar panels supply power to approximately 180,000 homes.
By 2023, the sidewalks had stopped producing power and couldn’t be maintained, but they weren’t removed. Schellenberg hopes that when people see them, they are inspired to think outside the box. She’s proud of the project and doesn’t measure its success in kilowatt hours but rather in what’s possible when it comes to renewable energy solutions. “It is another extension of finding ways to solve problems,” she says.
New York Governor Kathy Hochul has made energy affordability a centerpiece of her political platform this year, blasting proposed utility rate hikes and even promising to slow down implementation of the state’s climate law over the concern that the clean energy transition is costing New Yorkers too much.
But Hochul’s administration is slashing an energy affordability program that was once a priority for the governor, New York Focus has learned.
The EmPower+ program was designed specifically to help low- and moderate-income households “save energy and money” through energy efficiency upgrades. Since 2023 — at Hochul’s initiative — it has been New York’s one-stop shop to help residents take advantage of green building upgrades they might not otherwise be able to afford, like better insulation and replacing old boilers.
“I don’t know of any other program that makes such a big difference to the energy bill and the quality of life for a household that goes through [it],” said Jessica Azulay, executive director of the advocacy group Alliance for a Green Economy.
The program is now facing drastic budget cuts. In a July 11 meeting, the New York State Energy Research and Development Authority (NYSERDA) warned local contractors who install the upgrades that it would be cutting the EmPower+ budget from roughly $220 million this year to $80 million in 2027.
Michael Hernandez, New York policy director at the pro-electrification group Rewiring America, said he was “shocked” to learn of the impending cuts and has been sounding the alarm among advocates and lawmakers.
Azulay called the projected cuts “devastating.”
“As families are facing rising energy bills, the state is cutting back on a key tool that it has to help people get their energy bills under control, and to have homes that are more comfortable and safer and healthier,” she said.
In recent years, EmPower+ has served tens of thousands of New Yorkers, helping them identify ways that their homes might be wasting energy and fix them through installing better insulation and air sealing and switching to efficient new appliances like heat pumps. The program targets one- to four-family homes, allowing both homeowners and renters to participate.
The program covers up to $24,000 worth of upgrades per household, using a mix of state and federal funding. It aims to cover the full cost of upgrades for low-income households and, in some cases, guarantee that participants never pay more than 6% of their income on energy, by providing ongoing subsidies where needed.
Even New Yorkers who have gotten relatively minor upgrades through the program say it can make a big difference.
Isaac Silberman-Gorn, a first-time homeowner in Troy, outside Albany, said the program recently allowed him to replace a “dinosaur” of a dryer with a brand-new heat pump model. Thanks to the upgrade, his energy usage no longer spikes every time he does a load of laundry.
“It’s the first new appliance I’ve ever had,” he said. “Our energy bills are lower. I’m not worried about the thing starting a fire, which is nice.”
Silberman-Gorn, who works part-time as a bicycle mechanic and at an environmental nonprofit, said he wouldn’t have been able to afford the state-of-the-art new dryer if EmPower+ hadn’t covered the cost. “That was a game changer,” he said.
The program relies heavily on the work of local contractors, who conduct NYSERDA-funded energy audits for homes and then, typically, file the application to NYSERDA for upgrades that might be warranted. They’ve been a key avenue for bringing people into the program, often through customers who refer the companies to friends and neighbors they think might be eligible for similar upgrades.
NYSERDA told contractors in last week’s meeting that they can no longer sign up new customers for EmPower+ themselves. Clean energy advocates and contractors participating in the program see this as another way to tighten the belt.
“That will naturally slow the program down big-time,” said Hal Smith, CEO of Halco Home Solutions and president of the Building Performance Contractors Association of NYS, a trade group.
He said his own company, which works across the Finger Lakes region and has a staff of about 180, should be able to weather the cuts because it does a variety of work and serves customers across the income spectrum. But he worries that some companies working mainly or even exclusively for EmPower+ may have to shut down entirely or lay off much of their staff.
The cuts are particularly hard to stomach after years where NYSERDA was pushing for “more, more, more,” Smith said, building up the program as the state scrambled to meet clean energy targets and encouraging as many contractors as possible to get on board.
“That’s been the march for years, and we’ve all grown, grown, grown,” he said. “Now NYSERDA is saying we have to put on the brakes.”
A NYSERDA spokesperson said that EmPower+ remains a high priority for the agency and that it is only pausing applications from contractors while it reviews how to direct funds to the households most in need. (The spokesperson did not comment on the agency’s funding cuts to the program.)
Smith said he doesn’t blame any one actor for the cuts. The EmPower+ program — which was the result of a 2023 merger between two others — draws its funding from a dizzying array of sources. There’s money from New Yorkers’ utility bills, through a program approved by the state’s Public Service Commission; from the East Coast cap-and-trade program known as RGGI; from the state budget; from a federal home energy rebate program created under former President Joe Biden; and from the longer-standing federal heating assistance program LIHEAP.
Scott Oliver, an EmPower+ program administrator at NYSERDA, told contractors last week that federal and state budget cuts were forcing the agency to scale back the program. Hochul and state lawmakers gave EmPower+ a $200 million funding surge in 2023 but earmarked only $50 million for the program this year. President Donald Trump’s administration is seeking to eliminate LIHEAP entirely and cut back other weatherization funds.
Hochul could direct NYSERDA to tap other funding sources for the program, advocates say.
The cap-and-trade program RGGI has earned New York anywhere from $100 million to $400 million a year over the last decade and accumulated a surplus of more than $850 million, according to NYSERDA’s latest financial statement. The state’s new $1 billion climate fund included only $50 million specifically for EmPower+, but has another $110 million for unspecified green buildings projects, which the governor could use for the program. (The New York State Assembly had sought in negotiations to allocate more than $300 million just to EmPower+.)
And the Public Service Commission, New York’s utility regulator, recently increased the funding going from energy customers’ bills to programs like EmPower+, if not by as much as some advocates had hoped.
Advocates say it’s not yet clear whether Hochul’s administration intentionally cut EmPower+ or whether the program, with its complicated mix of funding, has simply slipped through the cracks.
Still, Hernandez, of Rewiring America, said it was bewildering that Hochul’s administration could allow such cuts to proceed while the governor emphasizes energy affordability as much as she has: “How can she be saying, doing both of those things at the same time?”
In a statement, the governor’s office highlighted the $50 million for EmPower+ in this year’s state budget.
“Governor Hochul has made affordability for New Yorkers a top priority,” said Hochul’s energy and environment spokesperson Ken Lovett. “The Governor continues to push back against devastating cuts in Washington, and calls on our state’s Congressional Republican delegation to join the fight to protect our state’s most vulnerable citizens.”
The EmPower+ cuts further slow New York’s progress toward meeting legally binding climate targets, in particular a requirement to slash energy use in buildings by 2025. That deadline is now just months away, and the state is far from meeting it.
Some climate hawks in the state legislature are beginning to cry foul over the EmPower+ cuts.
“I’m sure that right now the governor is doing her best to look at where we can cut corners,” said Assemblymember Dana Levenberg, of Westchester and the Hudson Valley, referring to the massive funding cuts coming down from Washington. “This is not where we should be doing that.”
In their presentation last week, NYSERDA officials said they were still looking for alternate sources of funding to keep EmPower+ whole.
“This is a problem that is absolutely fixable, and we need the governor to step in here and make the call,” said Azulay, of Alliance for a Green Economy.
Hochul has promised that she’s attuned to such concerns. “Utility costs are a huge burden on families,” she told reporters earlier this month, “and I’ll do whatever I can to really alleviate that.”
New Hampshire’s new state budget redirects an estimated $15 million from a dedicated renewable energy fund into the general fund, likely signaling the end of plans to expand a popular pilot supporting municipal solar developments.
While some New England states have moved to strengthen clean energy policy in the face of President Donald Trump’s efforts to quash renewable power development, New Hampshire has taken a different path: The provisions of the latest budget leave just $1 million in the renewable energy fund each year for programs that, in fiscal year 2024, cost more than $5 million to administer.
“This is a big step backward for renewable energy in the state. There’s going to be very little left over,” said Nick Krakoff, senior attorney in New Hampshire for the Conservation Law Foundation. “That means there would be basically nothing left for this municipal program.”
The renewable energy fund, established in 2007, receives money from electric service providers that are unable to meet their obligations to source a certain level of renewable power each year. Most years, the fund takes in anywhere from $2 million to $8 million. The money has traditionally supported a handful of renewable energy incentives, and revenues have generally exceeded spending. At the beginning of fiscal year 2024, the fund had a balance of nearly $15.3 million.
Earlier this year, the state energy department started laying out plans to use some of this money to support solar projects developed by municipal governments. Such developments have both financial and environmental benefits, saving money for towns — and thus taxpayers — while cutting greenhouse gas emissions from electricity generation in a region that relies heavily on natural gas to fuel its power plants.
Still, municipal solar projects can be a hard sell for voters in New Hampshire, a state with a reputation for frugality. The state has no sales tax or income tax, so government operations are funded mainly by hefty property taxes. It is also home to many small towns with constrained budgets. Though solar installations can save a town money, voters are generally reluctant to approve the upfront cost, which could increase their property taxes.
“The reality for New Hampshire residents is that municipal budgets are very, very, very tight, and property taxes keep going up,” said Sarah Brock, director of the nonprofit Clean Energy New Hampshire’s Energy Circuit Rider program, which helps towns develop clean energy and energy efficiency projects. “Every year at town meeting, there’s a pretty substantial reluctance to approve money for just about anything.”
In 2024, the state launched the Municipal Solar Grant Program to help towns overcome those hurdles and install solar panels on municipal property. The pilot program has a specific focus on small or economically disadvantaged towns that would have a harder time funding such projects on their own. The initiative uses $1.6 million in funding that the state received through the federal Bipartisan Infrastructure Law, passed in 2021.
Thirty towns applied for the funding through the pilot; 16 were selected to receive grants between $45,000 and $200,000. Staff with the Energy Circuit Riders program identified perhaps 20 more towns that might also be interested in future funding opportunities.
“We had over 50 towns in our active project pipeline that would want to go after this funding,” Brock said. “We know the demand is there.”
The plan was to follow up with a permanent program paid for by the renewable energy fund. In the spring, the state energy department asked for comments on the proposed program and ideas about how to modify the approach used in the pilot.
The annexation of the renewable energy fund, however, could put an end to these plans, advocates said. With only $1 million available each year, there would not be enough money available to continue existing offerings like its nonresidential competitive grant program and rebates for wood pellet stoves at current levels. Adding an entirely new initiative may be a nonstarter.
“No one is telling us the program is dead, but it is possible that it will be impossible to run if there isn’t funding for it,” Brock said.
Neither the office of Gov. Kelly Ayotte nor the state energy department responded to requests for comment about the future of the program.
The first project completed under the pilot was a 26-kilowatt solar array atop the town hall in Kensington, New Hampshire, in the southeastern corner of the state and home to about 2,000 people. Kensington has an annual budget of just $2.6 million, so voters were unlikely to approve a nearly $100,000 investment, even if it promised savings in the long run, said Zeke Schmois, chair of the town’s energy committee. So the local solar boosters turned to the state.
The town received about $92,000 for the project. The final panels went up in early July, making Kensington the first place to complete an installation as part of the grant program.
“This isn’t a solar farm, but it’s huge for a town like ours with such a small budget and such a small population,” Schmois said.
Kensington expects the installation to offset about 70% of the town hall’s annual electricity use, Schmois said. But those savings are just the beginning of the impact: The town historical commission was involved with the approval process and realized that modern solar panels can blend inconspicuously with roofing. The group is now eager to collaborate on future solar projects, Schmois said.
Other towns hope for similar benefits. Dublin, New Hampshire, received a grant of about $43,000 for a solar array that should meet all the town fire station’s power needs once it is installed later this summer, said Susan Peters, the chair of Dublin’s select board and founding member of its energy committee. She hopes the installation’s location along a major state highway will help normalize the idea of solar, and help build support for another project under consideration: a ground-mounted array near a capped landfill.
“The fact that we’re doing this project strengthens people’s interest,” she said.
Rooftop solar costs way more in the United States than it does elsewhere in the world. That’s long been a headache for the sector to navigate. But now with Republicans in Congress killing off the decades-old tax credit for rooftop solar, it’s a life-or-death problem.
So says Andrew Birch, a 25-year industry veteran who’s built a career on cutting solar projects’ “soft costs,” which make up roughly two-thirds of the price of a rooftop solar installation in the U.S. and consist of everything other than equipment costs.
Some of those factors are under a solar company’s control, like how much it spends on acquiring customers and managing projects. Others aren’t, like the expense associated with navigating complex permitting and interconnection processes that differ from city to city and from utility to utility.
Those costs rise when solar systems are accompanied by batteries, something that is becoming increasingly common as households look for backup power and respond to new incentive structures that prioritize storage, as is the case in California, the nation’s largest rooftop solar market.
Big upfront costs are the No. 1 reason Americans decide not to put solar panels on their rooftops. The forthcoming spike in installation costs created by the new GOP megabill will only make that hurdle higher. After this year, households will lose access to tax credits for 30% of the cost of solar, batteries, and other home clean-energy equipment, and companies that offer solar systems under third-party ownership models will face a set of uncertain restrictions that could choke off that part of the market.
In order for the U.S. to keep installing rooftop solar at a healthy rate — something that’s key to combatting climate change and helping people manage rising electricity costs and electrify their cars and homes — the industry needs to figure out how to prevent costs from ballooning once the incentives disappear.
“We’re now being forced to operate as an industry without subsidies,” Birch said. That puts the onus on the industry to both tighten its belt in areas that are under its control and press state lawmakers, local government officials, and utility regulators to reform their parts of the equation.
“We can survive and thrive — if we can reduce soft costs,” he said.
Birch, a native Australian known as “Birchy” in the solar world, is working on just that himself.
He helped launch SolarAPP+, an “instant permitting” software platform being used by more than 160 cities and counties across the U.S. to process solar permits in hours rather than weeks. OpenSolar, the company he co-founded and leads, offers free solar project design and management software to installers, paid for by equipment manufacturers and dealers eager for the increased sales it can bring.
There’s plenty of evidence that lowering these costs is possible: The soft-cost problem is a bit of a uniquely American phenomenon. In other places with high rooftop solar penetration, like Australia, the world’s rooftop solar leader, these costs are far lower.
Solar companies in Australia can quote, sell, and install a 7-kilowatt solar system with a 7 kilowatt-hour battery for about $14,000 in a matter of days, Birch estimated. In the U.S., that same system costs about $36,000, and getting permits and interconnections can take months — long enough to kill a fair number of installs before they can be completed, he said.
When it comes to cutting soft costs, local permitting reform is a big target.
Permitting regulations and processes vary widely across the roughly 23,000 city, county, and other local authorities that have jurisdiction over building permits, electrical code enforcement, and other must-haves for a solar or battery installation. Permitting can add roughly $1 per watt to the cost of a typical solar installation, according to the industry trade group Solar Energy Industries Association (SEIA).
Some do a good job of making the process smooth and straightforward. Others can be far less helpful and efficient. Slow or cumbersome permitting takes a toll on solar installers, stretching the time it takes to complete current projects and move on to the next.
“If you can ensure you’re making it through in three weeks versus three months, you’re operating much more efficiently,” said Barry Cinnamon, CEO of Northern California solar and battery installation firm Cinnamon Energy Systems. On the other hand, “in cities where the permitting is slow, you inevitably get them coming back in two weeks saying, ‘You’re missing a dash in that form — send it back,’ and then two or three weeks later saying, ‘We’re not sure the battery can go in that spot. Try again.’”
It’s hard to standardize permitting across local authorities, which range from well-staffed big-city departments to tiny towns with one or two people working on it. But software that can reliably complete the tasks of permitting officials can save time and reduce errors for big and small permitting authorities alike.
In 2018, SEIA and nonprofit the Solar Foundation launched the Solar Automated Permit Processing initiative and enlisted the U.S. National Renewable Energy Laboratory to develop an automated permitting platform. SolarAPP+ was the result. After pilot tests in 2020 proved it dramatically sped up permitting without sacrificing quality, the platform was made available at large.
Automated permitting turns multiple back-and-forth processes into a “one- to two-page digital form,” Birch said. Code standards groups like Underwriters Laboratories and the International Code Council have signed off on SolarAPP+, and similar automated platforms from startups and from city permitting departments are now providing similar same-day options.
The advantages of instant permitting are so great, Cinnamon said, that he’s stopped doing projects in cities and counties that don’t offer some form of it. With less than six months to finish projects that can secure tax credits, “we don’t have the time” to spend elsewhere, he said.
The next step is to expand instant permitting from hundreds to thousands of cities and counties by taking on statewide permitting reforms, said Nick Josefowitz, CEO of Permit Power, a nonprofit advocacy group.
Over the past several years, states including Democratic strongholds like California and Maryland as well as Republican redoubts like Florida and Texas have adopted solar permitting reform laws, he said. New Jersey lawmakers passed a bill this summer that now awaits Gov. Phil Murphy’s signature.
Reform looks different in every state. California set mandates for cities and counties to use instant permitting, while Texas and Florida required cities and counties to allow licensed and credentialed third parties to issue permits and conduct inspections on homeowners’ behalf. Colorado’s law backed off on mandates but offered incentives for local authorities to deploy instant permitting, while New Jersey’s law would empower a state agency to set up instant permitting for cities and counties to use.
Lowering permitting costs can allow solar installers to cut their prices, which increases their business, spurs more competition, and gives households more options, Josefowitz said. A series of studies this year from Brown University’s Climate Solutions Lab and the Greenhouse Institute found that streamlined and instant permitting in Arizona, Colorado, Illinois, Minnesota, New Jersey, New York, and Texas could result in an additional 2 million home solar installations between now and 2030, saving households a collective $100 billion.
The results are good not just for households and solar installers but for cash-strapped municipalities, said Elowyn Corby, mid-Atlantic regional director for nonprofit group Vote Solar, which advocated for New Jersey’s newly passed reform bill.
“When you put the onus on municipalities to process these permit applications, that’s an enormous drain on their resources as well, especially in lower-income communities where there isn’t as much municipal infrastructure,” she said. “We’re hoping this brings capacity back to local governments.”
Permits aren’t the only solar roadblocks. Utilities also need to approve solar and battery systems at homes connected to their grids before they’re allowed to be turned on. Solar installers have long complained that slow or costly interconnection processes are a significant drag on their bottom lines.
“I’ve heard from some of our installers — and some of the bigger ones — that the interconnection approval process is more of a challenge and a bigger cost than the permitting side,” said Ravi Mikkelsen, CEO of Atmos Financial, a financial technology company that connects lenders with solar installers and customers. “Some utilities are better than others, but across the board, this is a major issue.”
Interconnection rules are complicated, and utilities apply them differently. But reports from solar installers over the years have highlighted problems ranging from lengthy waiting times and restrictions on new solar hookups to exorbitant costs assessed on homes wanting to interconnect.
A lack of state regulator oversight for interconnection policies complicates efforts at reform, Josefowitz said.
Regulators in some states like California set rules for all regulated utilities, but other state regulators don’t. Even those that have set statewide guidelines for utilities have been slow to adopt rules that require them to put in place more streamlined processes or take the latest technology advances into account. A 2023 ranking from Vote Solar and the nonprofit Interstate Renewable Energy Council assessed state adoption of interconnection “best practices.” The groups gave only New Mexico an A grade and six other states B grades, while marking 13 with an F for lacking any statewide standards.
“We need [regulator] rules about when projects can be fast-tracked, what types of systems when and where can be automated and approved by software,” Josefowitz said.
Extreme amounts of rooftop solar can cause problems on power grids designed to carry electrons from big substations to customers.
“But batteries totally change the game on this,” he said, enabling homes to store solar power when utility grids don’t need it and release it when they’re in short supply.
That’s why solar companies ranging from nationwide players like Sunrun to regional and local installers are recasting their business approach to include becoming “virtual power plant” providers — active providers of energy and grid resources that help augment the resources that utilities can bring to bear.
Opportunities to earn money for these services are relatively scarce today. But with Republicans in Congress and the Trump administration making it much more expensive and difficult to build more renewable energy to meet the growing demand for electricity, utilities may be well advised to reduce the barriers to installing solar and batteries that can provide it, Mikkelsen pointed out.
“At $2 a watt, you can bring down the cost of your power, and you can save money on electrification,” he said. But also, “your battery can be used economically much more frequently and becomes super-valuable to the grid. You want to unlock the power of batteries? You fill them with cheaper electrons.”
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