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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.
Plans are in the works to build America’s first new aluminum smelters in nearly half a century. The two facilities, slated to go online in Oklahoma and possibly Kentucky in the coming years, would dramatically boost domestic production of the versatile metal if completed as planned.
But for that to happen, they will first have to secure a steady supply of electricity, at a time when AI data centers and other industrial facilities are competing fiercely for a share of the country’s limited power resources, and as the grid is strained by surging demand.
The smelters proposed by Emirates Global Aluminium and Century Aluminum would be energy hogs. Each plant is expected to produce about 600,000 metric tons of aluminum each year, requiring enough electricity annually to power the state of Rhode Island. That’s because the process of converting raw materials into primary aluminum requires hundreds of megawatts of power running at near-constant rates.
For the economics to pencil out for either facility, that power will need to be cheap. And it will need to be produced from carbon-free sources, like wind or solar, for the aluminum they produce to be more competitive on the global market, which increasingly favors low-carbon metal.
Unfortunately for American aluminum producers, both clean and affordable power are only getting harder to come by.
Electricity demand in the U.S. is rising faster than supply is forecast to grow, which is pushing up prices. Aging grid infrastructure and slow permitting timelines have long delayed the build-out of new power generation. Now the Trump administration and GOP-led Congress are creating additional financial and legal headwinds for wind, solar, and battery storage projects — the only resources that can be built fast enough to meet demand in the near term.
“With clean energy tax credits going away, we can reasonably expect the cost of electricity to go up in all markets,” said Annie Sartor, the aluminum campaign director for Industrious Labs, an advocacy organization. “That’s just profoundly challenging to aluminum facilities that are looking for electricity … especially in a moment when there’s a rush on electricity nationally.”
The deepening power crunch represents a major roadblock in the quest to reshore U.S. manufacturing.
The Trump administration recently raised tariffs on aluminum and steel imports from 25% to 50% to bolster the business case for producing primary metals domestically. It has also preserved a crucial award for Century Aluminum’s smelter that was issued in the final days of the Biden administration. In January, the Department of Energy awarded Century a grant of up to $500 million as part of a federal industrial decarbonization program, much of which has since been defunded.
But to successfully kick-start an American aluminum renaissance, the government and utilities will also need to make larger long-term investments in the nation’s ailing electricity sector, and develop tools that allow smelters to not just take power from the grid, but to help it run more smoothly, experts say.
“Ultimately, this is about energy,” said Matt Meenan, vice president of external affairs for the Aluminum Association, a trade group that supports an “all-of-the-above” approach to electricity sources.
“And until you crack that nut,” he added, “I think we’re going to have a hard time becoming fully self-sufficient for primary aluminum in the U.S.”
Aluminum companies worldwide produced 73 million metric tons of primary, or virgin, aluminum in 2024. The lightweight metal is used to make products as varied as fighter jets, power cables, soda cans, and deodorant. It’s also a key component of clean energy technologies like electric vehicles, solar panels, and heat pumps.
Producing aluminum contributes about 2% of total greenhouse gas emissions every year. The majority of those emissions come from generating high volumes of electricity — often derived from fossil fuels — to power smelters. The smelting process involves dissolving powdery white alumina in a scorching-hot salt bath, then zapping it with electrical currents to remove oxygen molecules and make aluminum.
The United States was once one of the world’s top producers of primary aluminum. In 1980 — the last year a new smelter was built — the nation had 33 operating facilities, many of which relied on cheap power from public hydropower plants. But then industrial electricity rates began to rise after the federal government restructured energy markets in 1977.
Deregulation was “the single most important factor leading to the near total demise of the primary aluminum industry,” the Aluminum Association said in a recent white paper entitled “Powering Up American Aluminum.” The U.S. industry’s downward spiral accelerated further after China joined the World Trade Organization in 2001, leading to a glut of inexpensive Chinese aluminum on the global market.
Today, just four American smelters remain operational. In 2024, they produced an estimated 670,000 metric tons of primary aluminum, or less than 1% of global production. The U.S. mainly makes secondary aluminum from scrap metal, which totaled over 5 million metric tons last year. While secondary production is growing, it can’t fully replace the need for strong and durable primary aluminum.
“There’s always going to be a role for primary aluminum,” Meenan said. “And we do think having smelters here is really important.”
Century Aluminum and Emirates Global Aluminium both say their new smelters will mark a new beginning for the U.S. primary-aluminum sector. The two facilities would together nearly triple the nation’s primary-aluminum capacity when they come online, potentially around 2030.
Century Aluminum first unveiled plans for its smelter in March 2024, after the Biden-era Department of Energy launched a $6 billion initiative to modernize and decarbonize America’s industrial base. As part of the award process, Century said its Green Aluminum Smelter could run on 100% renewable or nuclear energy and would use energy-efficient designs, making it 75% less carbon-intensive than traditional smelters.
At the time, the Chicago-based manufacturer identified northeastern Kentucky as its preferred location for the smelter, though the company was also evaluating sites in the Ohio and Mississippi river basins. More than a year later, Century still hasn’t picked a final project site for the $5 billion smelter — because it hasn’t yet locked down its power supply.
Electricity isn’t available at the fixed long-term price that smelters need to ensure profitability and pay back billions of dollars in construction costs, Matt Aboud, Century’s senior vice president of strategy and business development, said in May at a global aluminum summit in London, Reuters reported.
“We remain really excited about the project,” Jesse Gary, Century’s president and CEO, said on a May 7 earnings call. “The next two key milestones are to finalize negotiations of the power arrangements, and then following from that … we’ll be making a site selection.”
The Aluminum Association estimates that manufacturers would need a 20-year power contract at or below $40 per megawatt-hour to justify investing in a new smelter at today’s aluminum prices. Restarting the nation’s fleet of idled smelters, which represent 601,500 metric tons in primary capacity, would require a similar arrangement.
Currently, power-purchase agreements for U.S. renewable energy projects are in the range of $50 to $60 per MWh — a significant difference for these power-hungry facilities. Tech giants like Microsoft have signaled their willingness to pay north of $100 per MWh for electricity from nuclear and fossil-gas plants to fuel their data centers, giving those firms an advantage over price-sensitive buyers in the race for electricity.
Meanwhile, in Oklahoma, Emirates Global Aluminium is advancing its $4 billion smelter project with the promise of significant financial support from taxpayers and utility customers.
The Abu Dhabi-based conglomerate in May signed a nonbinding agreement to build the smelter with the office of Republican Gov. J. Kevin Stitt, a deal that includes over $275 million in incentives, including discounts for power. The manufacturer and governor’s office are working to establish a “special rate offer” from the Public Service Co. of Oklahoma — a subsidiary of utility giant AEP — for the new facility.
Simon Buerk, EGA’s senior vice president for corporate affairs, said that Oklahoma’s “energy abundance” was a key factor in selecting the state for the new aluminum smelter.
More than 40% of Oklahoma’s annual electricity generation comes from wind turbines spinning on open prairies, while about half the state’s generation comes from fossil-gas power plants. Last month, the Public Service Co. acquired an existing 795-MW gas plant just south of Tulsa to meet the rising energy needs of its customers, including potentially EGA.
Buerk said EGA and the utility are in “advanced negotiations” to finalize a competitive power contract. One option the groups are considering is a tariff structure that gives the smelter dedicated long-term access to a proportion of renewable energy, equal to 40% of the smelter’s needs. The smelter’s annual power mix “will be based on EGA’s decarbonisation objectives, market dynamics, and market demand for low-carbon aluminum,” he said by email.
Outside the United States, nearly all primary aluminum smelters receive some form of government backing in the countries where they operate — typically by ensuring access to affordable energy, said Sartor of Industrious Labs.
She pointed to Canada, the largest supplier of U.S. aluminum imports. Smelters in Quebec draw from the region’s abundant hydropower resources, which are operated by the government-owned entity Hydro-Quebec. The price of electricity that producers pay is often tied to the price of aluminum on commodities markets, so that smelters pay less during lean times and more when the market recovers.
“The industry functions through government support all over the world, and we should be looking at those models and finding one that fits us here,” said Sartor.
Manufacturers and utilities can also structure power-supply agreements that enable smelters to benefit, rather than strain, the grid, said Anna Johnson, a senior researcher in the industry program at the American Council for an Energy-Efficient Economy.
“When we think about how to address the challenge of procuring large amounts of clean power, one of the first tools we think about is, what can we do on the demand side to mitigate that load and make sure that the demand of these facilities is avoiding times of peak stress?” she said.
In New Zealand, for example, Rio Tinto’s Tiwai Point smelter receives financial incentives to curb its electricity use — and therefore lower its aluminum production — during dry seasons, when hydropower resources can become critically low. In Australia, the aluminum giant Alcoa is participating in a program that turns one of its smelters into an emergency resource when the grid is overly stressed. The Australian government pays Alcoa to halt production on some of its aluminum-making potlines for about an hour at a time.
In the U.S., other types of industrial plants — including a titanium-melting plant in West Virginia — are using behind-the-meter solar power and battery storage systems, so that the facilities are primarily drawing from the electrical grid only during off-peak hours.
Strategies like these that reduce electricity rates are especially crucial now that the development of cheap, renewable energy is set to slow in the United States. But manufacturers will still need access to new carbon-free electricity sources in order to produce the cleaner aluminum that customers are increasingly demanding, Sartor said.
“When [companies] build a new facility, they’re building it for 50 or 100 years,” she said. Even as the Trump administration winds back the clock on U.S. climate action, smelters “need to find clean power as a matter of international competitiveness.”
New York just took a big leap toward zero-emissions buildings.
On July 25, the State Fire Prevention and Building Code Council approved an all-electric building standard, making New York the first state in the nation to prohibit gas and other fossil fuels in most new buildings. Legislators and climate advocates celebrated the move, which had been mandated under the pathbreaking 2023 All-Electric Buildings Act.
“I’m excited that we are finally tackling, statewide, our largest source of fossil-fuel emissions,” said state Assemblymember Emily Gallagher, who sponsored the 2023 legislation. Buildings account for 31% of the Empire State’s planet-warming pollution.
New York is forging ahead on building decarbonization at the same time the federal government is backtracking, yanking support for renewable power and home energy efficiency and providing the fossil-fuel industry with new subsidies.
The state’s rules will apply to new structures up to seven stories tall and, for commercial and industrial buildings, up to 100,000 square feet beginning Dec. 31, 2025. Buildings bigger than that will need to be built all-electric starting in 2029. The new code will spur installations of heat pumps and heat-pump water heaters — ultra-efficient electric appliances that are good for the planet and, typically, pocketbooks.
The council left room for exceptions, though, including new laboratories, crematoriums, restaurants, and large buildings whose owners can prove the grid isn’t ready to accommodate their sizable all-electric heating needs. Michael Hernandez, a policy director at electrification advocacy nonprofit Rewiring America, said he doesn’t think the exemptions will eat away at the code’s efficacy, however.
With the rules finalized, “I’m relieved,” Gallagher told Canary Media. Fossil-fuel interests — such as the utility front group, New Yorkers for Affordable Energy — “really worked overtime to try to stop this,” she said.
The new regulations come on the heels of a recent legal victory: On July 23, a federal district court in New York upheld the state’s ability to implement the All-Electric Buildings Act.
The groups challenging the law in court — including the New York State Builders Association, National Association of Home Builders, National Propane Gas Association, and a few local union chapters for plumbers and electricians — alleged that it’s preempted by the federal Energy Policy and Conservation Act, the same justification used to overturn Berkeley, California’s pioneering ban on gas hookups in new construction. The New York judge was unconvinced by this argument, noting that the Berkeley decision relied on “deficient interpretations” of terms like “energy use,” and is “simply not persuasive.”
Opponents of the standard haven’t quit, though. An industry coalition that includes many of the organizations that brought the lawsuit sent a letter on June 26 to U.S. Attorney General Pam Bondi requesting that the Department of Justice move to block the code from taking effect. Michael Fazio, lead author of the letter and the executive director of the New York State Builders Association, declined to comment on the request’s status to Canary Media.
The state’s new energy code is expected to raise the cost of residential construction but also lower energy bills substantially for homeowners and renters, making it cost-effective overall with a payback of 10 years or less, according to a report commissioned by the New York State Energy Research and Development Authority. Over 30 years, households are expected to save an average of about $5,000 due to a 17% reduction in energy use.
Other research indicates all-electric construction is typically less expensive than that for buildings equipped to burn gas or fuel oil. Electric-only projects allow developers to forgo installing costly fossil-fuel infrastructure alongside the electrical systems requisite in modern buildings. A 2022 analysis by the decarbonization nonprofit New Buildings Institute, for example, found that building an all-electric single-family home in New York costs about $8,000 less.
The all-electric code will improve air quality by reducing reliance on fossil-fuel-fired boilers, furnaces, water heaters, and stoves. These conventional appliances spew harmful byproducts such as carbon monoxide, particulate matter, benzene, nitrogen oxides, and more, which can cause respiratory and cardiovascular issues — to lethal effect. In 2017, fossil-fuel use from New York buildings caused $21.7 billion in health impacts and nearly 2,000 premature deaths, more than in any other state.
Gas stoves, typically the largest sources of exposure to indoor air pollutants, are linked to nearly one in five asthma cases in children in New York, according to a 2022 study. “Places like the Bronx have the highest rates of childhood asthma in the country,” said Jumaane Williams, public advocate of New York City, in a call with reporters on Friday. “We know this is a life-and-death situation.”
“Numerous studies … show that both air pollution and climate change disproportionately impact low-income communities and communities of color,” said Lonnie Portis, director of policy and legislative affairs at the community-based nonprofit WE ACT for Environmental Justice. The state’s all-electric building standard “is a significant step forward for environmental and climate justice.”
The new rules will not only get heat pumps into new construction but help boost adoption in existing homes, according to Jay Best, CEO of home energy-efficiency company Green Team Long Island.
“We’re always telling people about heat pumps … solutions that are going to save them money and make their homes more comfortable,” Best told Canary Media. “But people are apprehensive because it’s something they’re not used to,” despite heat pump units outselling gas furnaces nationally.
“The code … sets a bar; this is the minimum that the state says is legal to build,” Best said. That “changes people’s view of the technology.”
Alex Beauchamp, Northeast region director at Food & Water Watch, underscored that passing the All-Electric Buildings Act and getting it into the state code was a victory of David-and-Goliath proportions, with “fossil-fuel companies, plus the gas utilities, plus big real estate” rallied in opposition, he said.
“When New Yorkers come together … we can win even in the face of opponents with an almost-limitless budget,” he said. “That is how we won this bill. It’s also how we are going to continue the fight to get fossil fuels out of all the existing buildings in the state.”
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.
Five years ago, B2U Storage Solutions proved that old EV batteries could hook up to the grid to store clean energy, safely and cheaply. Now the company is taking the concept to Texas.
B2U just broke ground on a second-life grid battery project in Bexar County, near San Antonio, the company told Canary Media. In the next 12 months, B2U will complete four projects in the region, totalling 100 megawatt-hours of storage, CEO Freeman Hall said. The move marks a major expansion for the scrappy innovator, at a time of increased interest in the value of used EV batteries.
On paper, it makes perfect sense: Putting old EV batteries to work on the grid tackles the waste stream created by the growing adoption of EVs while expanding clean energy storage at a discount compared to brand-new lithium-ion batteries. But delivering on the concept efficiently and safely is much harder in practice, and after years of trying, the industry has only installed a handful of utility-scale grid batteries.
B2U stores up to 28 MWh at its first project, in Lancaster, California, and also developed two other smaller facilities in that state. Another company, Element Energy, built a record 53-MWh second-life storage plant in Texas last year. Earlier this summer, lithium-ion recycling startup Redwood Materials beat that record: It unveiled a second-life battery business that includes a 63-MWh storage plant to serve an on-site data center in the Nevada desert.
B2U’s new portfolio won’t set any individual records, but it could prove out the repeatability of the second-life model. In developing for the Texas market, B2U focused on areas near population centers that face transmission constraints. It designed the projects as 10-MW systems with a little over two hours of discharge at full capacity, allowing them to qualify for a fast-track permitting program in the grid managed by the Electric Reliability Council of Texas, or ERCOT.
Once built, the batteries can arbitrage from cheap hours when the state’s massive solar fleet is cranking to peak-demand hours when electricity prices shoot up. Batteries, with their ability to instantly inject or absorb power, can also compete to provide various other forms of grid-stabilizing services in the ERCOT markets.
“Texas has been a very strong market with ever more volatility,” Hall said. “And that’s what storage does well, is take advantage of volatile conditions.”
The expansion draws on the company’s five-year track record of operating second-life batteries on the grid, and making money at it.
One lingering question for the sector has been how long the previously worn-down packs would survive when used for daily charging and discharging. The Lancaster project was designed to eke out 2,000 cycles from its initial batch of early Nissan Leaf batteries, Hall said; those packs have now exceeded that target.
Crucially, the equipment has not required much upkeep: Of the 2,000 battery packs that B2U operates so far, technicians have only had to pull out a single-digit number of them for maintenance, Hall noted. That has given the company confidence to dispatch the batteries a bit more intensely.
“We’ve got all these guardrails and real-time monitoring of the batteries that ensure safety, but we’re not as concerned about degrading the batteries,” Hall said. “They’re turning out to be pretty strong workhorses that don’t degrade as people thought they might.”
B2U said its first project, built in 2020, cost about $200 per kilowatt-hour, which at the time offered a roughly one-third discount compared to new battery systems. Today, new lithium-ion enclosures have come down to $150 to $180 per kilowatt-hour, Hall said, and B2U can deliver at half that rate based on the savings from used batteries. Accounting for additional costs associated with permitting, interconnection, and installation, a finished project comes in 30% to 40% cheaper than a new lithium-ion facility would, he added.
B2U has gotten this far with just $20 million raised in an extended Series A funding round, and another $8 million from the founders and friends. Hall built his California projects on the company’s balance sheet to prove out the concept, which was quite risky for most investors at the time. Consequently, B2U has reaped all the profits from those early investments.
Now, though, B2U has far less cash to throw at its projects than newly minted second-life competitor Redwood Materials. That company was founded by former Tesla Chief Technology Officer JB Straubel, a certified celebrity of the battery engineering world who swiftly raised $2 billion to tackle battery recycling. But Hall found Redwood’s arrival onto the scene more encouraging than intimidating.
“For the North American recycler that has raised the most capital and has been hyping the recycling opportunity the most to now make a big splash and say that they believe that the repurposing market can grow faster and generate more revenue than their core business — that’s quite the validation point,” Hall said.
Going forward, B2U has raised a fund to own its operating projects with a mix of outside equity, debt, and tax equity. That means Hall can sell off the projects to the fund (although B2U will keep a stake in them), freeing up money for new business activities. This sets the company up for faster growth than if it continued to support all its projects with its own corporate balance sheet.
Still, B2U maintains a rare distinction in the cleantech-startup universe: For relatively minor funds raised, the company has built real things that generate profits. Cleantech venture capitalists have heaped far more cash on pre-revenue companies chasing far more dubious propositions.
Five years ago was like “the first at-bat of the first inning” for second-life storage, Hall said, meaning he had a lot to prove in the field to dispel investor concerns about the novel technology. He took it slow on fundraising while he tackled those proof points.
“We’ve been very disciplined in deploying capital. That tends to be viewed by investors as a good thing, but the opportunity is such a big one right now that we need to do what’s smart for shareholders — and staying small probably no longer is as smart,” he reflected. “It’s probably time for us to grow, to take advantage of the opportunity in front of us.”
The starting gun for the long-promised U.S. nuclear renaissance might have just gone off.
The U.S. Nuclear Regulatory Commission announced late last week that it has granted several key approvals that Holtec International needs to restart Michigan’s 800-megawatt Palisades Nuclear Plant three years after the facility shut down. Although the project still needs to clear some federal hurdles, the NRC’s action signals its intention to give Holtec the full go-ahead.
If Holtec succeeds in bringing Palisades back online this year as promised, it would be the first nuclear plant in the U.S. to restart after being closed down. Remarkably, it would be just the second or third reactor to come back online in the global history of civilian nuclear power.
Holtec President Kelly Trice praised the NRC’s move in a statement, calling it “an unprecedented milestone in U.S. nuclear energy.” The company expects the plant to come back online before the end of the year — an extremely ambitious target given the uncharted regulatory territory of a reactor restart and the industry’s history of construction delays.
Located on Lake Michigan and a two-hour drive from Chicago, the Palisades plant started producing electricity on New Year’s Eve 1971 and was shuttered a half-century later in May 2022 by utility Entergy because of cost issues. It was America’s eighth-oldest nuclear plant at the time of its closing, with a troubled history of temporary shutdowns due to equipment failures. Although its performance improved in the later years of the plant’s operation, Palisades closed 11 days ahead of its scheduled shutdown because of a reliability issue.
Holtec — whose main lines of business are decommissioning reactors and managing nuclear waste — bought the plant in June 2022. But just weeks into the decommissioning process, it made the surprise revelation that it intended to revive the plant instead. Up until that point, Holtec had no experience in constructing, operating, or restarting a nuclear power plant.
Despite that lack of experience, the relatively speedy NRC approval means that Holtec can now reinstall uranium fuel in the reactor as soon as August and begin the work of restarting the complex nuclear facility. About 600 full-time workers are currently employed at the plant.
Palisades is not the only shuttered reactor that’s being considered for reopening as part of the U.S. strategy to jump-start its flatlined nuclear industry. Last year, Microsoft announced a multibillion-dollar plan with plant operator Constellation Energy to restart Three Mile Island Unit 1 in Pennsylvania by 2028; it had been decommissioned in 2019 because of poor economics. Power provider NextEra Energy is also weighing reanimating Iowa’s only nuclear plant, the 50-year-old reactor at the Duane Arnold Energy Center, which closed in 2020 because of storm damage and cost issues.
Nuclear power has newfound social license in the U.S. Citizen support has climbed in recent years. The U.S., along with more than 20 other countries, vowed to triple nuclear power capacity by 2050 during the COP28 global climate conference in 2023.
Nuclear is now viewed by many as crucial to meeting the soaring electricity demand that’s being driven by an AI-spurred data-center frenzy along with the electrification of transportation and industry. Tech giants in particular are hungry for the clean, firm, 24/7 power that nuclear plants can provide, as their data centers crave round-the-clock electricity.
Aside from renaming post offices, bolstering nuclear power is the rare type of policy that can gain bipartisan agreement — the Biden administration initiated this atomic energy rally, and the Trump admin is maintaining its momentum.
Trump’s recent set of executive orders on nuclear power sped up the licensing process and minimized regulatory burdens, all in the service of fostering American “energy dominance.”
So it’s a good time to be a nuclear plant operator. Notoriously expensive nuclear reactors can now claim a bundle of incentives and subsidies. Consider all the goodies Holtec will be able to take advantage of.
Not everyone is enthusiastic about the Palisades reactor restart.
Kevin Kamps of anti-nuclear organization Beyond Nuclear told Canary Media that the NRC is “under tremendous pressure” and “bowing to Holtec’s schedule” as it “pushes the envelope on risk.”
He wrote in a statement, “The zombie reactor restart scheme is unneeded, insanely expensive for the public, and extremely high risk for health, safety, security, and the environment.”
The advocacy organization claims that Holtec “neglected critical safety maintenance from 2022 to 2024.” Beyond Nuclear is particularly worried about the impact of corrosion on a massive, expensive, and critical part of the reactor: the steam generator.
There are thousands of steam generator tubes in a pressurized water reactor like Palisades. In instances of corrosion, they are routinely re-sleeved or plugged, but Arnie Gundersen, a former nuclear engineer and whistleblower, has testified in NRC proceedings that “the failure of a single tube would result in a release of radioactivity to the environment” and “a cascading failure of tubes could cause a reactor core meltdown and catastrophic release of hazardous radioactivity.”
Beyond Nuclear intends to appeal the NRC’s green light for restart once it’s finalized.
Unfortunately, restarting a few vintage plants would contribute little toward the broader goal of building hundreds of gigawatts of low-cost nuclear power. There just aren’t enough eligible decommissioned nuclear plants to make much of a difference.
Nuclear enthusiasts rave about the prospects for small modular reactors and other advanced reactors, with their novel designs, coolants, and fuels. But while those technologies are engineering marvels, they won’t do anything to drive down costs in the next few years.
A more direct solution to growing the U.S. nuclear fleet (and keeping up with a surging China) would be to build tried and tested models of big, traditional nuclear plants over and over again. Venture capital-funded consortia such as The Nuclear Co. and other parties are planning to do just that: deploy fleets of full-scale, licensed, and standardized reactor designs on sites with existing construction and operating licenses. It’s a strategy to avoid the first-of-a-kind shock of building a newer generation of reactor like Georgia’s Vogtle 3, which was years late and billions over budget.
Meanwhile, the NRC’s forthcoming approval of the Palisades recommissioning is a morale booster for the U.S. nuclear industry, which has needed to put some wins and megawatts on the board.
A correction was made on July 30, 2025: This story originally misstated which federal tax credits the Palisades plant would be eligible for if it restarted. The plant would be eligible for the 45Y production tax credit for new nuclear, not the 45U production tax credit for existing nuclear.
The country’s biggest power market is caught in a trap of its own making — and the more than 65 million people from the mid-Atlantic coast to the Great Lakes who rely on it for electricity will pay the price.
Last week, PJM Interconnection announced a new record in its annual capacity auction, the means by which the grid operator secures the resources it needs to maintain a reliable transmission grid across 13 states and Washington, D.C. Prices increased to $16.1 billion, up from last year’s already record-setting $14.7 billion and an eightfold increase compared to $2.2 billion for the 2023 auction.
Prices would have spiked even further if not for a cap instituted as part of a settlement agreement with Pennsylvania Gov. Josh Shapiro (D) reached in April. Even so, PJM estimates that residential customers could see utility bills rise by up to 5% in the years to come, or more than $100 in annual household costs — rate hikes that will occur on top of bill increases just now starting to hit customers as the result of last year’s auction.
These spiraling costs have galvanized both Republican and Democratic governors of states served by PJM to demand immediate reforms. “With billions of ratepayer dollars and the stability of our grid at stake, it is critical that PJM take concerted, effective action to restore state and stakeholder confidence,” governors from Delaware, Illinois, Kentucky, Maryland, Michigan, New Jersey, Pennsylvania, Tennessee, and Virginia wrote in a July letter to the grid operator.
But it’s unclear whether PJM can quickly solve the problems that are driving up costs. That’s because the core issue — barely any new generation capacity has been able to connect to the grid — will take years to resolve.
“You have a massive technical problem, which is the challenge to fix this broken interconnection queue and bring new resources online in a time of global uncertainty with tariffs, inflation, and supply chain issues that are slowing the construction and development of new generation resources,” Jon Gordon, a director at clean-energy trade group Advanced Energy United, said in a webinar last week dissecting the grid operator’s current predicament.
PJM isn’t the only U.S. regional grid operator struggling to get new power plants, solar and wind farms, and grid-scale batteries connected. But it has one of the worst track records, with projects taking an average of more than five years to move through the steps required to plug into the grid. Advanced Energy United gave PJM a D- score for its interconnection processes in a 2024 survey, the lowest of any U.S. grid operator.
The consequence has been a paltry amount of new generation and battery storage. PJM reported last week that about 2.7 gigawatts of new generation and “uprates” — existing projects that have augmented their capacity — had been added to its available pool of resources since its last auction. That’s the first such increase in the past four auctions, and a fraction of PJM’s roughly 180 GW of generation capacity.
Nor is PJM winning high marks for its efforts to fix its interconnection backlog. Critics say the grid operator has stalled on reforms that others have undertaken, including changes mandated by the Federal Energy Regulatory Commission. Last week, FERC ordered PJM to rework “conceptual proposals” that it said fail to meet federally mandated deadlines for implementing interconnection reforms.
In 2022, PJM froze the process for new projects seeking interconnection to deal with a backlog stretching back to the late 2010s. That backlog won’t be cleared until the end of 2026, leaving hundreds of gigawatts of prospective new supply in limbo.
“The market can’t work until the interconnection queue delay is fixed,” Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based utility customer watchdog group, said during last week’s webinar. An April study from research firm Synapse Energy Economics found that comprehensive interconnection reforms at PJM could save customers an average of $505 per year in utility bills and cut commercial and industrial electricity costs by 23% through 2040.
PJM noted in last week’s press release that it has processed more than 60% of the backlog in its interconnection queue. It also highlighted that more than 46 GW of “already-approved resources have yet to be built,” with many projects “navigating challenges outside PJM’s scope, such as permitting timelines, supply chain constraints and evolving project economics.”
Gordon pointed out that PJM’s interconnection bottlenecks have put energy developers in a very tough position. Nearly 95% of the grid operator’s backlog consists of solar, wind, and battery projects, and “many of those projects came into the queue pre-COVID,” he said.
Since then, interest rates have gone up dramatically, equipment costs have risen, and the Trump administration and Republicans in Congress have undone federal incentives and policies supporting clean energy growth. “Whatever those developers were thinking about those projects back then, the economics, everything has completely changed,” he said.
The forecasted demand for electricity on PJM’s grid has also increased enormously in the past four years. The AI bubble has driven up PJM’s projected load growth by 5.5 GW from last year’s auction, largely due to new plans for data centers in the region.
But PJM may not be applying the proper amount of skepticism to calculating future demand growth from data centers, said Abe Silverman, an attorney, energy consultant, and research scholar at Johns Hopkins University.
Many data center developers are seeking interconnection in multiple states for duplicative project proposals, he noted. Other U.S. grid operators are “doing a much better job trying to get a handle on the data center load growth,” including winnowing out speculative or duplicative requests, he said during last week’s webinar.
Without such safeguards, PJM runs the risk of overestimating the amount of new generation it will need to meet future demand, which will drive up prices, Silverman said. “If you believe the PJM load forecast, we need to add five nuclear units’ worth of generation to the market every year between now and 2030. And that’s just an enormous challenge, both financially and logistically.”
In the face of these issues, PJM has largely emphasized the need to keep fossil-fueled power plants online and has blamed state clean-energy policies for driving coal-fired power plants to close prematurely.
That argument has been echoed by Todd Snitchler, CEO and president of the Electric Power Supply Association, a trade group representing power plant operators with a preponderance of fossil-gas power plants in their portfolios.
“In recent years, a combination of state and federal policy shifts and poor market signals led to the premature retirement of essential generation,” Snitchler said in a statement after this month’s auction. “Now, as demand grows and supply tightens, we can’t ignore the consequences of past decisions, and we must accept that reliability comes at a cost.”
About 34 GW of coal capacity have retired across PJM since 2013, according to federal data. PJM’s independent market monitor forecast last year that as much as 58 gigawatts of generation will be retired by 2030.
But Citizens Utility Board has emphasized that those retirements are happening in both Republican-led states without clean-energy and climate mandates, including Ohio and West Virginia, as well as in Democrat-led states such as Maryland and New Jersey, indicating that state policies aren’t the chief driver. The main reason coal plants are closing is that they are increasingly unable to compete in energy markets against cheaper gas-fired power plants, renewable energy, and batteries.
Growing power demand is starting to slow the pace of closures. PJM noted last week that 1.1 GW of power plants have withdrawn their retirement plans since last year’s auction. PJM has also forced fossil-fueled power plants in Maryland that were set to close this year to remain open to maintain grid reliability.
The Trump administration may cite PJM’s growing capacity problems to justify using emergency federal powers to require aging fossil-fueled power plants to remain running. The Department of Energy has already used those powers to demand that a coal plant in Michigan stay open, as well as an oil- and gas-fired power plant in Pennsylvania — a move that PJM has publicly supported and that climate and consumer advocates are challenging.
At the same time, PJM has yet to advance near-term options for bringing power online quickly, Summers said. PJM’s proposal to reuse the grid connections left open at retiring plants for new resources, such as batteries, is still awaiting FERC approval, she said.
In February, FERC approved PJM’s plans to revamp another process known as “surplus interconnection service,” which allows existing projects to add new technologies to boost their grid value — for example, adding batteries to wind and solar farms. But the changes have not yet led to new capacity being brought into the market, Summers said.
Meanwhile, PJM’s attempt to fast-track new gas-fired generation won’t help in the near term, Summers said. In May, the grid operator announced 51 new projects selected through its Reliability Resource Initiative, which allows projects not already in the interconnection queue to propose additional resources to meet capacity needs. But most of the 9.4 GW of capacity secured through that process — and all of the newly built gas-fired power plant capacity — isn’t scheduled to be online until 2030 or later.
That’s not surprising. Major manufacturers have reported multiyear backlogs for gas turbines, restricting developers’ ability to add more capacity beyond what’s already in the works. These bottlenecks are likely to hamper similar fast-track efforts being undertaken by grid operators Midcontinent Independent System Operator and Southwest Power Pool.
Accelerating resources that can actually be built in the next two years — like solar and batteries — would be a better strategy to reduce costs, Silverman said.
“Prices are increasing right now because we don’t have enough supply,” he said. “We really have choked off that next generation of projects that should be coming in and taking those positions in the market.”
The rooftop solar industry is facing an unprecedented crisis. Utilities are cutting incentives. Major residential solar installers and financiers have gone bankrupt. And sweeping legislation just passed by Republicans in Congress will soon cut off federal tax credits that have supported the sector for 20 years.
But the fact remains that solar panels — and the lithium-ion batteries that increasingly accompany them — remain the cheapest and most easily deployable technologies available to serve the ever-hungry U.S. power grid.
Sachu Constantine, executive director of nonprofit advocacy group Vote Solar, thinks that the rooftop solar and battery industries can survive and even thrive if they focus their efforts on becoming “virtual power plants.”
Hundreds of thousands of battery-equipped, solar-clad homes across the country are already storing their renewable energy when it’s cheap and abundant and then returning it to the grid when electricity demand peaks and utilities face grid strains and high costs — in essence, acting as “peaker” power plants.
In places like Puerto Rico and New England, these VPPs have demonstrated their worth in recent months, preventing blackouts and lowering costs for consumers, and the approach could be scaled up dramatically. “If we do that, despite the One Big Beautiful Bill, despite the headwinds to the market, there is space for these technologies,” Constantine said.
Right now, there aren’t many other options for meeting soaring energy demand, he added. The megabill signed by President Donald Trump this month undermines the economics of the utility-scale solar and battery installations that make up the vast majority of new energy being added to the grid. And despite the Trump administration’s push for fossil fuels, gas-fired power plants can’t be built fast enough to make up the difference.
Meanwhile, the U.S. power grid has not expanded quickly enough, increasing the risk of outages and subjecting Americans to the burden of rising utility rates, Constantine said. State lawmakers and utility regulators are under growing pressure to find solutions.
Solar and batteries, clustered in small-scale community energy projects or scattered across neighborhoods, may be “the only viable way to meet load growth” from data centers, factories, and broader economic activity, Constantine said. And by relieving pressure on utility grids, they can help bring down costs not just for those who install them, but for customers at large.
This summer has brought new proof of how customers can turn their rooftop solar systems and batteries to the task of rescuing their neighbors from energy emergencies. Over the past two months, Puerto Rico grid operator LUMA Energy has relied on participants in its Customer Battery Energy Sharing program to prevent the grid from collapsing.
“Last night we successfully dispatched approximately 70,000 batteries, contributing around 48 megawatts of energy to the grid,” LUMA wrote in a July 9 social media post in Spanish. Amid a generation shortfall of nearly 50 MW, that dispatch helped avert “multiple load shedding events” — the industry term for rolling blackouts.
Puerto Ricans have been installing solar and batteries at a rapid clip since 2017, when Hurricane Maria devastated the island territory’s grid and left millions of people without power, some for nearly a year.
“There were tens of thousands of batteries already there that just needed to get connected in a more meaningful way,” said Shannon Anderson, a policy director focused on virtual power plants at Solar United Neighbors, a nonprofit that helps households organize to secure cheaper rooftop solar. “The numbers have been really proven out this summer in terms of what it’s been able to do.”
Puerto Rico’s VPPs are managed by aggregators — companies that install solar and battery systems and control them to support the grid. Tesla Energy, one such aggregator, provides live updates on how much the company’s Powerwall batteries are contributing to the system at large.
The impacts of distributed solar and batteries aren’t always so easy to track — but clean-energy advocates are busy calculating where they’re making a difference.
During last month’s heat wave across New England, as power prices spiked and grid operators sought to import energy from neighboring regions, distributed solar and batteries reduced stress on the grid. Nonprofit group Acadia Center estimated that rooftop solar helped avoid about $20 million in costs by driving down energy consumption and suppressing power prices.
A good portion of that distributed solar operates as part of the region’s VPPs. The ConnectedSolutions programs run by utilities National Grid and Eversource cut demand by hundreds of megawatts during summer heat waves. And Vermont utility Green Mountain Power has been a vanguard in using solar-charged batteries as grid resources at a large scale, in concert with smart thermostats, EV chargers, and remote-controllable water heaters. All told, that scattered infrastructure gives the company 72 extra megawatts of capacity to play with during grid emergencies.
Mary Powell, who led Green Mountain Power’s push into VPPs before that term had caught on, left to become CEO of Sunrun, the country’s largest residential solar installer, in 2021. Choosing to hire Powell indicated the company’s growing interest in becoming something of a solar-powered utility.
This summer, Sunrun dispatched hundreds of megawatts from more than 130,000 batteries across California, New York, Massachusetts, Rhode Island, and Puerto Rico. It recently expanded into Texas’ competitive energy, in partnership with Tesla.
“We are living in the future of virtual power plants in places like Puerto Rico, and California, and New England, and increasingly Texas,” said Chris Rauscher, Sunrun’s head of grid services and electrification. “It’s just about other states putting that in place in their territories and letting it run.”
Sunrun, Vote Solar, and Solar United Neighbors have been working for the last year to advance state policies that support VPPs. So far this year, the groups have promoted model VPP legislation in states including Illinois, Minnesota, New Mexico, Oregon, and Virginia.
In May, Virginia passed a law requiring that utility Dominion Energy launch a pilot program to enlist up to 450 megawatts of VPP capacity, including at least 15 MW of home batteries, Anderson said.
The legislative effort has had less luck in New Mexico and Minnesota, where bills failed to advance, Anderson said. In Illinois, a proposed bill did not pass during the regular legislative session, but advocates hope to bring it back for consideration during the state’s “veto session” this fall, she said.
A lot more batteries are being added to rooftop solar systems in Illinois, Anderson noted — a byproduct of the state clawing back net-metering compensation for solar-equipped customers starting this year. Similar dynamics have played out in Hawaii and California after regulators reduced the value of solar power that customers send back to the grid, making batteries that can store extra power and further limit customers’ grid consumption much more popular.
Rooftop solar advocates have fought hard to retain net-metering programs across the country. But Jenny Chase, solar analyst with BloombergNEF, noted that most mature rooftop solar markets have shifted away from rewarding customers for sending energy back to the grid at times when it’s not needed.
“In some ways that’s justified, because net metering pushes all responsibility and cost of intermittency onto the utility,” she said.
VPPs flip this dynamic, turning rooftop solar and batteries from a potentially disruptive imposition on how utilities manage and finance their operations to an active aid in meeting their mission of providing reliable power at a reasonable cost. Utilities have traditionally been leery of trusting customer-owned resources to meet their needs. But under pressure from lawmakers and regulators, they’re starting to embrace the possibilities.
In Minnesota, utility Xcel Energy has proposed a “distributed capacity procurement” program that would allow it to own and operate solar and batteries installed at key locations, letting the company defer costly grid upgrades. Rooftop solar advocates have mixed feelings about the proposal, given their longstanding complaints about Xcel’s track record of making it more difficult for customers and independent developers to build their own solar and battery systems.
Similar tensions are at play in Colorado, where Xcel is under state order to build distributed energy resources like rooftop solar and batteries into how it plans and manages its grid. This spring, Xcel launched a project with Tesla and smart-meter company Itron aimed at “taking these thousands of batteries we have connected to this system over time and [being] able to use them to respond to local issues,” Emmett Romine, the utility’s vice president of customer energy and transportation solutions, told Canary Media in an April interview.
But waiting for utilities to deploy the grid sensors, software, and other technology needed to perfectly control customers’ devices runs the risk of delaying the growth of VPPs, Anderson said. Simpler approaches like those being taken in Puerto Rico — where aggregators manage VPPs — can do a lot of good quickly. “Once you get that to scale, there will be a lot of learnings for the next stage,” she said
State- and utility-level incentives that encourage individuals to participate in VPPs are also a vital countermeasure against the damage incurred by the “big, beautiful bill” passed by Republicans this month, Anderson said. Under that law, households will lose a 30% tax credit that offsets the cost of solar, batteries, and other home energy systems by the end of this year.
However, companies such as Sunrun and Tesla will retain access to tax credits for solar systems that they own and provide to customers through leases or power purchase agreement structures, as long as they begin construction by mid-2026 or are placed in service by the end of 2027. And tax credits for batteries remain in place until 2033 for these companies.
VPP programs can’t make up for the loss of the tax credit for customers who haven’t yet installed solar or batteries, Anderson said. But by financially rewarding participants, they can help consumers recoup initial costs, she said, as long as they aren’t hampered by ineffective state policies.
“Folks can earn over $1,000 a summer through [some VPPs],” she said. “You couple in the leasing model for solar and storage, which is going to get a little more popular in the aftermath of the bill,” due to its ability to continue to earn tax credits, “and I think it’s a pretty good way to get batteries for low or no cost up front.”
It’s getting easier and easier to find a public EV charger in the U.S.
Between 2020 and 2024, the number of public EV charging ports available to U.S. drivers doubled, reaching nearly 200,000 by the end of last year, according to International Energy Agency data. Northeast states have the highest charger density by far, with Massachusetts at the top of the list.
It’s solid growth, though significantly slower than other regions that have embraced EVs more wholeheartedly. In Europe and China, both of which are adopting EVs much faster than the U.S., public chargers roughly quadrupled over the same period.
Even though an estimated 80% of charging happens at home in the U.S., concerns about a lack of public charging infrastructure have dogged EV adoption for years. American drivers consistently cite the issue, or its close cousins, like a fear that EVs are no good for road trips, as among the top reasons they are unlikely to get an electric car.
That’s why widely available public EV charging ports are so important to the transition to electric vehicles — a shift that needs to happen for the U.S. to clean up transportation, its biggest source of carbon emissions.
If the number of public plugs continues to grow at the rate observed in recent years, the industry would have over half a million public charging ports available by 2030, enough to meet a goal set by the Biden administration years ago.
That might be a big “if” under President Donald Trump.
Since taking office in January, Trump has tried to freeze billions of dollars’ worth of federal funding for public EV charging authorized by the 2021 bipartisan infrastructure law. A judge ruled last month that the administration must turn the spigot back on. The program was already sluggish to begin with, having funded the installation of just a couple hundred charging ports over the last four years, and the Trump turmoil has only thrown more sand in its gears.
Then there’s the possibility that EV sales slow down in the U.S. after Sept. 30, when Trump’s megabill eliminates federal tax credits for consumers. Fewer EVs hitting the road could undermine the economic case for companies to build new charging stations.
Still, it’s true that chargers are becoming a more familiar sight for drivers — especially those in the Northeast. As time goes on, that familiarity should help erode the stubborn perception that EVs are unworkable, and help push more and more people to embrace electric, emissions-free driving.
So far, 2025 has been a mixed bag for EV sales in the U.S. A record 607,089 EVs left the lot in the first six months of the year, Cox Automotive reports, but sales in the second quarter were still lower than in Q2 2024.
A big part of that Q2 decline has to do with Tesla, which remains the U.S.’s top EV seller but has suffered stateside and around the world thanks to CEO Elon Musk’s stint in the White House. This week, Tesla reported its profits dropped 16% in Q2 compared to the same period last year. Tesla doesn’t report its sales, but it delivered nearly 60,000 fewer vehicles in Q2 compared to a year ago.
General Motors, meanwhile, had better news to share. It sold 46,280 EVs in Q2, more than double its sales in the same period last year. That’s still a far cry from Tesla’s 380,000-plus deliveries, but it was enough to make GM the No. 2 EV brand in the U.S. And slower EV sales across the industry aren’t deterring GM CEO Mary Barra, who said the company sees EV production as its “North Star.”
Rivian reported a delivery decline in the second quarter but still plans to build new headquarters and an EV factory in Georgia. Smaller EV company Lucid says it delivered a record 3,309 cars in Q2.
Be prepared, though, for a rollercoaster in the next few months now that the “Big, Beautiful Bill” has sent EV tax credits to an early grave. Cox Automotive predicts EV sales will hit a new record in Q3 as buyers race to use federal incentives before they expire at the end of September. After that? “A collapse in Q4, as the electric vehicle market adjusts to its new reality.”
Trump calls off loan for major transmission line
The Trump administration this week canceled a $4.9 billion federal loan guarantee for the Grain Belt Express, putting its future in jeopardy, Canary Media’s Jeff St. John reports.
The planned transmission line, which was granted its loan guarantee under the Biden administration, is meant to bring wind and solar power generated in the Great Plains to cities further east. It has been in the works for more than a decade, and construction on its first phase was slated to start next year.
While the Grain Belt Express had support from utility regulators and large electricity consumers along the line’s route, Missouri Republicans turned against it in recent weeks. The state’s Republican attorney general launched an investigation into the project earlier this month, and Sen. Josh Hawley said he made a direct appeal to President Trump to pull back federal support.
Can the EPA revoke all its emissions rules at once?
The U.S. EPA is planning to demolish the bedrock of many of its climate change-fighting regulations, The New York Times reports. The agency is reportedly preparing a rule that would rescind the 2009 “endangerment finding,” which scientifically established that greenhouse gases harm human health. That finding underpins many of the EPA’s landmark emissions rules, including regulations targeting pollution from cars, factories, and power plants. If the finding is revoked, it would immediately end all those limits and make it harder for future presidential administrations to reinstate them.
The draft of the rule change doesn’t dispute that climate pollutants like carbon dioxide and methane drive global warming or put people’s health at risk, according to the Times. Instead, it claims the endangerment finding oversteps the EPA’s authority. The new rule is almost certain to face legal challenges if it’s finalized.
A “shadow ban” on renewables? Democrats, advocates, and industry groups push back on the Trump administration’s decision to heighten reviews for proposed solar and wind projects on federal land, saying it could lead to a clean energy “shadow ban.” (E&E News)
Shaving solar costs: Solar industry veteran Andrew Birch says cutting non-equipment costs like permitting and project management can reduce the price of rooftop solar installations as federal incentives expire. (Canary Media)
Reeling in the deep: The U.S. government’s step toward issuing The Metals Co. deep-sea mining permits conflicts with an international treaty, leaving the startup’s partners abroad wary of continuing to work together. (New York Times)
Can SMRs succeed? Nuclear industry leaders say there’s enough momentum and funding behind small modular reactor development to propel the sector beyond its past failures. (Canary Media)
Data center downgrade: OpenAI’s Stargate project softens its ambitious plans and is now only looking to build one small data center this year, which could have fallout for energy developers who would have powered the projects. (Wall Street Journal)
Carbon capture’s secret supporters: The oil and gas industry has played a big role in crafting an Ohio carbon-capture bill that could help keep fossil fuel operations running. (Canary Media)
Rates on the rise: U.S. utilities have requested or secured a record $29 billion in rate increases in the first half of the year, more than double the total reached halfway through 2024. (Latitude Media)
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