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Utility-scale solar outproduced gas plants on 82% of all days from January through May, with batteries helping to extend solar’s reach into the evening hours.
This year has been full of dramatic rivalries. World Cup matchups, Knicks versus Spurs, One Battle After Another versus Sinners at the Oscars, and now California solar power versus natural gas.
For years, natural gas has dominated electricity production in the climate-conscious Golden State, just as it has nationally. In both cases, this fossil fuel delivered about 40% of annual generation for much of the last decade. But that started to change in California as solar developers and rooftop installers added more and more capacity, and big batteries joined the party, too.
Last year, the competition turned into a Knicks-Spurs–style nail-biter: California generated nearly as much from large-scale solar power as from gas. This year, it’s turning into a Super Bowl LX–style rout, with solar surging ahead of gas generation for the first five months of 2026, per federal data.
In fact, solar outperformed gas on 82% of the days in that five-month stretch in the California Independent System Operator’s wholesale market. That’s all the more striking given that the state still has more installed gas capacity (29 gigawatts) than utility-scale solar capacity (25 gigawatts), and that this larger gas fleet can operate whenever, while solar is constrained to sunny times. Nonetheless, the solar fleet overcame those structural limitations to beat gas overall so far this year.
California’s gas fleet is in free fall: Generation dropped by 60% from the same time period in 2024. Solar generation increased by 21% in that interval.
Solar didn’t beat gas on its own, though. Battery developers have built 16 gigawatts of capacity in CAISO to charge up on solar power and then compete with gas after sundown. This buildup has rapidly altered grid dynamics in the evenings, when batteries regularly become the top source of power for multiple hours. Meanwhile, wind imports recently jumped as the gigantic SunZia project came online, and that takes the fight to gas in the middle of the night, further depressing its output.
There’s one big player missing from the government figures. The U.S. Energy Information Agency does not have a direct line on rooftop solar production, since those units don’t report data the way large power plants do; the EIA makes an estimate based on various data streams but doesn’t include those numbers in its solar-versus-gas comparison.
Empirically, we know that California’s rooftop solar capacity nearly matches its utility-scale capacity, so a complete accounting of solar production would presumably look like more of a blowout. Data firm Ember, for instance, tallied small- and large-scale solar production to show that all California solar nearly beat gas for the full year of 2024, but it hasn’t yet released results for the whole of 2025 on its U.S. Electricity Data Explorer.
What we can say for sure, based on just the EIA data, is that utility-scale solar alone is off to a roaring start. Gas may rally this summer, if heat waves push demand from air conditioners beyond what solar production can feasibly meet. But in recent months, the scoreboard hasn’t even been close, so this is solar’s game to win.
When that happens, it will mean that the world’s fourth-largest economy has swapped out its biggest fossil fuel for solar, making the grid both cleaner and more efficient.
The subscription-based approach aims to make it easier and more affordable to get a backup battery in your home. And it might be catching on.
Haven Energy is the newest company offering home battery service in Massachusetts for a low monthly payment, a model supporters say could accelerate adoption of residential storage.
Starting in four counties in the southeastern part of the state, the company will provide customers with a 15-kilowatt-hour home battery, installed and ready to go, starting at $29 a month, with a 10-year contract. These terms make obtaining a battery significantly more affordable in a market where a home system can easily top $15,000.
“Think of Haven as a low-cost battery backup subscription,” said co-founder and CEO Vinnie Campo.
Haven joins Tesla, which last month launched its own lower-cost monthly payment offering in both Massachusetts and Connecticut, a discounted version of its existing battery-leasing program. The Tesla option saves Massachusetts customers about $30 a month, which could shave nearly a third off the price of a standard monthly lease.
How does the pricing model work? Massachusetts utilities operate a demand-response program called ConnectedSolutions, which pays battery owners to discharge energy to the grid during times of peak demand, like those hot summer days when everyone turns on their air conditioners at once. With lots of batteries working in concert, these actions can reduce the need for the utilities to buy pricey, dirty electricity from peaker power plants. In the long term, the strategy can help delay costly grid upgrades paid for by consumers.
A typical battery could earn $1,375 per year participating in ConnectedSolutions. A new expansion of the program, ConnectedSolutions+, pays even more to battery owners in certain geographical areas where the grid is particularly congested, making the availability of local stored power even more valuable.
Haven and Tesla both retain ownership of the batteries in their programs, and thus earn these and any other available incentives. This revenue stream allows the companies to keep the monthly price low for customers. The model has the added advantage of making it easier for homeowners to get started with battery storage, eliminating the complication of sorting out and applying for incentives, Campo said.
“We take a complicated stack of rebates and incentives, and dramatically simplify that so it’s an easy-to-understand product,” he said.
Customers with solar panels will be able to save even more by charging up their batteries during sunny but low-demand times of day to use in the darker hours, rather than drawing from the grid.
When ConnectedSolutions calls on participating batteries — generally 30 to 60 times a year, always in the summer — Haven will leave at least 20% of the stored power available for its customers. If a major storm that could trigger an outage seems likely, the company puts its batteries in “safety mode,” preventing them from discharging to the grid.
“We are always prioritizing backup power for the customer,” Campo said.
The monthly payment model is not a completely new approach to driving battery adoption. Haven debuted in 2023, in California (a state that also has a robust incentive program for residential batteries), and evolved its business model in 2025 when the One Big Beautiful Bill Act changed the way the federal tax credits work. Vermont’s major utility, Green Mountain Power, has offered leases on two-battery systems for $55 a month since 2017. Today, some 4,600 households are enrolled, and the program continues to grow.
Battery boosters hope the trend continues. As of earlier this year, 26 states and Puerto Rico had programs paying residential battery owners to share their power with the grid, and more will join the list soon, said Todd Olinsky-Paul, senior project director for the nonprofit Clean Energy Group. These initiatives could pave the way for more monthly payment models that will make getting a battery as easy as signing up for any other home service.
“It’s like subscribing to cable or garbage pickup,” Olinsky-Paul said. “I think it’s going to be quite popular.”
As consumer interest surges and state legislators get on board, a few businesses have jumped into the domestic market.
A hands-on form of solar power has electrified the U.S. in the past year. Plug-in solar lets anyone hang a few panels in the sunlight and send the power straight into their wall sockets to partially offset their utility bill. It extends the benefits of clean energy, a little bit at a time, to renters and anyone else who hasn’t been able to access traditional rooftop solar.
This do-it-yourself energy production has operated in a regulatory gray area, though some intrepid customers have experimented with it anyway. But voters are demanding action to lower their soaring energy bills, and state leaders have responded with a wave of legislation to carve out explicit allowances for plugging solar panels into home outlets.
Last year, the Republican-controlled legislature in Utah became the first to legalize plug-in solar. In just the last few months, 10 more states passed plug-in solar laws, and several more are still considering bills.
The plug-in phenomenon originally took off in Germany as “balcony solar” in the late 2010s, and it accelerated when Russia’s invasion of Ukraine in 2022 spiked energy prices in Europe. German households had installed more than 4 million systems as of 2025, by some estimates, though only 1 million were officially registered.
But eager U.S. customers are not able to use the exact products sold across the Atlantic.
“We unfortunately can’t take one of those systems from Germany and bring them here and plug it into the wall, because we just have a different electrical system,” said Cora Stryker, co-founder of Bright Saver, a nonprofit that seeks to expand balcony solar access.
The business ecosystem is racing to catch up to this surge of consumer interest. But vendors looking to stake a claim in the U.S. market need to grapple with state-by-state rules and a shifting regulatory landscape. The venerable safety lab UL Solutions only started testing full plug-in systems in January, and no complete setup has officially cleared its certification yet. The National Electric Code is undergoing a multiyear update that could make plug-in more accessible — when the 2029 edition takes effect.
Given the swirling uncertainties, established rooftop solar providers are hanging back, for now at least, but a handful of new players are already selling to an eager public.
The only companies with direct experience navigating the plug-in solar market got that head start in other countries.
“The goal is to get those big German manufacturers here [in the U.S.] selling their systems, competing against each other, and lowering prices to the consumer,” Stryker said. “That will happen. It’s a question of how fast that will happen.”
CraftStrom launched in Germany in 2019. Its product fits naturally with how most people live in cities, said CEO and co-founder Stephan Scherer: German urbanites typically rent compact apartments that have balconies and that don’t use a ton of energy. They thus have the physical setup for hanging a few panels, and the opportunity to generate enough power to make an appreciable dent in their monthly consumption.
To make its panels easier for people to install, CraftStrom decreased the weight by replacing the typical glass and aluminum framing with special laminations to protect the silicon cells. The company has already gone through three iterations of microinverters and eight iterations of solar panels.
“The good thing about the German market was that we got to play around, test, improve in time for the U.S. market to start,” Scherer said.
CraftStrom has been selling thousands of systems across all 50 states for several years, Scherer said. But it had to change the equipment to match the design parameters of the U.S. grid, and then navigate safety standards that are evolving in real time.
CraftStrom, for instance, built its U.S. products around language in the National Electric Code that allows larger plug-in systems, provided that customers get an electrician to wire them into a dedicated circuit on the breaker box. For regular circuits, customers can buy a CraftStrom power meter that throttles solar production, depending on what else is on the circuit, to stay within National Electric Code stipulations.
These adaptations to U.S. rules add cost and complexity, as opposed to the truly plug-and-play German experience. The country’s plug-in market remains in the early-adopter phase before exponential growth kicks in, Scherer said.
Another major player in Germany’s market, EcoFlow has reengineered its products to sell in the U.S., starting with Utah. The company added software that ensures the equipment stays within the confines of a given state’s legislation, said Ryan Oliver, head of communications for North America. For instance, Utah has a cap on the total wattage a plug-in system can send to the house, which EcoFlow’s software can enforce. EcoFlow also sells integrated batteries to let customers eke out more solar generation without violating the cap.
One of the most enthusiastic evangelists for plug-in solar policy has now become a vendor for unusually low-priced systems.
Earlier this year, Bright Saver started selling plug-in panels on its website: one 180-watt panel for $499 or two for $699. Then last week, the nonprofit slashed its prices to sell the same systems “at cost,” discounting the 180-watt kit to $285.30 and the 360-watt one to $414.17, provided that customers pay a $29 membership fee.
Bright Saver chose this limited wattage for a particular reason: “The technical experts have already decided that 360 watts is the safe level to plug into any outlet,” Stryker said.
She’s referring to a proposed amendment to the National Electric Code concerning the level of solar production that can safely plug into any outlet; Bright Saver chose what system to sell given that analysis.
Bright Saver is not a manufacturer but assembles systems from parts it deems safe — panels and microinverters that have the necessary safety certifications individually. In a June interview with Canary Media, Stryker noted that Bright Saver was losing money on each unit that it sold, given the small volume and the overhead involved. The nonprofit is willing to stomach those losses in the near term, she said, because its mission is to get solar into the hands of more people, so they can lower their energy bills and carbon emissions. The offering quickly sold out. New inventory is expected in late August.
Numerous companies have proved themselves capable of making and selling solar panels for residential rooftops. Others make consumer-oriented off-grid solar panels and batteries for camping, van life, and prepper living. Both sets of businesses could leverage their brands and expertise to corner the plug-in market, but they have yet to commit to that.
Qcells manufactures 8 gigawatts of solar modules in north Georgia, and sells more residential panels than any other company in the U.S. Those qualifications could set the company up for success with a specialized line of made-in-America plug-in panels, but so far, Qcells has not entered the plug-in market.
“The excitement over balcony solar shows people see solar as key to cutting skyrocketing energy bills,” Patrick Sterns, Qcells director of grid services policy, said in an email. “It’s true, renewable energy can deliver lower, stable bills to all kinds of ratepayers, and programs like virtual net energy metering and community solar prove that. The problem is these programs face regulatory bottlenecks around the country at a time when accelerating access is key to delivering these benefits at scale.”
Established players have more to lose if they get caught on the wrong side of the regulatory gray areas. There’s also a scale mismatch: A company that sells gigawatts of panels in a year won’t be as taken by the potential to sell plug-in panels a few hundred watts at a time.
Rooftop-panel manufacturers typically sell to other companies that do the work of customer outreach and installation. The off-grid vendors may have a more natural inclination toward selling plug-in.
“I expect some quick movement from the portable-solar-generator players. Most of them have European products for balconies,” said Luke Bahl, who launched the website Simple Plug-In Solar to collect and share information about the phenomenon. “It’s their bread and butter to sell direct to consumer, with easy setup.”
The camping and off-grid solar businesses can’t immediately sell plug-in solar, because their products don’t have the eponymous plug. They are designed to feed electricity into a battery unit, which the customer connects to electronics to receive the charge. Plugging directly into a wall socket demands specific microinverter controls that the off-grid systems aren’t built for.
EcoFlow sells off-grid products alongside its new U.S. plug-in solar line. Jackery, one of the preeminent suppliers of personal solar-battery backup systems, has “successfully launched” balcony solar products in Europe, a spokesperson said. But the company does not offer a plug-in solar option in the U.S., and does not have an official timeline for bringing that technology to American consumers.
Plug-in solar’s niche is to reduce electricity use and hence utility bills. Off-grid solar is, by definition, designed for customers who aren’t connected to any utility. But it wouldn’t take much to add the right plug and controls to a product line that already gives people direct control over their energy.
Decades-old Ormat is seizing geothermal’s superhot moment by branching into next-generation technology and expanding its traditional plants.
Over two decades ago, Ormat Technologies began a big experiment on a swath of rugged land near the Hot Springs Mountains in western Nevada.
The geothermal company was already producing electricity there, using the heat found naturally in hot water and steam trapped beneath the earth’s surface. But in 2002, Ormat and its research partners decided to deploy an emerging approach to boost output at the Desert Peak power plant. They’d drill deep into hot, dry rocks and pump them full of liquids, creating geothermal resources where nature hadn’t provided.
In 2013, the 1.7-megawatt demonstration project connected to the grid, becoming the nation’s first “enhanced geothermal system” to hit that milestone. At the time, though, the industry still lacked the technology innovations and favorable economics needed to support a full-throttle scale-up of enhanced systems, which the U.S. has studied for over 50 years.
Today, that calculus is shifting.
The idea that companies can harvest energy without tapping hot springs or geysers is driving a surge of interest — and billions of dollars of investment — in America’s once-stagnant geothermal industry.
Startups are racing to build next-generation facilities that can supply clean, around-the-clock power to data centers and states with decarbonization mandates. Technology breakthroughs are making it cheaper and faster to develop new wells. Policymakers of all political stripes are working to uphold federal geothermal tax credits and to ease permitting and regulatory challenges that can slow down projects.
And Ormat itself is getting back into the enhanced geothermal game, having focused mainly on its conventional projects in the intervening years.
Ormat, whose headquarters is in Reno, Nevada, is a leading developer and operator of geothermal power plants. The 61-year-old firm owns dozens of clean energy projects globally, including over 1 gigawatt of geothermal capacity, mainly in the western United States. Those facilities all tap into hydrothermal resources, the naturally occurring reservoirs that are typically found near the boundaries of major tectonic plates.
It’s now planning to build a new enhanced pilot project at Desert Peak, together with the oilfield services giant SLB, as the companies work to commercialize the approach.
“We’re going back to where we started the journey, and it feels a bit like closing the loop,” said Daniel Moelk, Ormat’s executive vice president for subsurface, wells, and next-generation geothermal. The companies are gathering new geophysical data at the site to determine where to drill wells, he added, though he couldn’t say when the project might be completed.
Ormat is separately developing an enhanced pilot system with the Houston-based company Sage Geosystems, which will deploy its next-generation technology at one of Ormat’s existing sites in Nevada or Utah. Ormat invested $25 million in Sage in January as part of the startup’s $97 million Series B funding round.
“Opportunities are expanding with new emerging technologies, and we want to be part of it,” Moelk said.
That’s also true for Ormat’s manufacturing operation in Yavne, Israel, where the company was founded. In June, Ormat unveiled designs for power plant equipment that can operate in the higher-temperature and higher-capacity conditions that next-generation systems are expected to achieve. The 100-megawatt power-generation unit is meant to make any developer’s geothermal projects cheaper and more efficient overall by unlocking economies of scale, Ormat said.
Still, the new design reflects the world that the geothermal industry is building toward, not where it stands today.
The United States has just about 4 gigawatts of geothermal power capacity divided among 99 plants, over half of which are in California. Together, they supply a mere 0.4% of the nation’s total electricity generation. But the U.S. Department of Energy predicts geothermal could provide 90 gigawatts of always-on, carbon-free power to America’s grid by 2050 if the industry can significantly accelerate its ongoing cost reductions and enable large-scale enhanced systems to catch on.
Ormat and a growing crop of newcomers are being propelled toward that reality by the soaring energy demand from data centers. In California, Oregon, Washington, and other states, clean-power needs are rising as well, as buildings, factories, and vehicles transition away from fossil fuels and toward electrified solutions.
“There’s growth across the industry driven by the fact that power prices are higher than they’ve ever been,” said Michael O’Connor, director of the Mountain West Geothermal Consortium, a new initiative to accelerate geothermal deployment in the Mountain States.
He noted that, in some markets, developers and utilities are striking long-term agreements for “firm,” or on-demand, power that are two to three times higher than they were in 2021, incentivizing more geothermal companies to pursue new projects.
The recent momentum is also thanks to the geothermal drilling advances that have emerged in the years since Ormat launched its first Desert Peak pilot.
Fervo Energy, for example, uses horizontal drilling techniques and fiber-optic sensing tools from the oil and gas industry to fracture hard, impermeable rocks and create artificial reservoirs. In 2023, the Houston-based startup turned on a first-of-a-kind enhanced geothermal system in Nevada. The 3.5-MW project sends electricity to the grid to help satisfy some of Google’s power appetite in the state.
Simultaneously, Fervo has been developing its 500-MW Cape Station project in Utah, which is set to become the world’s largest enhanced geothermal system when fully completed, potentially by 2028. While developing the project, the company said it reduced drilling times by about 75% and slashed per-foot drilling costs by about 70% between 2022 and 2025, marking a significant achievement for the nascent industry.
To fund its scale-up, the nine-year-old company in May became the first next-generation geothermal firm to go public, netting about $1.9 billion. (Ormat, which hit almost $1 billion in revenue in 2025, joined the stock exchange back in 2004.)
The startup Quaise Energy recently credited Fervo’s IPO with giving it a fundraising boost. Quaise raised $134 million this month to advance its first superhot geothermal project near an Oregon volcano. The company XGS Energy, which is pursuing a novel closed-loop technology, has been hiring veteran finance executives as it evaluates going public itself.
“Fervo definitely led the way, in terms of showing a path to the public equity markets for pre-revenue development companies like us,” said Richard Chong, who joined XGS in May as the company’s chief financial officer. Chong previously worked at Calpine, where he helped secure over $2 billion in financing to expand The Geysers, a decades-old geothermal development in Sonoma County, California.
The enthusiasm for cutting-edge technologies is spilling over into the conventional geothermal market, which has grown at a tortoise-like pace in recent years.
Hydrothermal resources are generally easier and less expensive to tap, since they don’t require fracking deep underground. But scientists and companies have explored only a tiny fraction of America’s subsurface geothermal resources. For any developer, it can cost tens of millions of dollars just to do the preliminary drilling to locate those resources — and to confirm that they’re good enough to produce electricity for decades. Such an undertaking was harder to justify in the years when U.S. electricity demand was essentially flat.
Now, “the market conditions around electricity demand have driven a lot of developers to rethink their portfolios and their assumptions on if they should develop,” O’Connor said.
In June, Ormat received expedited approval for environmental permits from the Bureau of Land Management to begin developing the new 60-MW Pearl Geothermal Development Project on public lands in Esmeralda County, Nevada. The approval stems from the Trump administration’s 2025 emergency permitting procedures to accelerate energy development on federally managed lands — on which over 90% of identified U.S. geothermal resources are located.
The bureau has also awarded permits for Ormat’s other initiatives in Nevada, including the 30-MW Crescent Valley plant and the earlier-stage Diamond Flat and Pinto project sites, where the company will study and test for geothermal resources. All told, Ormat holds leases to some 400,000 acres across six states.
“Ormat has gone from a company that was focused on operating the assets it currently has to thinking about expanding, and they are not alone,” O’Connor said.
The startup Zanskar raised $40 million in April to build its first conventional geothermal plant. The company combines artificial intelligence with boots-on-the-ground surveying to identify hidden natural resources in the U.S. West. Last year, Zanskar said it had identified the first “blind” geothermal system — meaning it doesn’t have vents, geysers, or other visible features, or any historical records — for commercial use in more than 30 years.
“They’re taking advantage of the higher demand for the lower-hanging fruit,” O’Connor said of Zanskar’s conventional geothermal play. The startup and other firms “are either acting on leases that people have held for a while and not had motivation to use, or exploring for the first time.”
Ormat, for its part, will continue to rely on its “robust hydrothermal business” while also piloting the next-generation technologies that could enable geothermal to leave behind its niche position in the global energy market, Ormat’s Moelk said.
“Right now, we have what the world needs: renewable, local, baseload energy,” he said. “After 20 years in geothermal, I’ve never seen such a big opportunity.”
The Department of Defense has essentially frozen permitting for new wind installations over the last year, preventing more than 155 projects from moving forward.
A coalition of 18 states and Washington, D.C., has moved to join an industry lawsuit challenging the Department of Defense’s freeze on onshore wind projects in America.
It’s the latest in a nearly yearlong saga during which the Trump administration has obstructed more than 155 land-based wind projects across the country, according to data from the American Clean Power Association.
President Donald Trump has vowed to block the construction of wind farms during his second term, going as far as to claim that his administration would “try and have no windmills built in the United States.”
The administration has done its best to live up to that edict, waging an all-out war on wind farms, which last year generated more than 10% of the country’s electricity. The blockade has occurred against the backdrop of fast-rising utility bills, the product of high electricity demand that can only be met by building more energy capacity.
Trump’s attacks on offshore wind have been the loudest and most brazen, but onshore wind has not been spared. Last July, the Interior Department created a “choke point” for permitting new wind and solar projects on federal lands. One month later, in August 2025, the Defense Department quietly stopped issuing national-security approvals to onshore wind projects — a move that has impacted dozens of gigawatts of wind projects across both public and private land.
In April, a federal judge ordered the Interior Department to lift its blockade while a lawsuit led by industry groups makes its way through court, though the agency appealed the decision in June. In May, industry groups and wind developers filed suit against the Department of Defense’s permitting freeze, arguing that the delays created by the agency may threaten the viability of certain projects by causing them to miss deadlines to lock in expiring federal tax credits or to interconnect to the grid.
Nineteen attorneys general, all Democrats, filed a motion on Thursday to intervene in that suit and join the industry in requesting a court injunction against the DoD freeze. The motion argues that the DoD’s delay tactics could negatively affect grid reliability, energy affordability, climate goals, and jobs — and undermine state sovereignty.
The Trump administration claims the pause is necessary due to national security concerns. It provided a similar justification when halting work on all five in-progress offshore wind farms last year, but the argument was swiftly rebuked by federal judges five different times.
The DoD process is indeed meant to review wind projects for national security risks. Following the review, it is not uncommon for developers to take certain mitigation steps as directed by the military.
“For more than a decade, DoD engaged in a predictable review process and worked with developers to mitigate potential concerns,” according to a news release from the office of Massachusetts Attorney General Andrea Joy Campbell. Now, “wind projects across the country have been frozen at various stages of the review process, including those that had already completed mitigation negotiations and were awaiting only final DoD approval.”
Getting data centers to pay for new generation and batteries could be the best hope for the nation’s biggest power market to finally get a handle on costs.
With the conclusion of its latest capacity auction, PJM Interconnection has once again shown that its process for securing new energy is unable to keep up with the wave of electricity demand from data centers.
But PJM, the grid operator for the country’s biggest energy market, is poised to adopt a new process that could help fix these problems: by pushing data centers to pay directly for the new clean energy, batteries, and fossil-fueled power plants needed to meet their huge electricity demand.
Late last month, PJM stakeholders achieved a rare level of consensus in voting to approve the plan for a new auction, called a reliability backstop procurement.
The measure, which still needs final approval from both PJM and the federal government, represents the grid operator’s most significant step to repair an auction process that has left consumers paying more money for a less reliable grid. PJM’s board of directors is expected to submit the proposal to federal regulators in the coming weeks.
The results of PJM’s Tuesday capacity auction underscore how critical it is for the grid operator to find a solution.
PJM’s capacity auctions, held once or twice each year, are the key process through which it ensures there’s enough capacity to keep its grid up and running during summer heat waves and winter cold snaps. It’s a high-stakes task: 67 million people from Virginia to Illinois depend on PJM for electricity.
For the third time in a row, the capacity auction hit the market’s price cap, in this case, $325 per megawatt-day. Similar caps have been in place since last year, after state governors demanded a limit to the massive cost increases being pushed onto utility customers across the PJM region.
These latest capacity costs reached $16.4 billion, matching the record set last December, and are more than eight times as much as PJM has paid for capacity in prior years. Customers in some PJM states — including Illinois, New Jersey, and Pennsylvania — are already seeing their bills rise by more than 10%, in part because of these soaring costs.
And yet, these maxed-out prices are still not high enough to get energy developers and utilities to build the power plants PJM needs to hit its reliability targets. This week’s auction fell short of PJM’s reliability requirement by over 6.8 gigawatts — the second time in a row that sky-high prices have failed to bring sufficient capacity resources into play.
The upshot is that customers in PJM Interconnection are paying some of the highest rates in the U.S. for grid reliability — even as the grid operator says the system isn’t reliable.
At the root of the problem is an explosion of demand from data centers that utilities and project developers can’t keep up with.
The grid operator forecasts that 30 to 34 gigawatts of data centers will be online in states across its region by the early 2030s. Utilities and developers would struggle to meet that pace under favorable conditions, but PJM’s infamously sluggish interconnection process makes it an impossible task.
While power demand has soared, the capacity being brought online in PJM has stagnated.
Of the 138.3 gigawatts of resources secured in this week’s auction, only 525 megawatts came from new capacity. All told, just under 4 gigawatts of newly built and “uprated” capacity from existing projects have been included in the capacity auctions since 2024, well below the roughly 20 gigawatts of new capacity added in the five prior auctions.
“We’ve got two problems,” said Julia Hoos, who leads coverage of Eastern U.S. power markets for Aurora Energy Research. “One, new capacity is just more expensive than we’re willing to pay for; and two, we haven’t resolved the physical barriers to build. Now, we’re paying for both issues.”
And those problems aren’t going away. Monitoring Analytics, PJM’s independent market monitor, has cited forecasted growth in data center power demand as being responsible for more than $29 billion in additional capacity costs to customers in PJM since 2024. In a May report, the monitor warned that these costs will “continue to grow until the issues associated with the addition of large data center loads are addressed.”
It hasn’t been easy to land on a path forward.
Environmental groups, consumer advocates, and state politicians have been haggling with data center trade groups, utilities, and power plant owners for more than a year over how to manage electricity costs related to data centers.
Some argue that new data centers should be forced to drop offline during grid emergencies, to avoid burdening all other customers with the cost of building power plants to ensure service at those times. Others say data centers should be required to pay directly for the capacity resources needed to mitigate their burdens on overstressed grids.
The plan approved by PJM stakeholders in late June, which was put forward by utilities and the trade group Data Center Coalition, would enable that latter option.
Unlike PJM’s standard capacity auctions, which are aimed at meeting the needs of all the utilities and customers served by its grid, this reliability backstop procurement, or RBP, is meant to be a “one-time process to purchase new supply resources to serve new data centers and other large loads,” PJM explained in announcing the outcome of its stakeholder process.
The proposed backstop procurement auction would come with a price cap of $555 per megawatt-day, much higher than the limit now set on PJM’s broader capacity market. In fact, the amount is pretty close to Aurora Energy Research’s calculation that about $500 to $600 per megawatt-day is what’s needed to finance new capacity resources trying to get built and interconnected to the grid, Hoos said.
This new auction would also structure deals between data centers and project developers under 15-year contracts, which “makes it cheaper to build, because developers have more security,” she said. “In the short term, it may be the only way to build new capacity, because generators need certainty.”
PJM has also showed some signs of life in moving projects through its snarled interconnection queue.
This year, the grid operator finally cleared roughly 53 gigawatts of solar, batteries, wind, and fossil gas power projects to connect to its system. If the RBP is approved by the Federal Energy Regulatory Commission in its current form, it could be “potentially a way to funnel a lot of money to projects that are already in the works,” said Tom Rutigliano, senior advocate for climate and energy at the Natural Resources Defense Council.
But that’s not the only way for new data centers to pay for the resources they need to come online, Rutigliano and Hoos noted. An even bigger channel could emerge in the form of bilateral contracts — agreements between individual data centers and developers of generation, battery storage, and demand-side resources like virtual power plants.
Such bilateral contracting has always been an option for large power customers, Hoos noted. In fact, major corporations have been signing power-purchase agreements with solar and wind projects for more than a decade. But those contracts have been focused on securing clean energy, and not so much on projects that can provide capacity during hours when the grid is under the greatest stress.
That’s a more complicated type of deal to structure, and tech giants like Amazon, Google, Meta, and Microsoft are only in the early stages of combining clean energy, batteries, generators, and demand-side resources or flexible computing that can meet PJM’s capacity needs.
But with states served by PJM demanding that large loads bring their own capacity, these kinds of deals are increasingly seen as necessary to get new data centers built. As part of the same effort, PJM last month also started work on facilitating “bilateral, long-term agreements between large load customers and generation providers” as a way to help these processes along, it also announced.
In fact, the RBP could become a last-resort choice for large loads that can’t strike their own deals, Hoos said. “There’s a lot of value to these bilateral contracting models that move that risk to investors and to the large loads,” she said — not to utility customers at large.
What remains uncertain is whether the RBP and these bilateral deals can enable data centers and new grid resources to come online “without raising rates on everyone else,” Rutigliano said.
PJM was meant to tackle the cost considerations by adopting a “connect and manage” plan, a structure that would require data centers to either bring their own capacity or face being cut off from grid power during emergencies. But PJM stakeholders failed to approve any of the 11 connect-and-manage proposals on hand.
So PJM proposed that state regulators take the lead in setting the rules for how utilities bundle up all the capacity needs of the large loads seeking to come online and submit them to the RBP, Rutigliano said.
This creates a risk that utilities could claim to be representing large loads in future auctions without securing durable commitments from those customers to actually pay for the capacity they commit to buying. If that happens, utility customers would be left holding the bag.
All this is unfolding on a compressed timeframe. Under pressure from the Federal Energy Regulatory Commission and state governors, PJM has agreed to hold its backstop procurement auction in September. That’s not a lot of time to prepare — but Rutigliano thinks PJM needs to work closely with states to ensure that regular customers don’t end up paying for resources that utilities secure for data centers.
“The stakeholder-approved version is that only utilities that affirmatively step up and say ‘we want more capacity’ get put in as buyers,” he said. “States have to make sure that doesn’t get passed on to ordinary ratepayers. They have to make damn sure there’s a data center that pays for it, or [utility] shareholders pay for it.”
Even as renewables lose federal incentives and face other hurdles, Lazard finds onshore wind and large-scale solar again have the lowest levelized cost of energy.
Pretty much every type of energy is getting more expensive in the U.S., but clean energy is still a better bet than fossil fuels.
That’s the topline from investment bank Lazard’s latest annual report on the levelized cost of energy, or LCOE — a metric widely used to compare how expensive different sources of electricity are. Put simply, it expresses the present-day price of generating a megawatt-hour of electricity from a solar farm, a gas plant, or another power source, all while accounting for that source’s full lifetime operating costs. For example, it takes into consideration that a solar farm’s fuel and operational costs are tinier than a fossil fuel plant’s.
For the last decade, Lazard’s reports have basically reached the same conclusion: Onshore wind and utility-scale solar have a lower LCOE than fossil fuels. While that’s still true this year, the average LCOE of onshore wind and solar did surge by 11% and 18%, respectively, from last year, thanks to the loss of federal renewable energy tax credits, increased tariffs, high interest rates, and other challenges.
But the fossil fuel sector also faced headwinds over the past year, as a supertight market for turbines drove up the cost and timeline of building a gas plant. The LCOE of gas power from modern “combined-cycle plants” — which was already about $20 higher per megawatt-hour than solar’s and onshore wind’s in 2025 — rose by 15%. Still, those higher prices and construction delays haven’t stopped developers from pursuing ambitious gas projects as the AI boom sparks a scramble for on-demand power.
Although LCOE is a pretty handy way of comparing energy costs across sources, it has its limitations, the Clean Air Task Force argued in a report last year. The climate advocacy group says LCOE isn’t a good method for long-term decarbonization planning because it doesn’t account for many real-world concerns, like a power source’s land and health impacts or its ability to generate nonstop electricity.
Even so, plenty of evidence indicates that renewables will retain their cost-competitive edge. For one, they’re not subject to rocky fuel prices like oil and gas are — something that’s been on full display as conflict in the Middle East continues. And while solar and wind power generation remain at the mercy of the weather, batteries are making their fatal flaw of intermittency a thing of the past.
A first-in-the-nation data center ban
New York has become the first state to enact a moratorium on building hyperscale data centers. After a few weeks of will-she-won’t-she uncertainty, Gov. Kathy Hochul (D) signed an executive order barring data center construction for up to a year as the state hammers out regulations.
The move comes as data centers face criticism from both sides of the political aisle over their power use, and especially their potential to drive up electricity costs for residential utility customers. But despite the facilities’ widespread unpopularity, other governors have been reluctant to go as far as Hochul. In April, Maine Gov. Janet Mills (D) vetoed a bill that would have halted construction through November 2027. And just this week, Michigan Gov. Gretchen Whitmer (D) asked data center developers to pledge they wouldn’t raise power costs for state residents, but stopped short of calling for a total ban on construction.
Clean energy beats the heat
This week was another hot one in the Northeast, though temperatures weren’t quite as bad as they were earlier in July, when a major heat wave tested — but didn’t knock out — the power grid.
As I wrote last week, clean energy played a big role in meeting soaring demand while millions of people cranked up their air conditioners. Some New York City households even kept cool without adding to the grid’s burden. Our reporter Maria Gallucci is one of a few hundred New Yorkers participating in a pilot program that provides apartment dwellers with a small battery pack to plug their window AC into, reducing stress on the electric system, helping prevent blackouts, and even earning them a little cash.
Maria stayed on the heat wave beat with a look at how offshore wind tackled spiking power demand in New England. The region had to turn to oil power last year when it faced a similar hot spell, but this year, the emergence of more offshore wind meant the grid didn’t need as much of the dirty fossil fuels.
Endangered again: The Trump administration finalizes a change to how the Endangered Species Act is enforced, opening up critical wildlife habitats to oil and gas drilling and other development. (NPR)
Google’s big clean bet: Cypress Creek Energy breaks ground in Arkansas on what could be the largest solar and storage project in the U.S., with power from its first two phases purchased by Google to offset its data center demand. (Canary Media)
Weatherization win: A federal housing law that recently passed with bipartisan support will require the Trump administration to enact stronger energy conservation standards for manufactured homes, which aren’t subject to local and state building codes and are often inefficient. (Canary Media)
Fast food, fast charge: EV chargers are proliferating especially quickly in the South, including at fast-food chains like Bojangles and convenience stores. (New York Times)
Smoking out solar: The wildfire smoke that turned skies orange and hazy in much of the Northeast this week also caused solar production to plummet in New England. (WBUR)
A balcony solar deal: Nonprofit Bright Saver is selling zero-markup balcony solar packages starting at around $300 as more states pass laws allowing residents to use the plug-in panels. (Canary Media)
Turbines torpedoed: The Trump administration has delayed 155 new wind energy projects across 24 states over allegations that turbines threaten drone detection and national security. (Grist)
The global fleet of nuclear power plants is poised to expand quickly as climate goals, security concerns, and rising demand renew interest in the energy source.
The global nuclear energy industry has been muted since 2011, when the Fukushima Daiichi disaster unfolded in Japan. Some new reactors have been built — especially in China — but a lot of old nuclear power plants have been retired as well.
That means nuclear energy has been “running in place” for well over a decade, as a new report from BloombergNEF puts it. But now, the market is changing — and BNEF’s analysts predict that the sector is poised to break out in a sprint.
BNEF forecasts that global nuclear energy capacity will rise to 535 gigawatts by 2036, a 44% increase from last year’s installed capacity of 372 GW.
A simple reason for the optimistic forecast is that a lot of reactors are under construction worldwide: 76, according to BNEF, as of the first half of this year. Almost every single one is a conventional large-scale reactor, as opposed to a buzzy new small nuclear reactor. Those units represent 83 GW of new capacity on their own.
Nuclear energy’s turnaround comes as countries look to decarbonize their power grids, as it’s a readily available source of carbon-free electricity. It’s also just a big source of electricity, period — and global demand for power is rising fast. Several countries, including Japan, have also shown renewed interest in nuclear energy in light of the Iran war, which has roiled global oil and gas markets.
China is leading this new nuclear buildout. It’s home to nearly half of all reactors under construction worldwide, and by 2030 it may have more nuclear capacity online than the U.S., the current global leader.
Officials in the U.S., for their part, are talking a big game about reinvigorating the domestic nuclear industry. Construction in the U.S. remains scant compared with China’s dozens of in-progress reactors, but the sector is making some headway. Two smaller, advanced reactors are underway in the U.S. as of this spring, and an 800-megawatt reactor in Michigan may come back online this year after missing a 2025 target.
The things to track now are timing and cost. In certain markets, especially the U.S., nuclear projects have been dogged by extreme cost overruns and blown deadlines — and that combination has held back the sector’s growth. The new wave of interest gives the industry a chance to prove it can finish projects on budget and on time. We’ll see if it delivers.
In a first, the state could speed up data centers’ grid connection if they bankroll energy-saving residential tech like heat pumps and batteries.
New Jersey is offering data centers an unorthodox way to get the power they need: by bankrolling home energy upgrades.
Last week, Gov. Mikie Sherrill (D) signed a bill that will create a first-of-its-kind program to incentivize data centers to secure clean capacity by reducing demand elsewhere on the grid. Data centers will be able to pay for households to replace their energy-hogging electric-resistance space and water heaters with much more efficient electric heat pump appliances — or to install rooftop solar and batteries.
The scheme could lower electricity bills for potentially millions of households statewide by hundreds to thousands of dollars annually. In return, the data centers would get priority in the interconnection queue.
“New Jersey just set a national precedent,” said Ari Matusiak, CEO and co-founder of nonprofit Rewiring America, who served on Sherrill’s transition team. The law, called the Data Center Fair Share Act, “is a blueprint for how policymakers can start to think about households as energy infrastructure.”
Nationwide, utilities propose to spend at least $1.4 trillion on capital expenditures through 2030, according to consumer advocacy nonprofit PowerLines. “A meaningful percentage of that could be directed to households,” Matusiak said.
Rewiring America first championed the approach last September, when it released a report finding that installing heat pumps, solar, and batteries in homes could offset more than 93 gigawatts of anticipated AI-driven demand nationwide. The nonprofit provided input on New Jersey’s bill, but it “very much had its own momentum,” according to spokesperson Alex Amend.
Using what’s known as “voluntary demand-reduction trade programs” established at the utility-level, data centers will be able to hire companies that can aggregate households and other utility customers into a virtual power plant. The utility would then likely work with the aggregator to verify the resulting capacity will be there when the data center is built, according to Amend.
Power-hungry data centers have been pushing up electricity prices in the PJM Interconnection grid region, which includes New Jersey as well as a large swath of the Midwest and mid-Atlantic. And utility customers have been left footing the bill.
New Jersey’s law aims to put the kibosh on that. In addition to the household program, the measure will create a new rate class for data centers, following the lead of Minnesota, Oregon, and Virginia. The move is meant to ensure data centers pay for their own energy use and associated grid infrastructure.
Other states are looking to push data center dollars into home energy upgrades. California, Colorado, Illinois, Pennsylvania, “and likely many others” are considering legislation, said McKenna Beck, policy analyst at the nonprofit Natural Resources Defense Council, which helped create the New Jersey bill’s framework. On Tuesday, New York joined the list: Gov. Kathy Hochul signed an executive order that halts data center development for up to a year and directs regulators to consider requiring data centers to fund distributed energy resources and battery storage.
Hyperscalers are staying mum on New Jersey’s initiative. Microsoft declined to comment, Google did not respond in time, and Amazon told Canary Media that it had no stance.
Still, Big Tech companies are increasingly keen to leverage households as energy assets.
Last month, Google announced a pioneering agreement with the virtual power plant provider Voltus for up to 100 megawatts. Also in June, Tesla, Sunrun, and Renew Home broadcast that they would provide a whopping 16 gigawatts of power across data center hot spots in the U.S. using distributed energy resources. The power will be “ready in months, not years,” according to their website.
In New Jersey, Rewiring America estimates that of about 2 million single-family homes, roughly 85,000 have electric-resistance heating systems and 422,000 have electric-resistance water heaters. “But all households could benefit from home batteries and, in most cases, rooftop solar as well,” Amend said. “So the potential is enormous.”
New Jersey’s public utilities regulator has one year to flesh out the standards of the state initiative for utilities. Utilities then have 180 days to submit proposals for their individual programs.
Enrolled households could start getting data center–funded heat pumps, solar panels, and batteries as soon as mid-2028, Beck noted.
“These resources will directly lower bills for households and communities in which the data centers are built,” Beck said. “It’s incredibly exciting.”
As it pivots from shutting down nuclear plants to building them, Holtec says small modular reactors can cut costs and speed construction. Now it has to prove it.
Nuclear giant Holtec International is betting big that its 300-megawatt small modular reactors are the future of atomic energy.
On Friday, the Florida-headquartered firm filed paperwork with the Securities and Exchange Commission in order to sell shares in the company on the Nasdaq.
Across hundreds of pages, the disclosure document outlines the 40-year-old Holtec’s plans to transform itself from the industry’s undertaker — manufacturing canisters to safely store radioactive spent fuel and decommissioning shuttered nuclear plants — to its midwife, producing and operating new electrical stations. This transition comes as nuclear energy regains popularity in the U.S. as a way to meet booming power demand without creating more planet-warming pollution.
Developers have traditionally offset nuclear’s high up-front costs by building ever-larger reactors to capture the economies of scale. Since the early 2000s, however, a number of companies have proposed building small modular reactors that can be constructed identically and in batches. SMRs could generate about a third of the electricity of conventional large-scale plants, but, proponents argue, would bring down costs through assembly-line repetition rather than physical scale.
That cost reduction has yet to be proven out in the real world with actual plants. But in its S-1 filing, Holtec said, “SMRs will offer scalable, cost-effective solutions for new capacity with enhanced safety features, reduced construction timelines and reduced land and transmission infrastructure needs as compared to traditional, larger-scale reactors.” It noted that a single-unit SMR plant would only need 15 acres of land and take a mere three years to build. By contrast, the big reactors on the grid today can take up hundreds of acres, and construction typically drags on for nearly a decade.
Holtec’s SMR-300, as the pressurized-water reactor is named, “is expected to receive regulatory approval for deployment in 2029” and reach its first deployment “in the early 2030s,” according to the filing.
The company said it expects SMRs to play “a meaningful role in the expansion of nuclear capacity,” noting that they can “complement large-scale nuclear generation through lower upfront costs” and more flexible planning around how much power is needed.
For example, smaller reactors may be better suited for converting some old coal-fired stations into nuclear plants. The DOE has been researching the idea for years, given that nuclear and coal are both thermal resources that operate with similar rates of frequency and therefore use similar equipment to generate electricity from steam — which in nuclear plants is made from the heat created by splitting atoms and in coal plants is made from heat created by burning the black rocks. Converting a 400-MW coal plant into a similar-size nuclear reactor makes more financial sense than using a bigger reactor, which could require costly transmission upgrades and more space.
“We believe that our SMR-300 plant can become a favored nuclear generation source over large reactors because of certain advantages,” the company said in its filing.
The company will also operate at least one conventional reactor, the 800-MW unit it’s currently restoring at its Palisades nuclear station, in western Michigan. That project — the nation’s first effort to return a permanently shuttered nuclear reactor to service — could be completed within months, though its contract to sell power to the local grid won’t kick in until next year.
Holtec hopes to combine its plant-restart strategy with its SMR vision. It’s planning to deploy two SMRs at the Palisades site; if that works out, the company has said it may build SMRs at New Jersey’s Oyster Creek nuclear plant, which it’s been in the process of decommissioning for eight years.
Holtec owns three other defunct nuclear plants — Massachusetts’ Pilgrim, Michigan’s Big Rock Point, and New York’s Indian Point — that it could also try to rebuild. The Trump administration has called for reconstructing Indian Point, but Albany remains opposed to the controversial proposal.
Local opposition isn’t Holtec’s biggest hurdle, however. That would be competition from the nuclear behemoths in Russia and China. Virtually every Western nuclear developer is facing an uphill battle to compete with the Kremlin’s state-owned Rosatom, by far the biggest international vendor of nuclear technology in the world, and China’s two state-owned nuclear companies, which are building more than three dozen reactors at home and are expected to enter the export game soon.
Still, among its domestic rivals, Holtec may be the best positioned to hold its own on a global playing field. It is an established company with profitable enterprises in a dozen countries across four continents, and has experience managing infrastructure so sensitive it’s overseen by a dedicated agency, the U.S. Nuclear Regulatory Commission. The company has facilities with electrical equipment on-site that can be potentially used to deploy SMRs. It also has won significant support from the federal government, both in the form of a $1.52 billion loan the Department of Energy provided to finance the Palisades restart and the $400 million the agency gave the company to support construction of its first SMR-300s.
“We began work in 2011 on a small modular reactor solution, and drawing on our in-house capability to design, license, manufacture, construct, and commission nuclear systems, honed through decades of turnkey supply, we are now uniquely positioned to launch the development of our small nuclear reactor,” Krishna Singh, Holtec’s founder and chief executive, said in a letter to prospective investors.
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