Back
It’s been a rollercoaster of a year for clean energy. There’s no better way to show those ups and downs than with a chart, and luckily, we made a lot of those this year.
As 2025 comes to a close, let’s focus on just the ups. Here are 10 charts that prove the clean energy transition is still marching on in the U.S. and beyond.
We started 2025 with news of a big win from the year before. The U.S. added 56 gigawatts of power capacity to the grid in 2024, and nearly all of it came from solar, battery, wind, nuclear, and other carbon-free installations.
Solar, with 34 GW of new construction, made up more than half of the new additions. Batteries had a stellar year, too, nearly doubling the previous year’s total.
March brought a huge victory for clean energy in the U.S. Solar, hydropower, biofuels, and nuclear were all part of a clean team that covered 51% of electric power demand that month, while fossil fuels accounted for the remainder.
It’s not a surprise that this win came when it did. Milder temperatures that arrive with spring mean Americans are starting to switch off their heat, but don’t yet need air-conditioning, creating a low-demand “shoulder season.” Still, this chart shows how quickly the U.S. has closed a yawning gap between clean and fossil fuel power generation.
The U.S.’s steel and ironmakers are recording slow but steady progress toward getting off coal.
Steelmaking’s reliance on coal makes it one of the world’s dirtiest industries, but all new capacity in the works as of May will use technologies that sidestep the need to burn the fossil fuel. That includes several electric arc furnaces capable of producing millions of metric tons of steel each year.
The U.S. does still rely heavily on coal-fired blast furnaces to purify iron ore. But forthcoming projects will all use direct reduction, which uses natural gas as a fuel — and ironmakers could eventually replace that gas with carbon-free hydrogen.
As of mid-year, the world was on track to spend $2.2 trillion on renewable power, low-emission fuels, the power grid, and other clean energy sectors. Fossil fuels were on track to reap half of that: $1.1 trillion.
It’s a big shift from a decade ago, when coal, gas, and oil investments dominated energy spending. But with China leading the way, clean investments have surged.
Europe had a squeaky clean June. For the first time ever, solar provided more of the EU’s power than any other source, beating both gas and coal power combined. Solar power provided 22.2% of the region’s electricity, with nuclear at its heels, and wind also beating gas generation.
Just a decade ago, coal provided a quarter of the EU’s power, while solar generated just a sliver. Now, those electricity sources are on track to trade places.
The first half of 2025 produced a worldwide win for renewables. January through July was the first time in history that renewables produced more power than coal over that stretch.
Solar’s monumental rise is the main reason for the shift: The source more than doubled its share of global electricity production from 2021 to 2025. And while coal still remains the world’s largest source of electricity, it’s declining while solar and other renewable sources are on the rise.
U.S. battery storage deployment has skyrocketed over the past five years, and that progress isn’t stopping anytime soon. Over the next five years, the country will build nearly 67 gigawatts’ worth of new utility-scale batteries, BloombergNEF estimates.
If that comes to fruition, the U.S. will have nearly triple the battery storage capacity it does now. And there’s evidence to suggest it will: The One Big Beautiful Bill largely left utility-scale battery storage incentives intact, for starters.
Energy storage is crucial for renewables to take root, as batteries can store solar and wind power for use when the sun isn’t shining and wind isn’t blowing.
The latest data shows solar and wind made a speedy ascent this year — so speedy that they’re more than covering new power demand around the world.
Between January and September, power demand around the world rose by 603 terawatt-hours compared to that same time period last year. Solar met nearly all of that new demand on its own, and with a boost from wind, was able to cover all of it.
That’s a huge deal for the clean energy transition. When we produce more renewable power than is needed to cover growing demand, that’s when we can start chipping away at fossil fuels.
EVs may have faced a year of setbacks in the U.S. and beyond, but they’re still on an upward trajectory worldwide. Nearly 11 million new EVs were sold around the globe last year, with most of those new EVs hitting the road in China. Sales of plug-in hybrids and hybrid electric cars are on the rise too. Compare that to 15 years ago, EVs and hybrids were practically nonexistent.
Meanwhile, internal combustion vehicles are officially past their peak. At their all-time high in 2017, global sales of pure ICE vehicles hit 79.9 million units. Last year, sales dropped to 54.8 million.
Our final chart of the year is the ultimate bright spot. While the vibes suggested this would be a dismal year for clean energy deployment in the U.S., it simply wasn’t. Solar, wind, and storage accounted for 92% of new power capacity added to the grid this year through November. It all goes to show that while fossil fuels still produce most of the country’s electricity, clean energy’s growth is hard to stop.
For press releases, policy changes, and promises to build new nuclear power, 2025 was a gangbusters year. For actually adding new reactors to the grid, not so much.
In fact, around the world, more gigawatts’ worth of nuclear reactors were retired than turned on this year, according to new data from the consultancy BloombergNEF.
In the 11 months leading up to Dec. 1, only two new reactors came online, totaling 1.8 GW. Meanwhile, seven reactors totaling 2.8 GW of capacity were permanently shuttered. The net effect? Global nuclear operating capacity declined by just over 1 GW. Overall, the world had 417 reactors in operation churning out 337 GW of power as of the start of this month.
Belgium led the retreat, shuttering two reactors this year, even as the country’s lawmakers voted in May to repeal a 2003 law that required the country to phase out nuclear power entirely.
Taiwan also contributed to the decline when it closed the last reactor at its Maanshan plant on the island’s southern tip, completing the country’s long-awaited exit from atomic energy. Russia will round out the closures by decommissioning three 12-megawatt units at a plant in the Arctic by the end of this month.
The shutdowns are the result of a yearslong pullback on nuclear power across much of the world, with China and Russia being the key exceptions.
But they also come at what may be a turning point for that global retreat from nuclear. Around the world, new technologies are racing toward maturity, shuttered reactors are being revived, and dealmakers are seeking to shore up the future supply of clean electricity by investing in new nuclear power. Next year is the first time in at least 15 years that zero reactors worldwide are slated to shut down. While closures will pick up again in 2027, new capacity is projected to dramatically outpace shutdowns through 2029.
The West and its allies have struggled to build and maintain reactors, and recent developments affecting South Korea, one of the more efficient nuclear developers, will not make matters easier.
The country’s state-owned nuclear companies have managed to avoid the sluggish build-outs that have plagued other developers. In June, however, South Korean voters returned to power the center-left Democratic Party, which tried to phase out the industry entirely the last time it held the Blue House. Further, an intellectual-property dispute between the American nuclear champion Westinghouse and Korea’s state-owned companies — Korea Electric Power Corp. and its subsidiary Korea Hydro & Nuclear Power Co. — came to a close this year with a settlement that bars Seoul’s firms from competing for projects in North America, most of the European Union, Britain, Japan, and Ukraine.
On top of that, according to Chris Gadomski, the lead nuclear analyst at BloombergNEF, “there’s a lot of hesitation among countries in the world to do business with the Chinese,” who are currently building reactors at a far faster rate than any other country.
That makes President Donald Trump’s efforts to revive nuclear construction at home and sell more reactors abroad particularly impactful for the industry’s future in the West and among its allies, especially countries in Africa and Asia building nuclear plants for the first time.
“The No. 1 question is how effective Trump’s pushing and shoving will be,” said Gadomski, who authored the market overview report published last week. “He’s really trying to reestablish American nuclear dominance.”
Unlike buying solar panels or batteries from China, nuclear reactors are century-long commitments between the construction, operation, and eventual decommissioning of the plant. Each of those steps is traditionally carried out by the vendor country.
“People are just concerned, so there is an opening for U.S. technology to be exported overseas,” Gadomski said. “People are dying to get U.S. technology.”
But right now, he warned, the small modular reactors attracting most of the attention have yet to be proven. And the only new reactor the U.S. has built from scratch on its own turf since the 1990s is the Westinghouse AP1000 at Southern Co.’s Alvin W. Vogtle Electric Generating Plant in Georgia. The two new units there ran billions of dollars over budget.
Estimates from the Massachusetts Institute of Technology suggest that the next AP1000 will come in significantly cheaper than even the shrunken-down small modular reactors currently under consideration, since the supply chain and design are now cemented. Indeed, Vogtle Unit 4 came in roughly 30% cheaper than Vogtle Unit 3, the first AP1000 to be built in the U.S.
Washington is working to expand the AP1000’s footprint. Both the Export-Import Bank of the U.S. and the U.S. International Development Finance Corp. have expressed interest in financing the construction of Poland’s first nuclear plant, made up of three AP1000s. In October, the Department of Commerce announced a deal with Japan to furnish Westinghouse with at least $80 billion to build 10 AP1000s in the U.S.
But Gadomski cautioned that the willingness to make such big investments largely hinges on the rising demand for power from data centers providing artificial intelligence software.
“If the AI boom collapses, we won’t need so much energy,” he said. “We’ve got tons of cheap natural gas, and there are technical and social risks to building out nuclear.”
Two years ago, Massachusetts regulators created a framework for phasing out the use of natural gas in buildings — a groundbreaking move for the state’s decarbonization efforts. Today, however, momentum has slowed as gas companies clash with lawmakers, regulators, and advocates on a fundamental question: Are utilities legally obligated to provide gas service to any consumer who wants it?
The debate may seem arcane, but at stake is the speed and scope of Massachusetts’ clean energy transition — and one of the nation’s first major attempts at a managed shift away from gas.
National Grid, Eversource, and other gas utilities say the answer is a resounding yes. The ability of residents and businesses to choose gas service is a “fundamental right,” said Eversource spokesperson Olessa Stepanova: “We cannot force them off that service.”
On the other side of the argument, advocates contend that safeguarding public health and fighting climate change are urgent benefits that outweigh individual customers’ personal preferences for one kind of fuel. The obligation, in their view, is to provide functional heating — not a specific source. The utilities, they say, are looking for ways to delay an inevitable upheaval in their industry rather than collaborating on a smooth transition.
“They see this as an existential threat to their business model, and they are digging in. They’re not at the table,” said James Van Nostrand, who chaired the Massachusetts Department of Public Utilities when it issued the 2023 order, and who is now policy director at The Future of Heat Initiative.
Massachusetts has long been a leader in pushing for a transition away from using natural gas and other fossil fuels to heat buildings and to fuel stoves and dryers.
In October 2020, the state was one of the first in the nation to launch a “Future of Gas” investigation, a process examining how gas companies can play a role in the clean energy transition and what that should look like. In December 2023, the state Department of Public Utilities wrapped up the investigation with a 137-page report that spelled out a clear vision of stopping the expansion of gas service and decommissioning some portions of the infrastructure, but largely left it to lawmakers, regulators, and utilities to enact the principles outlined.
The future laid out in the document goes like this: Rather than automatically investing in new gas infrastructure or replacing aging pipes, utilities will look for opportunities to deploy “non-gas pipeline alternatives” — like geothermal networks, air-source heat pumps, energy efficiency, or demand response — that can meet customers’ needs. Gas utilities will proactively coordinate with electric utilities to ensure the poles and wires can accommodate, say, switching dozens of houses in an area to heat pumps. The order also calls for utilities to undertake demonstration projects to test out the process of transitioning neighborhood-scale portions of the gas system to electrified heat or thermal networks.
The order called for gas utilities to submit plans detailing how they would assess whether an area could be equally or better served by a non-gas option. They did so in April 2025, but there is a catch: Utilities insist that they need customers to agree to participate in any such alternatives.
“It’s very hard to accomplish any decommissioning if you have to have that 100% buy-in from all the customers,” Van Nostrand said.
At the heart of the utilities’ argument is the legal concept of “obligation to serve.” The idea, a common principle in utilities regulation, is that a gas utility can’t just cut off customers it is already serving; if you want to keep gas, you get to. Requiring customers to modify their equipment would infringe on their constitutional property rights, the gas utilities argue.
The Mass Coalition for Sustainable Energy, a coalition of business groups, labor unions, and professional associations, has its own concerns about accelerating a transition away from natural gas. The group argues that pushing customers from gas to electric heat could increase energy bills and possibly compromise grid reliability.
Advocates, however, say the utilities are seizing on the idea of obligation to serve to justify dragging their feet on a transition they don’t want to see happen.
“If policymakers are trying to do something utilities don’t like, delay is always a tool they will use to resist it,” said Caitlin Peale Sloan, vice president for Massachusetts at the Conservation Law Foundation.
What’s more, according to advocates, lawmakers, and the state attorney general’s office, is that the utilities are wrong on the law. They argue that utilities are allowed to withdraw gas service in certain circumstances, such as lack of payment or for reasons of health, safety, and other purposes defined in law. A climate law passed in 2024, they say, provides such a definition by specifically identifying the reduction of greenhouse gas emissions as a factor that may be considered when deciding whether gas service can be discontinued. It also specifies that regulators must consider whether “adequate substitutes” are available for heating and cooking.
Furthermore, the utilities’ argument about the importance of consumer choice ignores the fact that their position takes away choice from the households who would want to join a geothermal network, said Amy Boyd Rabin, vice president of policy and regulatory affairs for the Environmental League of Massachusetts.
“I want customers to be able to move into the future and not be weighted down by having to continue to pay for a fossil fuel infrastructure that they didn’t ask for and they don’t want,” she said.
The Department of Public Utilities is currently in the process of asking utilities for more details about their arguments and considering feedback from other stakeholders. Advocates expect that regulators will ultimately disagree with utilities’ understanding of the obligation to serve, sending the question to court.
Though Massachusetts was among the first to start formally planning a transition off gas, the utilities’ resistance means the process is moving too slowly, advocates said. And substantial progress is unlikely to occur until the question of what obligation to serve really entails is settled.
“That’s a very important legal question that underpins any attempt to move forward in a meaningful way on gas transition,” Peale Sloan said.
Kansas ranks among the sunniest states in the nation, and its famously flat landscape is ideal for vast rows of solar panels. Yet it ranks just 41st for solar installations, raising the question: What’s the matter with Kansas?
The simple answer is that on the gusty Great Plains, wind energy gained an early foothold and dominated the renewable buildout. The wonkier explanation points to the state’s weak incentives — including a voluntary renewable energy portfolio standard and a limited net-metering rule — as well as pushback from residents who don’t want to live next to solar arrays. As a result, the state has few utility-scale solar installations.
The developer of a 270-megawatt project in the northwestern corner of Kansas thinks the Sunflower State’s solar industry is poised to bloom.
Last week, Doral Renewables announced a power-purchase agreement for its Lambs Draw Solar project in rural Decatur County, bordering Nebraska. The company declined to disclose its offtaker, but CEO Nick Cohen said, “It’s a major tech company with a big name that does a lot of data centers across the U.S.”
“This is a turning point,” Cohen said. “You’re going to see more and more solar in places like Kansas.”
As recently as five years ago, he said, “it would have been wind.” But the best tracts of land for building turbines have already been developed.
The data indicates that a solar boom is indeed getting underway in Kansas — one in which Lambs Draw will be a key participant but far from the only one. In May, the state plugged in its first major project in the 189 MW Pixley Solar Energy installation, a big leap from the state’s second-biggest array of just 20 MW. Several even larger projects are expected to come online over the next few years, including a sprawling 510 MW installation slated to go live next December.
Construction hasn’t yet begun on Lambs Draw, but Cohen said the site is “shovel ready” and expects the project to benefit from safe-harbor rules that allow developers to lock in expiring federal investment tax credits by breaking ground early next year.
“What has happened is that solar has become the lowest levelized cost of energy of any new-build energy source out there,” Cohen said. “Solar has reached the tipping point where it’s the most economical and achievable energy solution in places like Kansas.”
Lambs Draw will span 4,000 acres leased from four landowners, though not all of it will host panels. Part of Doral Renewables’ strategy is to “use avoidance and what I call neighborly courtesy,” Cohen said. That means “getting more land than we need, then avoiding any sort of environmental features, whether it’s a habitat or wetlands.”
Then, he said, “we’ll ask neighbors, ‘Is it OK if we put this here?’”
The local acceptance matters. At this point, solar development is “not really a question of state by state anymore,” said Pol Lezcano, the director of energy and renewables research at the real estate and consulting firm CBRE.
“It’s more like a county-by-county issue,” he said.
The economic development agency in Decatur County lured Doral to the region in hopes of generating more tax income and finding a way for farmers to diversify revenue.
“They respect landowner rights as sacred,” Cohen said. “The officials in the county are also very professional and see this as a generational uplift for everyone. They’ve been incredibly friendly. They convinced us to come, and it worked.”
Part of Doral’s appeal was that Lambs Draw may, in fact, involve lambs. The company plans to incorporate agrivoltaics, with crops planted between rows of panels and livestock employed to graze and keep the grasses trimmed. Cohen said the company and its landlords haven’t yet decided what to plant.
Despite the acreage, Lambs Draw’s 270 MW is smaller than the Philadelphia-based Doral’s typical 500 MW project. The size, Cohen said, is limited by what the local power lines — which connect to the Southwest Power Pool grid system — can handle.
“Originally, we wanted it to be more, but ultimately the grid is a constraint,” he said. “It’s healthy at 270, and that’s where we’re going to keep it.”
Nationwide, Doral has 400 MW of solar in operation, another gigawatt under construction, and more than 15 GW in the queue.
The company hasn’t yet selected the panels for Lambs Draw. But its 1.3 GW Mammoth Solar project currently underway in Indiana uses panels from manufacturers in Texas and India. Doral expects to make a similar deal for Lambs Draw, allowing the company to obtain panels quickly enough to access sunsetting federal tax credits and avoid new restrictions on imports from China.
“Solar is a once-in-a-lifetime opportunity for rural America, and places like northwestern Kansas have an opportunity to have a competitive advantage,” Cohen said. “They have something other people don’t have: flat, tillable farm fields with a strong grid connection.”
American factories use lots of hot water and steam to produce everyday goods like milk, cereal, beer, toilet paper, and bleach. Most facilities burn fossil fuels to get that heat, emitting huge amounts of planet-warming pollution in the process.
Switching to electricity could significantly and immediately slash those emissions in many places, according to a new report by The 2035 Initiative at the University of California, Santa Barbara. Electric versions of industrial boilers, ovens, and dryers are already available, and newer models promise to boost factories’ efficiency and curb energy costs even further.
“We can make progress today with the technologies we have,” said Leah Stokes, an associate professor of environmental politics at UC Santa Barbara and one of the principal researchers for the report.
But electrifying factories is a far more complex undertaking than, say, trading a gasoline-fueled car for a battery-powered vehicle. The process involves making many head-scratching calculations and engineering choices, which is partly why companies have been slow to adopt electrified equipment. Stokes said the report aims to demystify some of those decisions so that U.S. manufacturers can start tackling their heat-related emissions.
“We wanted to answer this question [of] where is it most technologically and economically feasible to electrify industrial process heat today?” she said during a Dec. 16 webinar. The study also drives home the need to rapidly build more clean energy to power all that new demand.
Researchers simulated what it would look like to electrify nearly 800 large industrial plants within three sectors: food and beverage, chemicals, and pulp and paper manufacturing. These facilities use relatively low- and medium-temperature process heat — unlike scorching cement kilns or steel mills — and together account for about 40% of CO2 emissions from the U.S. industrial sector.
The UC Santa Barbara team modeled four scenarios for electrifying each of these plants, beginning with “drop-in electrification” — using electrode boilers and electric ovens and dryers — and progressively expanding efforts to include major energy-efficiency upgrades and advanced technologies, like high-temperature heat pumps from the startups AtmosZero and Skyven.
At the most ambitious level, electrifying these factories could slash the country’s emissions by 1.3 billion metric tons of CO2 equivalent by 2050, while also providing $475 billion in public health benefits by improving air quality, researchers found. The figures assume the U.S. electric grid will be running almost entirely on clean energy by mid-century, up from 40% today.
“This one space actually can contribute an outsize share of the global [climate] mitigation we need to keep our global temperature rise in check,” said Eric Masanet, a sustainability science professor at UC Santa Barbara who led the study with Stokes.
In certain cases, it can cost manufacturers about the same amount of money to get heat from electric systems rather than gas-fired ones, he said. That includes processes that use less intensive heat, like ethanol and plastics production, since heat pumps work more efficiently at lower temperatures. It’s also true for factories located in places where fossil gas is relatively expensive. In Delaware, New York, and Washington state, for example, companies enjoy a more favorable “spark gap” — the difference between electricity and gas utility costs for the same unit of energy delivered.
Just as cost varies by facility, so does the potential for emissions reductions. The largest CO2 savings are in states with low-carbon grids, like Washington, California, and Vermont. In places with dirtier grids, switching to electricity can actually increase emissions in the near term if utilities meet that demand with gas- and coal-fired power plants. But even in those areas, researchers expect that electric equipment installed today will still cut pollution over time as the grid gets cleaner.
For that to happen, factories will need a lot more wind, solar, geothermal, and other carbon-free sources to come online. Electrifying the processes included in the study could require 158 to 301 terawatt-hours of additional power, or about 16% to 30% of the electricity currently consumed by industry. That new load would add to the soaring demand that’s already coming from data centers and electrified homes and vehicles.
“If we want to bring the type of electricity to the industrial sector that it’s going to need … we’re going to need to improve the grid,” Sen. Sheldon Whitehouse (D-R.I.) said during the webinar, adding that streamlining the federal permitting process would hasten the build-out of new transmission and clean energy projects.
The UC Santa Barbara team outlined other policies that could accelerate industrial decarbonization, particularly for the facilities where electrification is more expensive than burning fossil fuels. A 30% federal investment tax credit or state-level grants would offset the up-front costs of investment in new equipment. A “clean heat” production tax credit would lower operating costs, as would reducing industrial electricity rates.
Stokes noted that, even without such incentives, cleaning up manufacturing would take a minimal toll on consumers’ wallets. Take breweries, which use heat for mashing, boiling, and fermenting ingredients and sterilizing containers. “Our modeling shows that even if electrification doubles the cost of energy as an input to beer production, it’s 1 cent per beer,” she said.
“This is something that we can do, and it’s super important,” she added.
Rooftop solar and home batteries are way more expensive in the U.S. than in most countries, largely due to slow and burdensome local permitting and utility interconnection processes.
But there are tools installers can use to bring down these so-called “soft costs,” which make up about two-thirds of the price of installing solar, batteries, and EV chargers in the U.S.
One of the most effective such tools is called the meter socket adapter — and major home-electrification companies are increasingly making use of it. Over the past few years, companies including Tesla, ConnectDER, and Enphase have won approval from a growing number of utilities to use these devices to circumvent complex electrical work that can add days of labor and thousands of dollars in costs to installations.
Recent regulatory momentum in California, the largest home solar market, is also boosting the tech, which takes the form of a metal ring that’s inserted between utility meters and the meter boxes that connect homes to the grid. Inside each meter socket adapter is all the technology needed to connect, protect, monitor, and control solar, batteries, EV chargers, and other electrical devices.
Using tools like these to decrease soft costs is increasingly important as utility bills climb nationwide and regulatory headwinds threaten to make solar more expensive. Federal tax credits for home electrification expire at the end of this year, and several states have pared back compensation programs for solar owners.
Meter socket adapters are also a no-brainer for installers to use, according to Marcelo Macedo, who previously worked at SolarCity and Tesla and now runs his own installation company, Coastside Clean Energy. He said they can turn a multi-day job into a simple, half-day, plug-and-play exercise, largely because they help standardize projects.
“You can supervise more people doing more work faster, and most importantly, more predictably,” he said. “You can more reliably close out jobs on a tighter time frame with fewer hiccups. Your time to cash flow is more predictable. That leads to saying yes to more jobs, and being able to get more jobs done in a month.”
Meter socket adapters can generate serious — if highly varied — savings.
So says Colby Hastings, senior director of residential energy at Tesla, whose meter socket adapter device called the Backup Switch has been approved for use by dozens of utilities across the country, including Green Mountain Power in Vermont, Commonwealth Edison in Chicago, and all of the biggest utilities in the solar-rich states of Arizona and California.
Where utilities have cleared their use, “the Backup Switch can save thousands of dollars on a typical installation in both material and labor,” she said.
Exact figures depend on the particulars of household meter design and configuration and what equipment is being installed. On average, the Backup Switch can deliver savings of about $335 in hardware costs and about $360 in labor costs per storage installation, according to a report Tesla published this summer. More complicated projects can see greater savings, Hastings said. And Tesla Cybertruck owners get the added benefit of being able to use the Backup Switch to connect their EV battery for home backup power.
Most of those savings come from avoiding the need to relocate key household circuits into a different electrical panel for battery backup, Hastings said. A separate remote energy meter will still be necessary for homes that only want to back up a subset of their circuits. But for whole-home backup setups using a Backup Switch alongside a Powerwall battery, installation can be as quick as “a few hours,” she said, compared to more than a day needed to install equipment and run conduits if a battery is installed without the Backup Switch.
To be clear, meter socket adapters aren’t helpful for every home that wants to go solar. But for those adding solar and storage or an EV charger, it’s more likely than not that they can speed things up and shave some cost.
Home design also matters. Meter socket adapters are particularly useful for homes with meter boxes located right above the circuit breakers. These “meter-main combos” are more common in warmer climates, including California, the country’s top home solar and battery market.
Meter-main combos can make it particularly hard to install home energy tech through the electrical panel, said Raghu Belur, chief product officer at solar microinverter and battery vendor Enphase. Their tight configuration leaves no room for the microgrid controllers that automatically isolate homes when the grid goes down, or the current transformers that can measure power flows on home circuits.
Meter socket adapters simplify things because they integrate all of these devices into a single unit. Enphase has its own meter socket adapter now approved by nearly 50 U.S. utilities.
“It has a powerful 200-amp switch inside it to isolate the home during outages,” Belur said of the device. “That dramatically reduces the balance-of-system costs” and can “save thousands of dollars in labor.”
Meter socket adapters are also far more elegant systems, said John Bergh, CEO of Bay Area solar installation company Cobalt Power Systems. He likened the custom-designed webs of electrical conduits, transfer switches, junction boxes, and electrical sub-panels typically required to install batteries to a “wall of spaghetti” on a home.
“If you think about one crew having to take three to four days to install a battery system with a traditional transfer switch or system controller or gateway, versus a crew that can now do multiple installations in one day with a Backup Switch and Powerwall 3, it’s much more scalable,” he said. That means getting “more clean energy installed faster, which is what we’re all looking for.”
But for meter socket adapters to put a real dent in soft costs, more utilities will have to let installers use them — and getting utilities comfortable with third-party devices that plug into their meters has been a long slog.
Whit Fulton, CEO of ConnectDER, knows just how long it has taken. He launched his meter-socket-adapter company in 2011, and won his first utility project in 2015 with Green Mountain Power, which is in the vanguard in deploying solar-charged batteries in households. Similar utility-led projects have followed in Arizona, Hawaii, and New York.
But it wasn’t until more recently that ConnectDER has been able to supply a meter socket adapter for use by solar and battery installers. “It’s been a crawl-walk-run approach,” Fulton said, driven as much by policymaker pressure as by utility acceptance.
One big win came in 2021, when Colorado state lawmakers passed a law that required utility Xcel Energy to allow customers to use meter socket adapters to connect solar systems. “Xcel adopted it, and it worked pretty well,” he said. “From there, we were off to the races,” with utilities in 25 states serving a collective 30 million households now allowing some use of ConnectDER’s meter socket adapter designed for installation with home solar systems.
A separate ConnectDER meter socket adapter designed for installation with EV chargers has also been approved for use by 21 utilities in 14 states, he said.
This summer, ConnectDER launched its latest product, dubbed IslandDER, built specifically to simplify whole-home battery backup systems that are an increasingly common add-on for homes installing solar or looking for alternatives to fossil-fueled generators, Fulton noted. IslandDER is being used by partners including Lunar Energy, FranklinWH, SolarEdge, and EcoFlow, with test installations in 12 states and larger-scale deployments expected next year, he said.
Getting approvals for these devices is not easy. Utilities are cautious by nature. For Tesla to notch its dozens of approvals, Hastings said it took years and “hundreds, if not thousands, of meetings.”
At the same time, California regulators helped push utilities to accept meter socket adapters with a decision this summer that “created a regulatory framework by which the utilities have to review products like these, and create an avenue for approval,” said Kyle Breuning, director of applications and fleet analytics for Lunar Energy, a home-battery and energy-controls startup.
Ultimately, Hastings would like Tesla’s Backup Switch to be an option for installers across the country. Right now, only about 40% of the projects installed today that could use a Backup Switch are allowed to do so, she said.
“It’s safe, it’s reliable, it’s field-tested. It has gone through extensive processes with many utilities,” she said. “I can’t think of any good reason not to approve it.”
A correction was made on Dec. 22, 2025: This story originally misstated Kyle Breuning’s title. He is now director of application and fleet analytics for Lunar Energy, not senior manager of applications engineering.
The Interior Department announced Monday it is pausing leases for all five large-scale offshore wind projects under construction in America, citing unspecified issues of national security.
Canary Media obtained a copy of a letter notifying one of the affected wind farm developers, providing new details about the move — the Trump administration’s most sweeping attempt yet to halt offshore wind construction.
A Bureau of Ocean Energy Management letter to Dominion Energy executive Joshua Bennett orders the Virginia-based utility to “suspend all ongoing activities” related to its Coastal Virginia Offshore Wind project, a 2.6-gigawatt wind farm slated to start coming online in less than four months, for “the next 90 days for reasons of national security.”
“Based on BOEM’s initial review of this classified information, the particularized harm posed by this project can only be feasibly averted by suspension of on-lease activities,” the letter reads.
The 90-day time frame is not mentioned in the Interior Department’s official statement on the order.
The letter adds that BOEM will work “in coordination with [the Department of War]” during the suspension to determine whether the risk posed by the Coastal Virginia Offshore Wind project can be mitigated. It also states that “BOEM will consider all feasible mitigation measures before making a decision as to whether the project must be cancelled.”
Ultimately, “BOEM may further extend the 90-day suspension period” based on its review of each project, according to the letter.
News of the pause was first reported by Fox News. Wind developers didn’t receive stop-work orders via letters from BOEM until roughly an hour or two later, according to a person familiar with the matter who was granted anonymity because they are not authorized to comment publicly.
The letter obtained by Canary Media mentions an “assessment” completed by the “Department of War” in November that contains “new classified information, including the rapid evolution of relevant adversary technologies and the resulting direct impacts to national security from offshore wind projects. These impacts are heightened by the projects’ sensitive location on the East Coast and the potential to cause serious, immediate, and irreparable harm to our great nation.”
There is currently one large-scale offshore wind installation operating in the U.S. — the South Fork Wind farm off the coast of New York — as well as two pilot-scale projects generating electricity near Block Island, Rhode Island, and Virginia Beach, Virginia. The letter makes no mention of these East Coast projects or any national security risks their operation may pose.
The letter was signed by Matthew Giacona, the acting director of BOEM, a young political appointee and former oil and gas lobbyist for the National Ocean Industries Association.
In October, congressional Democrats asked the Interior Department’s inspector general to investigate Giacona following revelations, first reported by the news site Public Domain, that he has used his BOEM position to work on niche policy matters previously the focus of his oil lobbying role.
The Interior Department’s press release about the pause also cites claims not included in the letter to Dominion Energy, including mention of a 2024 Department of Energy study that determined offshore wind turbines could cause radar to “miss actual targets” while also noting that “wind energy will play a leading role in the nation’s transition to a clean energy economy.”
Dominion Energy did not respond to a request for comment.
A spokesperson for Equinor, the partially state-owned Norwegian energy firm that is developing the Empire Wind project off the coast of New York, said, “We are evaluating the order and seeking further information from the federal government.”
The Trump administration had previously hit two of the affected projects — Empire Wind and Revolution Wind — with stop-work orders. Both installations were later allowed to proceed, although that construction pause cost Equinor nearly $1 billion. The remaining three projects, Coastal Virginia, Vineyard Wind, and Sunrise Wind, had been spared until now. Several of these projects are more than halfway complete; Revolution Wind is at least 80% finished.
Monday’s announcement is not the first time the administration has used national security as an excuse for throwing sand in the gears of offshore wind.
Upon pausing the Revolution Wind project in August, Interior Secretary Doug Burgum invoked national security concerns, including the threat posed by “undersea drones.”
But between 2020 and 2023, the Revolution Wind project endured an extensive regulatory review, including by the Pentagon and Federal Aviation Administration. BOEM approved the project under the condition that all turbines be built to lighting and marking standards that would ensure they’re visible to aircraft at night. Radar mitigation requirements were mentioned in the approval, demonstrating stakeholder engagement on this issue. In August 2023, the U.S. Army Corps of Engineers — a branch of the military — co-signed the authorization of plans for Danish developer Ørsted to build 65 wind turbines for the Revolution Wind project.
“Was the military at the table, represented and consulted with during this stakeholder process? The answer is: very much so,” wind energy veteran Bill White told Canary Media in August. From 2009 to 2015, White represented Massachusetts on a BOEM-led intergovernmental task force focused on the siting of New England offshore wind energy areas.
In February 2024, a Brown University research group examined 441 claims made against offshore wind during the first six months of 2023. They found multiple times “military readiness” and “radar interference” were mentioned in ways that the researchers found misleading or problematic.
“[S]uggesting that our military is unaware of this issue or has done nothing to address it is completely untrue,” the report concluded.
J. Timmons Roberts, a co-author of the report and a professor of environmental studies and sociology at Brown University, called the administration’s halt to five approved wind farms because of classified national security information “bonkers.”
“These claims aren’t new and they have been, in the past, shown to be quite baseless,” he said.
A correction was made on December 23, 2025: This story originally stated that Giacona had yet to receive Senate confirmation, but his position does not require such approval. It has also been updated to clarify the terms of Revolution Wind’s approval, which included radar mitigation requirements
It’s been a difficult year for clean energy in America. President Donald Trump entered office in January and promptly stopped the transition away from fossil fuels and toward solar, wind, and batteries in its tracks. Right?
Not quite. In fact, for all of Trump’s paeans to “beautiful, clean coal” and to natural gas, it’s clean energy that has once again led the way this year. Through November, 92% of new power capacity added to the grid in 2025 came in the form of solar, wind, or storage, according to Cleanview analysis of U.S. Energy Information Administration data shared with Canary Media.
That’s in line with figures from recent years. In 2024, 96% of U.S. capacity additions were carbon-free.
This year, solar alone accounted for half of new capacity added to the grid through November, while storage made up 31%. Despite Trump’s all-out assault on wind energy — and his pledge that no “windmills” would be built during his term — the energy source has so far accounted for more gigawatts of new electricity than gas turbines have.
It’s worth noting that December is typically the busiest month for new energy deployments in the U.S., so these numbers will look a bit different when the full-year data comes in. It’s also possible that clean-energy deployments are artificially high right now as developers race to complete projects before Trump’s restrictions on lucrative tax credits kick in. And, overall, fossil fuels still generate a much larger share of U.S. electricity than renewables do — even if solar and wind are closing that gap.
Still, the figures underscore the warnings made by energy experts, policymakers, and advocates: The Trump administration is playing with fire by trying to limit the development of solar, battery, and wind energy right when electricity demand is rising at its fastest rate in decades.
These are the quickest sources of energy to deploy. Meanwhile, gas turbines face a supply-chain crunch that is both driving up the cost of some new power plants and making it near impossible to build enough gas facilities to meet new demand, even if climate concerns weren’t a factor.
Should Trump administration policies succeed in drastically slowing down solar, batteries, and wind next year, it’ll only make the mounting energy-affordability crisis even worse.
This year in energy has been an absolute blur. We started with President Donald Trump’s declaration of a federal energy emergency, saw the gutting of clean-energy tax credits, and finished with an Election Day where affordability took center stage.
Now, with 2025 almost behind us, let’s rewind and revisit the 10 stories that defined this year.
Trump declares an energy emergency
On his first day in office, Trump set course for a total revamp of the American energy landscape. Step one: Citing rising power demand to declare a national emergency on energy, all while freezing funds for clean energy programs. Trump proceeded to use that “emergency” to prop up fossil fuels — more on that below.
Interior Department halts — then restarts — Empire Wind construction
The Trump administration’s laser focus on killing offshore wind became impossible to ignore when, in April, it ordered Empire Wind to stop work. The turbines off New York had only been under construction for a few weeks, and the stop-work order was eventually lifted. The story essentially repeated itself a few months later with the nearly complete Revolution Wind project.
The Department of Energy forces coal plants to stay open
In May, the U.S. DOE cited its “emergency” to force Michigan’s J.H. Campbell coal plant to run past its retirement date. That order has been extended twice, and so far, the plant has racked up more than $100 million in costs for utility customers. The DOE later ordered other soon-to-retire fossil-fueled plants to keep operating.
The “Big, Beautiful Bill” guts clean energy incentives
On the Fourth of July, Trump signed into law the One Big Beautiful Bill Act, which was big but certainly not beautiful for clean energy. The legislation took an axe to the Biden administration’s Inflation Reduction Act and its tens of billions of dollars in funding for the energy transition.
Nuclear gets a federal boost
At least one carbon-free power source has been exempt from Trump’s hit list. The administration has elevated nuclear power as a solution to rising power demand, including by promoting the restart of some retired nuclear plants. It’s also poured funding into the development of small modular reactors and other next-generation technologies.
Batteries have a stellar year, again
Energy storage was also spared the Trump administration’s wrath, though tariffs and “foreign entity of concern” rules will likely weaken the industry. Still, the U.S. installed 12.9 GW during the first three quarters of the year, already beating 2024’s total installed capacity of 12.3 GW.
EVs’ record quarter and collapse
Federal tax credits for EV purchases went out with a bang. In the three months before their expiration at the end of September, the U.S. saw nearly 440,000 new EVs hit the roads, smashing the past quarterly sales record. But now that we’re in a post-incentive world, EV sales have sunk.
Blue-state climate grants slashed
One of the Trump administration’s biggest attacks on clean energy came in October, when the DOE moved to claw back nearly $8 billion in grants for climate and energy projects, largely in states that voted for Democratic nominee Kamala Harris in the 2024 election. The Justice Department later admitted in a court filing that those states’ politics put them in the administration’s crosshairs.
Data center opposition reaches a fever pitch
Data centers and their potential to use huge amounts of energy became a top concern in 2025, especially in hot spots like Virginia and Texas. State legislatures introduced close to 200 bills regarding data centers this year, with about 50 aimed at incentivizing their development, and others targeting their impact on the environment and on electricity costs for other consumers.
Energy affordability defines state elections
Democrats swept this year’s few statewide elections, many of which centered on rising energy prices. Both New Jersey Gov.-elect Mikie Sherrill and Virginia Gov.-elect Abigail Spanberger campaigned on promises to tackle spiking energy costs, and the two Democrats who won seats on the Georgia Public Service Commission said they’d push to build more clean, cheap energy.
Ford trades EV ambitions for battery storage
From electrifying its bestselling F-150 to building a massive manufacturing complex in Tennessee, Ford once aspired to lead the EV transition. That all changed this week as the company announced it will incur nearly $20 billion in charges to extricate itself from its EV investments. That Tennessee facility, known as BlueOval City, will build gas-powered trucks in lieu of electric models, and production of the F-150 Lightning will end.
But as Ford backs away from EVs, it’s entering a new market. The automaker will repurpose its Kentucky EV battery facility to build grid-scale batteries instead. As Canary Media’s Julian Spector put it, Ford is essentially copying Tesla’s game plan to expand into storage — but without an EV stronghold to fall back on, it could be a risky move.
Another coal plant restart — and more to follow?
As you read above, the Trump administration’s coal plant restarts are a huge piece of its fossil-fuel-boosting agenda, and we got two more updates on that front this week. On Tuesday, the DOE ordered Unit 2 of TransAlta’s Centralia, Washington, coal power plant to stay open for the next 90 days. TransAlta has been planning since 2011 to shutter the facility, and was prepared to do so this month to comply with a Washington state law prohibiting coal burning that takes effect next year.
A similar situation may soon play out in Indiana, Canary Media’s Kari Lydersen reports. Two coal plants in the state are supposed to close this month, but their owners have told regulators they anticipate orders from the Trump administration will keep the facilities running.
Also this week: The U.S. House passed a bill that will broaden the Federal Energy Regulatory Commission’s authority to keep power plants online past their scheduled retirements.
Not so fast: The U.S. House passes the SPEED Act, an attempt at revamping the National Environmental Policy Act to hasten energy project permitting, but the bill faces a big hurdle in the Senate: opposition from climate-hawk Democrats. (Inside Climate News)
The sun is setting: Solar companies face a “mad rush” of customers looking to get panels before federal tax credits expire, leading to installation delays that could cause many hopeful buyers to miss out on the incentives. (The Verge)
Can you dig it? A Colorado coal town prepares for the closure of its nearby power plant by building an industrial park that aims to attract businesses by offering low-cost geothermal heating and cooling. (Canary Media)
Fusion fight: China pulls ahead in its race with the U.S. to prove and commercialize fusion energy technology, largely because it’s devoting far more resources to the effort. (New York Times)
Keeping renewables rolling: Tribal nations look to loans and philanthropy to keep building planned clean energy projects after the Trump administration revokes the Solar for All program and other federal funding. (Utility Dive)
Planning committee: A New Hampshire program that deploys experts to help small towns plan for a transition to clean energy inspires a federally funded nationwide pilot. (Canary Media)
Winter woes: The National Energy Assistance Directors Association predicts U.S. home heating prices will rise an average of 9.2% this winter compared to last — about three times the rate of inflation — thanks to increasing gas and electricity prices and cold conditions. (New York Times, news release)
The Georgia Public Service Commission on Friday approved a controversial plan that will allow the state’s biggest utility to commence one of the largest new fossil-fuel buildouts in the country — a move that critics fear will raise utility bills for most Georgia residents over the coming years.
The last-minute settlement was approved unanimously by the five commissioners, all Republicans. The vote came just weeks before two of those commissioners are set to be replaced by Democrats who won upset victories in the November election by running on the issue of energy affordability.
Back in November, staff at the PSC recommended that the commission allow Georgia Power to build only about one-third of the nearly 10 gigawatts of new gas-fired power plants and batteries the utility had requested. Friday’s decision instead gives it the go-ahead to move forward on building the full total.
The utility has justified that scale by pointing to forecasts of booming electricity demand due to new data-center construction. In recent weeks, however, even Georgia Power has reduced its data-center demand projections. And across the state and the country, concerns are rising that the boom in artificial intelligence that is driving data-center investments may be a bubble about to burst.
That’s why PSC staff deemed the utility’s full buildout plan too risky — and why energy experts and consumer and environmental advocates oppose it. Should Georgia Power build all of that infrastructure while data-center demand fails to materialize, its customers would be forced to pay higher bills for the unnecessary power plants.
“It is a massive financial gamble,” said Jennifer Whitfield, a senior attorney at the Southern Environmental Law Center, one of several groups protesting Georgia Power’s gas-heavy buildout plan. “The bottom line is that we don’t need this much energy based on the data that’s been provided.”
The PSC staff expect the plan to raise average household utility bills by about $20 per month, or possibly more if gas prices rise or data-center demand fails to show up, according to testimony from November. Those costs would be layered on top of six rate hikes since late 2022 that have already increased average residential bills by $43 per month, and which helped propel the two incoming Democratic commissioners to victory in November.
Georgia Power can expect to profit handsomely from the commission’s decision. The utility revealed in a Securities and Exchange Commission filing last week that the plan would allow it to invest $16.3 billion in “company-owned projects” — capital investments on which the utility earns a guaranteed rate of return.
To avoid passing extra costs onto consumers, Georgia Power would need gigawatts’ worth of data centers to be built and to continue buying electricity for decades.
Right now, it’s highly uncertain whether those data centers will ever show up.
“[O]nly a fraction of the requested capacity is backed by data center customers that have signed contracts for electric service, and even less have signed contracts covered by the protections contemplated in the Commission’s new rules and regulations,” the Southern Alliance for Clean Energy and Sierra Club wrote in a briefing filed with the commission. “With no data center customer committed to pay for most of the capacity Georgia Power is requesting for the entirety of the assets’ lifetimes, ratepayers will inevitably be on the hook.”
PSC staff in November testified that only about 3.1 gigawatts of Georgia Power’s buildout should be approved right away, based on the number of data centers that have executed contracts with the utility. It also proposed allowing about 4.3 gigawatts more on condition that additional data centers sign definitive contracts by March 2026.
Indeed, PSC staff’s forecasts of demand growth between now and 2031 were far lower than Georgia Power’s: about 6 gigawatts less under a “lower large-load materialization assumption,” and about 4 gigawatts less under a “greater large-load materialization case.”
Utilities and regulators across the country are struggling to manage similar mismatches between the unprecedented boom in proposed data centers and the increasing uncertainty that those plans will come to fruition.
When the new Democratic commissioners take office next month, it’s unclear whether they’ll be able to adjust the plan or rein in costs.
Foes of the plan are pressing commissioners to use their authority to force Georgia Power to update its load-growth forecasts and report on changing costs for the power plants it plans to build, and to retract approval for spending plans that may no longer be justified by growing demand.
But Whitfield noted that Friday’s vote by the commission authorizes Georgia Power to begin charging customers for the expenses it incurs to build and procure the resources approved by the plan.
“If in the future the commission were to modify its certification order — which it could — Georgia Power would still be able to recover any costs it incurred up to that point,” she said.
It’s also unclear whether the settlement agreement will force Georgia Power to follow through on its public pledges to limit the impact of its data center–driven investments on everyday customers, Whitfield said. Her group filed a motion earlier this week asking the commission to order Georgia Power to provide more information about its plan to use revenue from data centers and other large customers to put “downward pressure” on rates for typical residential customers.
“There are so many loopholes in the financial assurances that staff tried to achieve when it entered into this stipulation,” she said. “The end result is nearly meaningless for a typical Georgia Power customer … The reality is, we just don’t have any reassurance that all of us aren’t going to be on the financial hook for it.”
.svg)
