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The U.S. House just voted to cancel efficiency standards for new manufactured homes — a move that could hit especially hard in the Southeast, where such housing is common and energy insecurity is high.
The measure would rescind 2022 criteria for insulation, air sealing, and other energy-saving features in prefabricated, or mobile, homes, restoring weaker standards more than 30 years old. The legislation comes as utility bills are rising fast nationwide — and if it is passed by the Senate and signed into law, it could cost households in double-wide houses hundreds more per year in increased electricity costs.
“The very first energy bill that the House of Representatives passed this year would increase energy costs on some of the households and families in the United States that are most struggling to make ends meet,” said Mark Kresowik, senior policy director with the American Council for an Energy-Efficient Economy. “This will have more harmful impacts in the Southeast than anywhere else in the country.”
Of the 4.7 million prefab homes delivered nationwide in recent decades, more than half are in just 10 southern states. Texas leads the country, with nearly 600,000 units, and North Carolina is second, with over 330,000, according to the U.S. Census.
Manufactured homes are exempt from state and local energy codes, and older models are notoriously energy inefficient, with thin insulation, drafty windows and doors, and often outdated modes of heating and cooling. Those who live in manufactured homes also tend to have less income than those in site-built varieties, making these needlessly high energy costs even harder to handle.
“Utility costs can be in the several hundred dollars for folks in a manufactured house,” said Claire Williamson, senior energy policy advocate at the North Carolina Justice Center, which advocates for low-income families. She added that “$300, $400, even $500 a month in peak costs is not trivial.”
The prefabricated homes exacerbate energy insecurity in the Southeast, which is the most energy-burdened region in the country: One in three households in the region struggles to pay their utility bills, according to the Southeast Energy Efficiency Alliance.
The U.S. Department of Housing and Urban Development last updated standards for manufactured homes in 1994. In 2007, a bipartisan law directed the Department of Energy to issue more protective rules. In 2022, the Biden administration finally did so, but the new criteria were paused last summer by the Trump administration.
The Manufactured Housing Institute, the trade group for prefabricated home builders, has long fought against the stricter standards, which it argues are too costly, confusing, and bureaucratic.
The bipartisan bill that passed the House last week largely gives the builders what they want, restoring the 1994 standards and preventing the Department of Energy from ever issuing stronger rules.
The 2022 rules were expected to cost an average of $4,222 per double-wide home up front but pay for themselves in the form of lower energy bills in less than five years. For single-wide units, the additional up-front costs were pegged at $660, which households would recoup within one year.
“This is so clearly about the homebuilder special interests,” Williamson said, “and has nothing to do with ensuring better, more affordable housing for people.”
About half of all factory-made homes are already built to efficiency standards that are much stricter than those rescinded by the House, said Grant Beck, vice president of strategic partnerships at Next Step Network, a Kentucky-based nonprofit that supports ownership of prefab homes.
This fact shows that better-built manufactured homes can benefit the industry and consumers alike, say affordability advocates, far better than the bill that’s now before the Senate.
“We understand that we’re in an affordability crisis, particularly with relation to housing and first-time home buyers trying to enter the market,” Beck said. “However, the lower purchase price on a home for a family is eroded if they’re unable to make monthly payments due to high and rising energy costs.”
Sergio Mendez was tired of earning a living by working security in nightclubs. So the 22-year-old resident of Chicago’s Southwest Side decided to make a big change, enrolling in a 10-week program that promised to teach him the fundamental skills needed to pursue a career in the solar industry.
“I was just dealing with a lot of drunk people. I wanted to get out of it,” Mendez said of his former job. Now he envisions a future as a solar salesperson or installer. In late December, he graduated alongside six other young adults enrolled in the course, run by Elevate, a national clean-energy nonprofit based in Chicago.
The cohort is stepping into an industry that experts say is going strong in Illinois, even as the Trump administration cancels clean-energy tax credits, claws back funding for pollution-reducing projects, and enacts other policies that make it harder to build renewable energy.
Illinois has emerged as a solar leader in recent years, thanks in large part to its robust incentives and its mandates that utilities get an increasing amount of electricity from renewables. In 2024, the state ranked fourth nationwide in terms of new solar capacity, with over 2,800 megawatts installed, and it added another 815 megawatts in the first three quarters of 2025, according to a December report by consultancy Wood Mackenzie and the Solar Energy Industries Association.
The industry’s momentum translates to lots of employment opportunities: The Solar Energy Industries Association counted almost 6,000 solar jobs in Illinois in 2025, and it projects that the state will add close to another 15,000 megawatts of solar over the next five years.
“With energy demand growing — some would say, out of control — solar is the fastest [generation source] to deploy,” said J.D. Smith, a spokesperson for the Wisconsin-based solar installer Arch Electric. “From a technical standpoint, if you’re trying to power the grid, [solar] is such a good decision. You can get it cheap and fast, and it’s repeatable.”
Companies expanding to meet that demand are eager to snap up graduates of workforce development programs.
In the past year, Arch — one of the employers at a December job fair for Mendez and his peers — has hired 14 graduates of training programs run by Elevate and other Chicago-area nonprofits. Seven of those individuals are already in apprenticeships to become certified electricians.
“If you know at least 50% of the people you hire from these organizations will want to be an apprentice and invest in their future with your organization, that makes it a business no-brainer,” Smith said.
Solar companies also rely on training programs to produce qualified candidates from what the state has defined as “equity” communities, he explained. Under Illinois’ 2021 clean-energy law, firms can access incentives for hiring individuals from these areas, which face disproportionate amounts of pollution and have historically been excluded from economic opportunities.
“There is an enormous demand for these programs,” Smith said. “We will take everyone we can get who is willing to invest their time and learn.”
The course that Mendez graduated from marks Elevate’s first solar training aimed specifically at adults between the ages of 18 and 24.
Many of the participants, including Mendez, are alumni of the Academy for Global Citizenship, a K–8 charter school on Chicago’s Southwest Side that hosted the course in two geodesic domes built specifically for the program. The school’s campus boasts both ground-mounted and rooftop solar panels, as well as a geothermal heating and cooling system.
“When you’re around it since you’re young, it’s just normal,” Mendez said of solar.
Solar training in session on Dec. 4, 2025, inside one of the geodesic domes at Chicago’s Academy for Global Citizenship (Kari Lydersen/Canary Media)
Over the course of Elevate’s training, students learned about everything from the basics of electricity to solar system installation. They got hands-on practice with panels and wiring and took a field trip to see one of Illinois’ many community solar arrays. And they prepared for the North American Board of Certified Energy Practitioners exam; a certification like the one issued by NABCEP is required to install solar on buildings in most states, including Illinois.
“We see how to set up a solar panel system, how all the parts work, how we make sure not to blow anyone up,” said student Josh Paz, age 23, another alumnus of the charter school. Before enrolling in Elevate’s training, he had worked in retail stores, in warehouses, and as a landscaper.
“I’ve always liked to work with my hands, so it’s pretty fun,” he said of solar. “And we’re building a cleaner future. America’s a little behind the rest of the world, but it’s good to see solar growing exponentially.”
Other graduates of the Elevate program are similarly bullish about building a career in clean energy — and using it to address societal injustices in Chicago and beyond.
“You see the discrimination, the amount of residential areas near power plants, all Black and brown people,” said 21-year-old Matthias Hunter. “The race for renewable energy in America is going to be a challenge, especially with this administration. But there’s light at the end of the tunnel. This is the future. It’s not optional.”
In the far reaches of Appalachian Ohio, DeepRock Disposal Solutions and other companies pump salty, hazardous waste from oil and gas fracking thousands of feet underground at high pressure. Last year, the state gave DeepRock permits to drill two more injection wells for pumping such waste underground. The new wells are slated for rural Washington County, which sits on Ohio’s southeast border.
The state’s approval has drawn fierce opposition from surrounding community members and local governments that fear waste from the wells could escape and pollute their drinking water supply. Leaks have happened before, including from some DeepRock wells. But these opponents haven’t been able to stop the company’s latest drilling plans.
This lack of local authority highlights an unfair discrepancy in Ohio, according to legal experts and clean energy advocates: While state law allows counties, townships, and disgruntled residents’ groups to delay or even doom many solar and wind developments, it blocks almost all local decision-making power over fossil fuel endeavors.
The difference between how Ohio law deals with renewables and petroleum “is night and day,” said Heidi Gorovitz Robertson, a professor at Cleveland State University College of Law.
On one hand, state law gives the Ohio Department of Natural Resources “sole and exclusive authority” to permit oil and gas activities. “So the local governments are cut out entirely,” Robertson explained, noting a 2015 Ohio Supreme Court decision that held that the state’s comprehensive regulation of oil and gas activities preempts even city zoning ordinances that would otherwise restrict that work.
On the other hand, a 2021 law lets counties ban new solar and wind development for most of their territory. Even for “grandfathered” projects that are technically exempt from such bans, the Ohio Power Siting Board has used opposition from local governments as grounds for finding such developments were not in the “public interest.”
“What you have looks like total inconsistency” when it comes to deciding which energy projects should go where, Robertson said.
That has serious implications for the energy transition: It holds back the projects that would slash planet-warming and health-harming pollution while further entrenching the lead that the oil and gas industry has in Ohio’s electricity sector.
Ohio also treats renewables differently than it does fossil fuel projects when it comes to letting the community participate in permitting decisions. The state lets disgruntled residents intervene as official parties in wind- and solar-permitting cases, which allows those individuals to appeal permit approvals to the Ohio Supreme Court. Yet residents cannot intervene or appeal in cases about where oil and gas activities go.
Advocacy groups such as the Buckeye Environmental Network say this imbalance is making communities like Washington County, where DeepRock plans to inject more fracking waste, less safe.
Fracking — a drilling technique to extract fossil fuels from rocks thousands of feet deep — produces millions of barrels of waste per year. Regular wastewater treatment plants can’t handle those super-salty fluids, which can contain heavy metals, radioactive chemicals, and company “trade secret” compounds. That’s why the waste is typically disposed of in deep wells.
Ohio had more than 200 active fracking-waste injection wells as of late 2024, with several already in Washington County.
Marietta, a city of about 13,000 on the Ohio River, abuts Warren Township, where DeepRock will drill the new wells. The city’s leaders worry that the waste could migrate out of the rock layer where it will be stored. A 2019 investigation found that waste had escaped from another injection well in Washington County, although it wasn’t discovered in drinking water at that time.
The Marietta City Council passed a resolution in October that noted problems with waste escaping from other wells, and it urged the state to place a moratorium on disposing of more fracking waste in the area. The city also tried to appeal one of DeepRock’s permits, but the Division of Oil and Gas Resources Management at the Department of Natural Resources responded that its Oil and Gas Commission, which reviews those administrative appeals, lacks jurisdiction for Marietta’s claims.
“People are saying we don’t want these injection wells,” said Roxanne Groff, an advisory board member of the Buckeye Environmental Network. “And the main reason is the water.”
Groff’s group is taking another approach to stopping the DeepRock project: It’s suing leaders at the Ohio Department of Natural Resources over the permits issued for the wells. The lawsuit, filed in November, argues the agency illegally relied on outdated regulations that were in effect when DeepRock first filed for its permits but that were replaced in 2022 by stricter rules meant to better protect public safety and health.
“The law is very clear in our view that [the department] should be applying the rules in place at the time of permitting,” said James Yskamp, a senior attorney at the nonprofit Earthjustice, which is representing the Buckeye Environmental Network. When DeepRock applied for its permits in late 2021, the current siting rules were already in draft form, and the public comment period on them had ended. Moreover, the agency didn’t complete technical reviews, provide public notice about the permits, or accept comments on them until last year.
Karina Cheung, a spokesperson for the Department of Natural Resources, said her agency has no comment on pending litigation. But she did note that any permit to operate the wells after they’re drilled will need to comply with current rules in the Ohio Administrative Code. That permit would control how the company pumps waste underground under pressure, but not where that waste goes. And the wells would already have been drilled.
Lawyers for the officials at the Department of Natural Resources and for DeepRock want the case dismissed. The department had no duty to apply the current law, the filings claim. And any harm is speculative, they argue, because it wouldn’t happen until after fracking waste is pumped down.
The Buckeye Environmental Network’s petition before the Franklin County Court of Appeals indicates the two DeepRock wells are approximately 2 miles from protected groundwater resources for people in the city of Marietta and Warren Township. Already-operating wells in the area pump tens of thousands of gallons of fracking waste underground each day. Injecting yet more fluids under high pressure could cause waste to migrate out of deep rock layers and up through rock fissures, abandoned wells, or other conduits, the group alleges.
These concerns are founded on evidence, Groff noted, unlike people’s objections to solar projects, which she said tend to be lacking in factual support or based on false information.
Robertson at Cleveland State has the numbers to back up that claim: She analyzed the grounds for testimony against a utility-scale solar project in a permitting case in 2024. Most objections either had no basis in fact or had already been addressed by permit conditions. The rest were statements of opinion.
To the extent there is any consistency in how Ohio treats different types of energy projects, “it’s that the oil and gas industry wins every time,” Robertson said. “The oil and gas industry benefits by blocking local voices in oil and gas industry decisions. And the oil and gas industry benefits by having local voices involved in the wind- and solar-energy decision-making.”
The Trump administration is going after gas bans in two California cities.
Last week, the federal government sued to block the San Francisco Bay Area’s Morgan Hill and Petaluma from prohibiting the use of fossil gas in new buildings. Both have populations of less than 60,000.
The complaint, filed in the U.S. District Court for the Northern District of California, alleges that the restrictions violate a 1975 federal law that governs appliance efficiency standards. Climate advocates decried the move as federal overreach.
“Mayors and the people who elect them should decide the type of energy that powers the future of their communities,” Kate Wright, executive director of Climate Mayors, said in a statement. “The Justice Department’s lawsuit does nothing but tie the hands of local leaders who seek to help families find relief from high energy prices.”
More than 150 local governments have adopted some form of zero-emissions standards for new buildings, from banning gas outright to encouraging electrification. Such rules can benefit not only households’ comfort, health, and resilience but also their pocketbooks. Depending on local factors such as weather and energy costs, residents could save thousands of dollars over the lifetime of their homes’ superefficient electric appliances.
Why did the Trump administration target Morgan Hill and Petaluma? “I see it as part of a … broader harassment campaign between the federal government and states and cities that it’s unhappy with,” said Amy Turner, director of the Cities Climate Law Initiative at Columbia University’s Sabin Center for Climate Change Law.
In April 2025, President Donald Trump signed an executive order requiring the attorney general to identify state and local laws “burdening the … use of domestic energy resources” — namely fossil fuels, not local solar or wind — and take “all appropriate action” to stop their enforcement.
Empowered, the Department of Justice sued four Democrat-led states last year: New York and Vermont to block Climate Superfund laws, which would make oil and gas producers pay for their greenhouse gas pollution; and Hawaii and Michigan to prevent them from suing fossil fuel companies for climate damages. The cases are ongoing.
Now the administration is attempting to crush municipal efforts to curb fossil fuel use in buildings. But whether the Department of Justice’s lawsuit will be viable remains in doubt, Turner explained. “There are some really significant questions around whether the federal government has standing to bring this case.”
Morgan Hill’s and Petaluma’s ordinances — passed in 2019 and 2021, respectively — are essentially relics of a laxer era when gas construction across California went largely unchecked, according to Matt Vespa, senior attorney at the nonprofit Earthjustice.
“California’s really moved on,” he said. “We have a very strong state code now [that’s] pushing buildings to be all-electric,” making it less important that cities themselves block gas hookups.
The Golden State’s latest building standard, which took effect Jan. 1, encourages gas-free construction more vigorously than ever, according to Vespa. The code is also technology-neutral, stopping short of banning new gas connections.
Instead, the rules require developers to meet specific efficiency standards, which are based on the performance of electric heat pumps, he said. Heat-pump appliances are about two to five times as energy efficient as gas furnaces and water heaters.
Developers could choose to install gas in their buildings anyway. But for an edifice to pass muster, it would need more efficiency improvements, such as a thicker jacket of insulation or triple-pane windows. Plus, the code requires that certain new buildings equipped with gas also be “electric-ready,” meaning they have the electrical service and wiring required for the structures to eventually go fully electric.
California is also shifting the economics of gas and all-electric construction. In 2022, the state nixed subsidies for gas lines to new buildings; and in 2024, it eliminated electric-line subsidies to mixed-fuel construction. What’s more, developers of all-electric homes can claim incentives of $1,400 to $5,500 per gas-free unit through the California Electric Homes program, which still has $24 million in its coffers.
In its court challenge against Morgan Hill and Petaluma, the Trump administration is using the same premise that struck down Berkeley, California’s pioneering gas ban in 2023.
In California Restaurant Association v. Berkeley, a three-judge panel for the 9th U.S. Circuit Court of Appeals ruled that the 1975 Energy Policy and Conservation Act (EPCA) preempts the city’s ban on gas hookups. The court’s reasoning, in brief, is that because this federal law prevents jurisdictions from deploying differing standards for the energy use and efficiency of covered appliances, it invalidates local bans preventing the use of gas appliances.
If you’re confused, you’re not alone. Many judges have found the EPCA argument flawed, even in the Berkeley case. When the three presiding judges decided not to authorize a rehearing en banc with a larger panel of judges in 2024, 11 circuit judges dissented. It was an unusual move, rarely done.
“In nearly a decade on the bench, I have never previously written or joined a dissent from a denial of rehearing en banc,” wrote U.S. Circuit Judge Michelle T. Friedland. “I feel compelled to do so now to urge any future court that interprets the Energy Policy and Conservation Act not to repeat the panel opinion’s mistakes.”
The opinion misinterpreted EPCA, she continued: “EPCA’s preemption provision guarantees uniform appliance efficiency standards. It does not create a consumer right to use any covered appliance” — such as a gas furnace.
In recent court battles invoking EPCA, judges have upheld the local laws restricting fossil fuel in new buildings in New York and New York City. These lawsuits — and many others brought on the same premise — continue to move through the courts. (In November, New York elected to pause its all-electric building standard, which would have taken effect at the end of 2025, for unrelated reasons.)
In the meantime, some towns have shifted to other tactics that encourage all-electric construction. New York City, for example, set an emissions limit of 25 kilograms of CO2 per million British thermal units that doesn’t explicitly prohibit gas use.
Regarding the future of all-electric buildings in Morgan Hill, Petaluma, and the rest of California, Vespa is sanguine.
“We see very high percentages of buildings going all-electric already,” he said. “Nothing about this lawsuit is going to change that.”
U.S. carbon emissions increased in 2025, even as clean energy installations surged.
Economy-wide emissions rose by 2.4%, according to a new analysis of federal data by the research firm Rhodium Group. This ended a two-year streak of emissions reductions and clocks in as the third-largest emissions increase in the last decade. The country is still emitting 18% less than it did in 2005 (compare that to President Barack Obama’s goal of a 26% to 28% reduction by 2025), but the economy has resisted a smooth glide toward decarbonization.
“It’s not the most notable increase that we’ve seen, but in the context of this bumpy downward trend, it is an up year,” said Rhodium Group research analyst Michael Gaffney.
Some of that emissions increase came from factors that Gaffney referred to as statistical “noise,” namely a very cold winter that pushed up space-heating needs in buildings. That kind of variation is to be expected. But changes in the power sector could be more potent signals of things to come.
The power sector has generally led the U.S. economy in emissions reductions, largely because gas plants have outcompeted coal plants over the last two decades, and gas emits less carbon when burned than coal. But in 2025, coal proved that it’s not dead yet. Natural gas prices rose by 58% over 2024 levels, under pressure from space-heating demand and global exports via liquefied natural gas terminals. At the same time, demand for electricity soared: Generation increased by 2.4% from the year before, as data centers, crypto miners, and electric vehicles consumed more energy.
Taken altogether, the rise in demand at a time when gas was less economically competitive gave coal an opening in the markets, and its generation surged by 13% in 2025.
“This year is a bit of a warning sign on the power sector,” Gaffney said. “With growing demand, if we continue meeting it with the dirtiest of the fossil generators that currently exist, that’s going to increase emissions.”
AI data center demand shows every sign of increasing far beyond 2025 levels in the years ahead. That’s while export capacity for liquefied natural gas is on track to double by 2029, greatly expanding competition for U.S. gas supplies. The Trump administration has issued a flurry of “emergency” orders to block coal plant retirements, and many utilities are also choosing to push back planned coal plant closures as they respond to the sudden growth in power demand, Gaffney said.
Coal generation has plummeted by 64% from its peak in 2007, but it has rebounded for brief periods along that trajectory. 2025 offered a reminder that coal isn’t on a one-way street to obsolescence. Even without new coal plant construction, existing plants can ramp up operations when the opportunity arises, and could well continue to do so over the next few years.
The data from 2025 also challenges another truism in climate advocacy circles: that breakthroughs in climate technologies have decoupled economic growth from emissions growth. Last year, though, emissions increased faster than real GDP, which grew by a projected 1.9%, per Rhodium.
“Were this to persist, this would be a troubling sign for the broader transition, just because we’ve predicated this whole thing on ‘you can grow the economy without exploding emissions,’” said Ben King, Rhodium’s director of U.S. energy projects.
The brightest spot for decarbonization came, not surprisingly, with the wild success of solar energy. The power industry is building more gigawatts of solar than any other type of plant, and that construction pushed solar generation up by 34%.
“We did see a record year for solar generation last year — but for that, we would be in a much worse position from an emission standpoint,” King said.
However, solar is growing very fast from a small baseline, and on a national level, it still lags behind natural gas, nuclear, coal, and wind in total generation. Without the tremendous solar build-out, utilities might have burned even more coal. But solar alone couldn’t satisfy the growing demand for electricity last year.
Looking ahead at the durability of these trends, King said, “the question is, to what extent can policy actions continue to suppress that solar growth?”
Solar installations last year rolled forward on momentum created by supportive Biden-era policies. But the second Trump administration has taken numerous actions to block or slow renewable power plant construction. If those efforts succeed in slowing the pace of solar development, and power demand and gas prices remain high, the country could be on track for more emissions increases in the years to come.
A federal judge has ruled that Ørsted can resume the construction of its nearly complete, 704-megawatt Revolution Wind project off the coast of Rhode Island.
The decision on Monday comes after the Trump administration issued stop-work orders to all five of the offshore wind projects under development in the U.S. in late December, the culmination of President Donald Trump’s yearlong war against the renewable energy source.
Revolution Wind, a $6.2 billion project that is nearly 90% complete, was hit with an earlier federal stop-work order in August from the Bureau of Ocean Energy Management, a division of the Interior Department. A federal judge ruled in favor of Ørsted in September, allowing the project to move forward until December’s order, which cited unspecified issues of “national security.”
On Monday, the Danish developer said it will “resume construction work as soon as possible” while its complaint against the Trump administration is heard by the courts.
Judge Royce Lamberth of the U.S. District Court for the District of Columbia, who issued the injunction, said from the bench on Monday that the bureau’s August suspension order was “the height of arbitrary and capricious” and that the December order’s vague claims of national security risks did “not constitute a sufficient explanation for the bureau’s decision to entirely stop work on the Revolution Wind project.” He noted that the government’s argument for halting construction was “unreasonable and seemingly unjustified.”
Each offshore wind project has been repeatedly vetted by the Department of Defense since being proposed, and developers said they were blindsided by the Trump administration’s latest security concerns.
Ørsted and two other offshore-wind developers, Equinor and Dominion Energy Virginia, all sued to vacate the Trump administration’s 90-day construction freeze from December. Ørsted’s court hearing was the first, and judges are set to consider the fate of the other in-progress offshore wind projects this week.
On Wednesday, a court could decide on Equinor’s 810-MW Empire Wind project, which also previously received and defeated a stop-work order. A hearing for Dominion Energy’s massive 2.6-gigawatt Coastal Virginia Offshore Wind project is scheduled for Friday. In addition to energy developers, the states of Connecticut, New York, and Rhode Island have all sued to get the projects going again.
The stakes are high: In total, the five offshore wind farms affected by the Trump administration’s December order would bring nearly 6 GW of capacity to the grid, or enough to power roughly 2.5 million homes across the East Coast.
The U.S. can’t afford to lose any of these projects. Energy demand is climbing across the nation, causing household utility bills to soar. More power plants are needed to keep bills from rising even further — especially in regions swamped with power-hungry data centers, like Virginia.
In addition, grid operators have been banking on the arrival of these large-scale offshore wind projects, several of which are more than halfway complete. In August, ISO-New England issued an unprecedented warning that the Trump administration’s first pause on Revolution Wind created “unpredictable risks” that could “undermine the power grid’s reliability and the region’s economy now and in the future.”
At least one project could be abandoned imminently. Equinor, which already lost nearly $1 billion because of the first stop-work order on Empire Wind, says the beleaguered project faces “likely termination” if it can’t continue work by this Friday.
Meanwhile, industry groups applauded Monday’s decision.
Kat Burnham, the New England policy lead for Advanced Energy United, said the D.C. court “rightly saw through a politically motivated stop-work order that would have caused real harm: driving up costs, delaying power for Rhode Island and Connecticut, and putting good-paying jobs at risk.” In a statement, she said the decision is “good news for workers, ratepayers, and anyone who recognizes the need for a fair energy market.”
The latest skirmish over offshore wind comes after a year of assault from the Trump administration. Trump has gummed up the build-out of onshore wind and solar power, too — but no energy source has been targeted like offshore wind.
The impact of Trump’s war on the sector is profound.
When he was reelected in 2024, BloombergNEF expected 39 GW of offshore wind capacity to come online in America by 2035. The research group hedged that number to 21.5 GW if Trump managed to repeal wind tax credits during his term. He did. As of October, BNEF expected just 6 GW to get online by 2035 — a number that will be even lower if any of the in-progress projects buckle under the weight of the latest order.
Out in the fertile yet water-constrained farmlands of California’s western Central Valley, a massive solar, battery, and power grid project that could provide a quarter of the state’s clean energy needs by 2035 has taken a critical step forward.
In December, the board of directors of the Westlands Water District, the agency that manages water delivery to more than 600,000 acres in California’s agricultural heartland, approved the Valley Clean Infrastructure Plan. VCIP calls for building up to 21 gigawatts of solar energy and an equivalent amount of battery storage across up to 136,000 acres, along with a series of high-voltage transmission lines to connect the electricity generated to the state’s grid.
That would be the largest solar and battery project in the country, and it will take up to a decade to be completed. But Patrick Mealoy, a partner and chief operating officer of Golden State Clean Energy, the company developing the master plan in partnership with the district, said it’s expected to move quickly, with the first construction work potentially happening within the next two years.
Golden State Clean Energy will carry out only a small part of the project, Mealoy said. It will mostly seek third-party solar and battery developers, with individual installations ranging in size from 100 to 1,150 megawatts.
Mealoy, a 30-year solar veteran, codeveloped Westlands Solar Park, the first major solar farm in the district. When fully completed, that project will be one of the largest in the Central Valley and produce 2.7 gigawatts — a fraction of VCIP’s scope.
The VCIP is designed to manage the multiple challenges that can stymie piecemeal solar and battery projects, such as winning environmental approvals, securing buy-in from landowners and communities, and interconnecting to the state’s congested transmission grid, Mealoy said.
“We’re doing the transmission studies, the environmental impact studies, and outreach to communities, all at the same time, to make sure there are no showstoppers.”
The VCIP is as much about preserving the region’s agriculture industry as it is about generating clean electrons, said Allison Febbo, the district’s general manager. That’s because the plan will allow the district’s more than 700 growers to redirect increasingly limited water supplies from land slated for clean energy development to land that remains under cultivation.
“The real benefit to us is that it gives our growers another crop to grow, which is the sun,” she said. “Our growers have this issue: ‘I have 100 acres of land but only enough water to irrigate 50 of those acres. What do I do with the remainder of those acres?’”
For decades, California’s Sacramento–San Joaquin River Delta has delivered water via the Central Valley Project’s system to irrigate the Westland Water District, the largest water district in the country. But in recent years, restrictions brought on by environmental and endangered species regulations for the delta have forced Westlands to fallow an increasing amount of farmland, expanding to more than one-third of its total acreage. And under the state’s Sustainable Groundwater Management Act, farmers will soon face stringent restrictions on how much water they can pump from the region’s long-stressed aquifers.
As more and more land has been left uncultivated, farm employment and property tax revenues have declined in the region. “The schools can’t be supported, the businesses can’t be supported,” Febbo said. “This is a way to maintain economic viability and support our communities.”
Mealoy said the VCIP could revitalize the region’s economy. “The cost of building solar is well north of $1 million per megawatt, probably closer to $1.5 million,” he said. Spread across 21 gigawatts of planned development, “that’s billions and billions of dollars that could be built on fallowed ag land, creating jobs and creating an enormous tax base for Fresno County,” which encompasses the land being set aside for development.
The economic benefits would extend beyond the region. An analysis commissioned by Golden State Clean Energy last year found that the clean energy and transmission congestion relief the plan would deliver could yield annual electricity cost savings of about $850 million and reduce the state’s power-sector carbon emissions by 15% through 2050.
The plan will also help reduce the grid congestion that’s created yearslong interconnection delays for large-scale solar and battery projects throughout the state, Mealoy said. In 2024, state lawmakers passed Assembly Bill 2661, a law that allows the Westlands Water District to develop its own transmission grid to get solar to market.
The project’s transmission infrastructure will be constructed under a project labor agreement using 100% union labor. That has won it the backing of the International Brotherhood of Electrical Workers Local 1245, which represents workers at Pacific Gas & Electric, the state’s largest utility.
Westland Water District’s approval of VCIP’s programmatic environmental impact report last month will allow the next big phases of the project to move ahead, Febbo said.
“With this master-planned approach, we’ll have one set of guidance, one set of rules. We’ll be able to handle how land is managed, how pests are managed, dust control — all of those things can be dealt with on a large scale.”
The project should deliver other benefits to the surrounding communities as well. Westlands Water District is bound by state law to develop community benefits agreements to provide funding for job training, environmental remediation, economic development, and other community needs for the roughly 15,000 people living nearby.
Those residents don’t want energy extraction to come at their expense, said José Antonio Ramírez, city manager of the town of Livingston and acting director of Rural Communities Rising, a newly formed collaborative of unincorporated communities. An earlier endeavor, the Darden Clean Energy Project, to be built on land to be purchased from Westlands Water District, has been criticized for having an inadequate community benefits plan.
Febbo said the district is “committed to a community benefit program, so tax revenues and other revenues will be spent on the communities that need it,” but that this work has only just begun.
Ramírez said his group is pressing for the unincorporated communities it represents to have a say in how that plan is shaped. “A lot of people out here are just making ends meet on a day-by-day scenario,” he said. “I don’t think our communities know the opportunities before them — and that these opportunities can go south if they don’t speak for themselves.”
Nearly 10 years after Massachusetts announced plans to buy 1.2 gigawatts of carbon-free hydropower from Canada, the clean electrons are finally set to start flowing into the state.
As soon as this Friday, the New England Clean Energy Connect transmission line could begin commercial operations.
The 145-mile project, extending from the Canadian border to the southern Maine city of Lewiston, will function as something like an enormous extension cord, plugging the New England grid into a supply of electricity generated by energy giant Hydro-Québec. The new supply is expected to save the average residential customer in Massachusetts $18 to $20 per year and move the state closer to its goal of net-zero emissions by 2050.
“This is a significant moment for clean energy in New England,” said Phelps Turner, director of clean grid for the Conservation Law Foundation.
Avangrid, the developer of the transmission line, told Maine utility regulators earlier this month that operations are scheduled to begin on Jan. 16. Work is underway to meet that target.
“Teams are busy on both sides of the U.S.-Canada border,” said Hydro-Québec spokesperson Lynn St-Laurent. “We have been actively testing the equipment for the past several weeks.”
Following a tumultuous year for clean energy projects, the completion of the controversial transmission line is both a rare triumph and a case study in the challenges of balancing decarbonization and the preservation of wild lands. It’s also an uncommon example of transmission getting built in the U.S., where it has proven difficult to construct the massive power lines needed to deliver new electricity supply to population centers.
The project has its roots in a 2016 Massachusetts law that called for the state to procure 1.2 gigawatts of Canadian hydropower, or other renewables, and 1.6 gigawatts of offshore wind energy. The first idea for importing power from the north involved working with a planned 192-mile transmission line through New Hampshire. However, the project was scuttled in 2019 by public outcry against the prospect of chopping a path through some of the state’s treasured forests.
Massachusetts then looked east, to Maine, to find a route for the transmission line. Similar objections quickly arose, with opponents in the state filing a series of legal challenges. In 2021, Maine voters approved a ballot referendum effectively blocking the project. Work froze until August 2023, a few months after a jury unanimously ruled the project could move forward.
The delays spiked the project’s price tag. Before the line could start providing power, the developer, state regulators, and utilities had to come to an agreement about how those costs would be covered. In early 2025, they settled on terms that increased the price utilities would pay by a total of about $521 million, but ensured consumers would still see savings.
“The project faced many challenges over many years, and it survived all of them,” Turner said.
In addition to the modest monthly savings expected for Massachusetts utility customers, the influx of hydropower should keep rates down for consumers throughout New England by pouring lower-cost electricity into the market that will put downward pressure on prices, right at a time when rising energy bills have become a major issue, Turner said.
Questions remain, however, about how much new power the project will actually bring to the New England grid.
Hydro-Québec already sends power into the region on a separate transmission line, though these exports have decreased in recent years, even stopping almost entirely for a period in 2025. It’s possible that meeting its commitment to deliver along the New England Clean Energy Connect line will mean Hydro-Québec chooses to send less power along other pathways, said Dan Dolan, president of regional trade group the New England Power Generators Association. The net increase in clean power may be lower than anticipated.
“The change in flows over the last several years, particularly in 2025, do not leave me optimistic that Canadian hydro is here to save the day,” Dolan said.
I spent much of 2024 writing about the ambitious plans that U.S. steelmakers had to clean up the coal-reliant industry. But by the start of 2025, it was fast becoming clear that those green-steel dreams were in serious trouble.
Under the Biden administration, two big companies had proposed pioneering projects for cleaner steelmaking that were slated to receive $1 billion in federal support and would serve the growing market for lower-carbon metal. The industry seemed poised to begin a new chapter in the storied history of American iron and steel.
The manufacturer SSAB planned to produce iron — the key ingredient in steel — using green hydrogen in Mississippi. Then early last January, I saw the Swedish company had quietly withdrawn from award negotiations with the U.S. Department of Energy following the demise of its would-be hydrogen supplier, Hy Stor Energy. Soon after, President Donald Trump took office for a second time, moving swiftly to rescind grants and dismantle federal programs meant to advance clean energy and curb industrial emissions.
It wasn’t long before Cleveland-Cliffs, the other award recipient, shelved its own initiative for a hydrogen-ready ironmaking plant in Ohio. Today, the company is working with the Trump administration to develop a new scope for the project, one that preserves the use of fossil fuels. And SSAB recently told me that it’s not planning to revive any hydrogen-based projects in the United States.
Green hydrogen, which is made with renewable energy, has long been considered the Holy Grail for decarbonizing heavy industries because it can be used to replace fossil fuels in existing technologies and manufacturing methods. But now the U.S. green hydrogen boom itself has collapsed, taking the steel industry’s ambitions down with it.
At the dawn of 2026, America’s steel producers have no major green hydrogen initiatives slated to start this decade. Supplies of the low-carbon fuel remain scarce and expensive, and there’s no serious, coordinated attempt by the U.S. government to help resolve these stubborn barriers to cleaner steelmaking.
But while it may seem as if the industry has given up on decarbonizing U.S. steel production, the reality is much more nuanced.
Despite the high-profile retreats, manufacturers are still steadily making progress to clean up the country’s nearly 2-century-old industry. Legacy companies are investing in new steel-recycling mills, and startups are building facilities and raising private funding to scale novel technologies. Tech giants are boosting demand for cleaner construction materials as they work to limit the climate impact of the data center boom.
So what should we expect in the year ahead? There is no one clear path forward in the transition to greener steelmaking but rather many winding roads, with some heading toward progress and others looping back to the past. Here are three broad developments I’ll be keeping an eye on.
America’s modern steel era began in the late 19th century, fueled by scorching blast furnaces that use coke — a purified form of coal — to transform iron ore into molten iron, which is then turned into steel. This is still the main way that virgin, or “primary,” steel is made today, and it’s responsible for the bulk of the industry’s carbon emissions and toxic air pollution.
In recent decades, U.S. manufacturers have largely shifted to making “secondary” steel by recycling scrap metal in electric arc furnaces. But a dozen blast furnaces still operate in a handful of states, and their owners say they’re committed to keeping the facilities running well into the future.
U.S. Steel, which is now a subsidiary of Japan’s Nippon Steel, is set to “reline” its largest blast furnace in Gary, Indiana — a major maintenance project that could extend the aging furnace’s operating life by up to 20 years. In late December, U.S. Steel’s board of directors approved $350 million for the undertaking. The company also announced that it will restart operations at an idled blast furnace in southern Illinois to meet rising demand for domestic steel.
Cleveland-Cliffs, which relined one of its blast furnaces in Cleveland in 2022, plans to make similar upgrades at two other mills. The company will reline a blast furnace in Burns Harbor, Indiana, in 2027 and do the same in Middletown, Ohio — the site of its previous hydrogen project — “in the next four to five years,” according to CEO Lourenco Goncalves.
“Reality is back. La-la land is gone,” he said about the change of plans during an earnings call last May.
The manufacturers argue that propping up existing infrastructure is the better choice economically for maintaining and expanding their steelmaking capacity, versus building a new furnace or adopting other technologies. In the long run, however, those coal-fueled furnaces could become big liabilities as automakers, data center developers, and other key customers look to suppliers that offer less-carbon-intensive metal.
“The real challenge, from a technology perspective, is that there’s not really a path for a blast furnace to make the [low-carbon] products that are increasingly being demanded in the market,” said Kaitlyn Ramirez, a senior associate in RMI’s Climate-Aligned Industries Program. “There’s no solution that’s going to be cost-competitive to do that.” She added that the relining decisions represent a “window of opportunity” for steel producers to pivot away from coal instead.
Even as the two steel giants throw a lifeline to a few old dirty furnaces, they and other companies are still making investments to expand lower-carbon production of the ubiquitous, sturdy metal.
Nippon Steel, for its part, recently announced plans to build a $4 billion plant somewhere in the U.S. with two new electric arc furnaces, which typically combine a little bit of iron with a lot of scrap metal. These facilities can curb carbon emissions by 75%, compared to traditional steel mills, because they require using dramatically less coal, a figure that will grow as the nation’s grid increasingly runs on clean energy, according to industry reports.
Its subsidiary U.S. Steel already operates a sprawling steel-recycling operation in Osceola, Arkansas. I visited the Big River Steel site in late 2023, when U.S. Steel was building a second multibillion-dollar plant to make steel specifically for electric vehicle motors, solar panels, and power generators and transformers. Right next door was a field of flattened dirt where Entergy’s 250-megawatt solar farm was soon to be installed.
U.S. Steel finished the construction last year, and the company plans to buy enough clean electricity from the completed solar project to cover 40% of the second plant’s operations. Major steel recyclers like Nucor and Steel Dynamics have also struck deals with clean energy developers in other states to help reduce the emissions associated with running their power-hungry furnaces.
U.S. Steel is also set to construct a “direct reduced iron” facility at the Big River Steel site as it works to lead the industry in “advanced, sustainable steel production,” spokesperson Amanda Malkowski told the Arkansas news site Talk Business & Politics.
Neither Nippon Steel nor its subsidiary has given many specifics about the new ironmaking project. But most DRI facilities operating today use fossil gas to remove oxygen from iron ore, which yields lumps of iron that are fed into electric arc furnaces. This process emits about half as much CO2 as a coal-fired blast furnace. Using green hydrogen can curb overall emissions even further, by up to 90%, experts say.
Based on what’s happened in recent years, I’d be surprised if Nippon Steel plans to source green hydrogen for the project. But another major steelmaker claims to be committed to using the fuel down the road. Hyundai Motor Group says it plans to build a $6 billion steel plant in Louisiana by 2029 that will include a DRI facility and an electric arc furnace. The Korean automaker reportedly intends to start producing green hydrogen at the facility in 2034, though it hasn’t said much publicly about how it will manage such a feat.
Industrial giants aren’t the only ones working to clean up U.S. steelmaking. A handful of well-funded startups are steadily advancing newer ways of making the high-strength metal without using coal.
Last year, Boston Metal said it gotten one step closer to commercializing its “molten oxide electrolysis” technology after it fired up an industrial-size reactor at its facility in Massachusetts. Electra unveiled the site of its first demonstration plant in Colorado, where the company will produce iron with electrochemical devices powered by renewables. And in Texas, the startup Hertha Metals is turning iron ore directly into steel using a high-temperature, single-step process that currently runs on fossil gas but could switch to green hydrogen whenever supplies become commercially available, Hertha’s CEO Laureen Meroueh told me.
These novel efforts are drawing investment from not just global mining giants and metals manufacturers but also companies that use lots of steel — and see the material as a major source of their own supply chain emissions. Meta, for example, has agreed to buy certificates from Electra that will allow the tech company to count the emissions reductions associated with each ton of Electra’s clean iron toward Meta’s climate targets.
“Many of the long-term-focused large companies are looking at sustainability goals that last 10 to 20 years,” said Greg Matlock, the Americas metals and mining tax leader at accounting firm Ernst & Young. “Regardless of what the current political landscape is, I do think there’s absolutely still an appetite [for industrial decarbonization], and it’s a global appetite.”
The European Union is driving much of that global momentum. On Jan. 1, the 27-member bloc began implementing a carbon border tariff, which charges fees on imports of steel, aluminum, and other industrial products made in dirtier facilities abroad. The idea is to level the playing field for European manufacturers that invest in cleaner and potentially costlier facilities, while also encouraging other countries to regulate their own industrial CO2 emissions.
The carbon tariff won’t directly affect U.S. steelmakers all that much, given that they export only a tiny amount of metal to EU-member countries. But the policy’s ripple effects are already transforming the broader industry and putting pressure on all steel producers to modernize and clean up. Countries such as Brazil and Turkey have introduced domestic carbon-pricing policies in response to the EU’s moves. China has started shipping steel made using hydrogen to Italy, which experts say could set the stage for boosting Chinese green-steel exports.
“We’re moving toward a global standard … for lower-carbon steel, so American companies will be well positioned to compete in [global] markets if they continue to decarbonize,” said Angela Anderson, director of industrial innovation for the World Resources Institute. “It’s not likely that those trends are going to just dry up or reverse anytime soon.”
The U.S. has a chance to be at the cutting edge of cleaner steelmaking. Right now, the question seems to be not if we’ll take it, but when — and how far we’ll fall behind the rest of the world in the low-carbon industrial revolution.
Voters worried about rising electricity prices and the onslaught of power-hungry data centers helped Democrats earn a governing trifecta in Virginia last year.
Now, as state lawmakers prepare for a breakneck, 60-day legislative session that begins this Wednesday, clean energy is emerging as a key strategy for dealing with those challenges.
“Oftentimes, I go into a legislative session sort of just guessing what people are going to care about,” said Kendl Kobbervig, advocacy and communications director for the nonprofit Clean Virginia. Not this year, she said. “No. 1 is affordability, and second is data center reform.”
The concerns come as Virginia, the world’s data center capital, is at a crossroads on its quest for 100% clean energy. The commitment began in earnest in 2020, when the state enacted a measure requiring its two investor-owned utilities — Dominion Energy and Appalachian Power Co. — to convert to carbon-free electricity by midcentury. The law also prevents new construction of fossil fuel–burning plants, with some exceptions.
But the landscape has changed dramatically over the last five years, with Dominion now projecting enormous electricity demand from the 663 data centers in the state, and counting. The company has used those predictions to justify building a spate of new gas plants over the next decade, starting with a 944-megawatt complex in Chesterfield County, just southwest of Richmond. Though regulators are taking a second look at the controversial new plant, they’ve mostly blessed the company’s plans. At the same time, Dominion warns that President Donald Trump’s move to halt construction of its Coastal Virginia Offshore Wind Project, with a projected 2.6 gigawatts of capacity, could constrain supply.
These demand pressures are one reason Virginians face rising energy bills.
Dominion, the state’s largest utility, won approval last November for a roughly 9% increase in residential rates over the next two years in a ruling that advocates say didn’t do enough to ensure that data centers pay their fair share of costs. Customers of Appalachian Power, in the southwest corner of the state, have already seen a spike in their bills, driven in substantial part by the escalating price of gas and coal.
Republicans and even some Democrats have said the way to cost-effectively meet ballooning power needs is to back away from the clean energy transition and the 2020 law, the Virginia Clean Economy Act. But multiple Democratic lawmakers are pushing bills this year that do just the opposite in an effort to save consumers money and increase electricity generation.
“The name of the game this session is affordability,” Democrat Del. Phil Hernandez of Norfolk said at a news conference last week.
One proposal to lower costs, offered by Hernandez and Sen. Schuyler VanValkenburg of Henrico, is dubbed the Facilitating Access to Surplus Transmission, or FAST, Act.
The bill is made possible by a new rule at PJM Interconnection, the multistate entity that manages Virginia’s grid: Facing lengthy backlogs for new grid hookups, PJM said last year it could connect some sources on an expedited basis so long as they didn’t trigger meaningful upgrades to the transmission grid.
“There are miles and miles of our current transmission infrastructure that are not being used at nearly their full capacity,” said Jim Purekal, a director at Advanced Energy United who heads the organization’s legislative work in Virginia. “A traditional peaker plant only operates at various points around the year. The rest of the time, it’s essentially dormant.”
The FAST Act, Hernandez said, “will lay out a process to help get these new energy projects up and running.”
The PJM surplus interconnection rule is a permission structure, not a mandate. And utilities may be tempted to use the regulation to build expensive new fossil fuel plants. The bill would set up a study of how much headroom is on the grid and create a procedure to allow only the most cost-effective resources to utilize it.
“Let’s make sure that if you’re going to be using this capacity,” Purekal said, “you’re using the most affordable assets on the commercial market today: solar, onshore wind, and battery storage.”
Advanced Energy United expects 2 to 3 gigawatts of such resources could be colocated with existing power plants of all types within four years. That’s about two times faster than it has taken a project to get through PJM’s queue in recent years.
“We believe this could be one of the fastest, lowest-cost ways to add power to the grid,” Hernandez said.
A complementary effort, to be introduced by Sen. Lamont Bagby of Richmond and Del. Rip Sullivan of Fairfax, would increase grid battery targets in the 2020 law and help ensure energy storage projects are cost-effective for ratepayers.
With Hernandez, the lawmakers promoted it at last week’s press event behind a podium sign that read, “Energy Storage Keeps Electricity Affordable.” One reason that’s true, Sullivan noted at the conference, is that batteries can charge when electricity prices are low and supply is abundant — as on a mild, sunny afternoon — and discharge when demand is high and hourly prices go up. “We can store energy when it’s cheap,” he said, adding that “this is the best energy storage bill in the country.”
The storage and surplus interconnection bills aren’t the only pieces of legislation on Democrats’ affordability agenda.
Indeed, incoming Del. Lily Franklin of southwest Virginia is among those seeking to bring costs down for customers of Appalachian Power, in part by reining in transmission and fuel charges that typically get less scrutiny in rate cases.
Likewise, Sullivan and Sen. Scott Surovell of Fairfax will proffer legislation to lay the groundwork for a ratemaking scheme that would align utilities’ profits with their performance on clean energy, efficiency, and affordability. Among others, the measure was recommended last month by the influential Commission on Electric Utility Regulation, which Surovell chairs.
The stamp of approval may help the measure’s chances in the legislature this year, as should its lead patron. “Sen. Surovell is the Senate majority leader,” Kobbervig said. “So when he says yes to things, you think, ‘OK, this has legs!’”
The other thorny problem at the top of lawmakers’ energy agenda is the explosive growth of data centers in the state. According to Dominion, the facilities could account for an eyepopping 51% of its electricity sales by 2035, though such figures are notoriously slippery.
“There’s a lot of uncertainty in this market. There’s a lot of speculative load,” said Nate Benforado, senior attorney at the Southern Environmental Law Center. “At the same time, that is an astounding number.”
Environmental advocates’ plan to confront the challenges posed by data centers includes sticks such as increasing transparency on utility projections and ensuring that residential customers aren’t unfairly burdened with increased costs. But Sullivan and Sen. Creigh Deeds of Charlottesville also want to reform a sizable carrot: the generous tax incentives that lured Amazon, Google, and their ilk to the state in the first place.
“It’s by far Virginia’s largest tax break, and it’s going to some very large companies,” Benforado said. That’s part of why its conditions should include investments in renewables and efficiency.
“We want to only give a tax incentive to data centers that are accelerating the clean energy transition — and certainly not hurting that transition.”
Several of the measures Democrats plan in 2026 cleared the General Assembly last year, only to be vetoed by outgoing Gov. Glenn Youngkin, a Republican.
But on Jan. 17, Youngkin will be replaced by Gov.-elect Abigail Spanberger, a Democrat who campaigned on affordability and data center growth, and has already championed the bill to increase the state’s battery storage targets, among other measures.
“I recognize the complexity of our current challenges and threats posed by the future demands, but the answer is not to sit so our problems only get worse,” Spanberger said at a news conference last month about her energy agenda, according to the Virginia Mercury.
Still, Republicans have sought for years to weaken or repeal the 2020 Clean Economy Act, and the onslaught of data centers, community concern over large-scale solar farms, and the Trump administration’s anti-renewables stance are breathing new life into their arguments.
At the same time, powerful Democrats, including Surovell and House of Delegates Speaker Don Scott of Portsmouth, haven’t ruled out relaxing the law’s prohibitions on new gas plants, according to Inside Climate News. Dominion has asserted that such plants are needed to keep the lights on in the face of new demand.
Clean energy advocates plan to forcefully rebut those claims in the General Assembly and the public square.
“It is incumbent on us to be pushing back on the concepts that gas is clean, that gas is affordable, that it’s the only way to have a reliable grid,” said Benforado. “They are simply not true.”
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