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BYTOM, Poland — Adam Drobniak pulled into the parking lot of a convenience store and stepped out of his sedan into the overcast afternoon. A coal mine just across the street cast dust into the air as conveyor belts sorted the shards of black, burnable rock. Down the road, a goliath coking plant belched fire and thick clouds of steam as its roaring ovens cooked off impurities in the coal to refine it for blast furnaces. The air smelled burnt, and it was difficult to tell whether the sky was gray from clouds or smoke. Drobniak took out a silver case from his pocket and flashed a mischievous smile as he withdrew a hand-rolled cigarette, then dangled it from his lips and touched the flame of an old-fashioned Zippo to the tip.
“I spent decades around this,” he said, motioning to the surrounding area. “How much more damage can it do?”
Bytom is located in Silesia, an ethnically distinct province in southern Poland and the European Union’s biggest coal-mining region. Silesia still produces millions of tons of coal annually and has been extracting it from the ground for hundreds of years. The first state-owned coal mine opened about 20 minutes southwest of Bytom in 1791, when the region was controlled by Prussia. Over the next two centuries, the area was transformed into a key node in Central Europe’s industrial supply chain, with the third-largest gross domestic product of any province in the region, behind only the Polish capital of Warsaw and the Romanian capital of Bucharest. Coal became a way of life.
Now Silesia is figuring out the least painful way to kill the coal industry.
An economist by training, Drobniak has become something of a doctor administering palliative care.
Over the past five years, Drobniak, who works at Poland’s University of Economics in Katowice, Silesia’s provincial capital, has partnered with labor unions, local officials, and industry leaders on a “just transition” plan to shift Silesia away from coal without abruptly destroying the livelihoods of thousands of people whose families have worked in the industry for generations, spanning kingdoms, republics, communism, and capitalism.
That plan, which seeks to capitalize on an economic transition already underway in Poland and give workers the time and resources to adjust, has become something of a model for neighboring countries such as Romania and Bulgaria, which are struggling with their own transition away from coal. And, though the plan faces pushback from EU policymakers in Brussels and shifting priorities in Warsaw as different parties vie for national power, Poland seems to be moving in the right direction. Across the province, new industries — from manufacturing to technology — are booming.
However, development has not been evenly distributed. The economic gap between cities such as Bytom and Katowice has more than doubled in the past three decades. While Katowice teems with new buildings and businesses, Bytom represents what Drobniak called the “worst case” for the transition, a corner of Silesia unusually entrenched in coal and suffering from high poverty and unemployment rates as the industry shrinks. The city has lost nearly a quarter of its population since the early 2000s, with residents leaving in pursuit of better opportunities elsewhere. Indeed, the coal mine that was cranking away when Drobniak and I visited Bytom this fall was set to close in December. Most of the miners there will likely transfer to other coal mines in Silesia.
As in many parts of Europe, wind turbines line the horizon on the drive into Silesia. Solar panels glimmer on old stone roofs. Poland is racing to build its first nuclear power plant and is inking deals with virtually every major small-modular-reactor vendor in the U.S. and the United Kingdom. The country is even carrying out drilling experiments to see whether geothermal heat could replace coal in its district heating system. It’s no wonder why: Poland’s coal phaseout is set to kick up a notch this year, even as electricity demand is rising. But the size, history, and Europe-wide importance of Silesia’s coal industry put the phaseout on a different scale — making the steps the region is taking to avoid upheaval for workers especially consequential.
The Silesian coal industry’s first brush with death came three decades ago.
In 1996, Poland enacted sector-wide reforms meant to consolidate mines and privatize state-owned enterprises as the country transformed after the fall of the Soviet Union. Over the course of just a few years, the number of jobs in the mining sector plunged by 356,000. After Poland joined the EU in 2004, its economy grew rapidly and employment in the coal sector partially recovered. But it dipped again, by tens of thousands of jobs, during the 2008 financial crisis and the 2020 pandemic.
Poland’s overall wealth expanded as the country integrated into the EU. But the relationship also brought tensions. As Brussels imposed increasingly strict targets to cut emissions from power plants and phase out coal, many countries built up renewables backed by natural-gas-fired plants. Pipelines stretching westward across Europe from the bloc’s eastern border soon flowed with gas molecules from Russia, one of the world’s biggest producers.
Poland was reluctant to follow suit. Centuries of fighting off invasions from the east — including four decades under Moscow’s control as a Soviet satellite — left Poles wary of depending on Russia for fuel. When Russia invaded Ukraine in 2022 and started throttling Europe’s gas supply, Warsaw’s continued reliance on coal seemed, to some extent, vindicated. However, even as the conflict underscored the risks of Russian gas, surging electricity demand across the EU and looming emissions-cutting deadlines only emphasized the need for Poland to find new sources of power.
To Silesia’s coal miners, the end is looking inevitable.
“We are fighting for our lives here,” Krzysztof Stanisławski, a lifelong miner, told me when I visited the headquarters of the Kadra trade union, which represents many of the region’s coal workers. “It’s a big problem. We are fighting, and we are losing.”
But there are degrees of losing. In July, Drobniak and members of the Kadra union had visited the British city of Newcastle as part of a tour of the U.K.’s former coal-producing regions. The location was fitting. The city in northeastern England was once a coal-mining capital whose product fueled the first phase of the Industrial Revolution. But in the early 1980s, then–British Prime Minister Margaret Thatcher incapacitated the coal unions as part of the Conservative Party’s crackdown on organized labor, and the steady push toward cleaner sources of power shrank the industry. The final coal mine near Newcastle closed in 2005.
“We visited Newcastle to learn about what we should avoid in the future,” Drobniak said. “There were very poor provisions to support the people there. We saw it physically. The Newcastle area just seemed very degraded.”
Hoping that Poland could avoid a similar fate, Drobniak had already helped broker a deal with the national and provincial governments to phase out coal in waves. The talks started in early 2020, when government regulators invited a group of economists to prepare a report on what a just transition away from coal could look like. The economists came out with recommendations in May of that year and promptly began work on a national strategy in June, all while drafting regional plans for provinces such as Silesia.
To start, the agreement promised benefits to keep coal workers solvent. Under the plan, which took effect in 2021, workers can access free training to transition to other lines of work while continuing to receive some compensation from their mining jobs.
Workers who opt to quit the mining industry for good are entitled to a one-time severance payout of 170,000 Polish zloty ($47,000). Miners who are within four years of retirement and leave early can count on a salary equivalent to 80% of their typical annual earnings.
The deal that Drobniak helped broker set a deadline of 2049 for Poland’s final coal operations to shut down, years later than in many other EU nations. Not everyone supported the idea. Poland’s reliance on coal has rendered its air some of the dirtiest in Europe, shaving an average of nine months off its citizens’ lives. Its per capita greenhouse gas emissions are the fifth-highest in the EU, and Brussels has continued to pressure Poland to speed up its transition. Meanwhile, Warsaw is bristling at spending more money to keep the coal sector’s operations going for another 23 years.
Over coffee and cookies at Kadra’s modest offices on the outskirts of Katowice, in the shadow of idle smokestacks from now-defunct coal-fired plants, Grzegorz Trefon, the union’s head of international affairs, recalled a famous speech Nikita Khrushchev gave at the Polish Embassy in 1956, in which the Soviet leader vowed to defeat the capitalist forces of the world through patient confidence that “history is on our side.”
“That’s what we want,” Trefon said. “We want to win by time.”
The reference to a reviled Russian ruler drew chuckles among his compatriots in the room. Dariusz Stankiewicz, the regional government’s lead specialist on the transition from coal, stepped in to clarify what Trefon meant.
“This shows that when we are facing this in a very slow manner, our economy can transform itself and produce new workplaces,” he said.
Between 2005 and 2022, Silesia lost 55,000 jobs in the mining sector, according to government data. But the region added 160,000 jobs in other sectors during that same 17-year time period.
“If we slow down the process, the economy can cope with this problem and produce new jobs,” Stankiewicz said. “This is why I support this very slow phasing-out process.”
In Bytom, poverty is entwined with pollution. Men looking older than their years, with sinewy muscles and tattoo-covered torsos, arrive shirtless at the grocer to buy cases of beer or vodka after finishing midday shifts at the mine. Across the street from the coking plant, women visibly solicit customers for sex from the stoops of Soviet-era apartment blocks. Drobniak warned me to be ready to run if anyone seemed to be eyeing my camera.
A roughly half-hour drive east, on the northeast side of Katowice, is a neighborhood with similar-looking buildings but a dramatically different vibe. The cobblestone streets and old brick buildings of the Nikiszowiec Historic Mining District hark back to an earlier era when this part of the region was powdered with coal dust and ash from active mines and industrial sites.
Today, however, the district is spotless and filled with local tourists who come to see hockey games at its indoor rink, eat at upscale restaurants, and shop at its art galleries. A facility that once contained a major coal mine now serves as a hub for video game developers.
“This was not a place that people wanted to come to,” Drobniak said. “Now it’s hard to get a table at the restaurants here on a Friday night.”
Both Warsaw and Brussels have contributed to Katowice’s advancement over the past 20 years, as has celebrity academic Philip Zimbardo, the American social psychologist best known for the Stanford Prison Experiment, whose international work eventually led him to set up a nonprofit called the Heroic Imagination Project in the historic district in 2014. That organization worked to create employment opportunities for young people, and as conditions improved, the EU gave the city a grant of 200 million euros ($235 million) to help revamp industrial buildings for modern uses.
The starkest transformation, however, may be in the city center, where the newer industries that Silesia has attracted have flocked. While mining once accounted for more than half of the province’s gross domestic product, it now makes up a third, as factories producing automobiles, machinery, and electronics have popped up. Gleaming new office towers brandishing the logos of multinational consultancies rise between older brick buildings. Modern luxury condos with architecture one might expect in Miami or Tel Aviv but not Central Europe take up entire blocks of an otherwise quaint city. A grass-covered park swoops down to a vast, futuristic stadium built in the Soviet times. Once an area where coal was gouged from the ground, it is now a gathering space for entertainment and corporate events — part of why Katowice was recognized last year as Poland’s best city to live in.
But Katowice remains small compared with larger cities such as Warsaw and Krakow. To Drobniak, the future of Silesia should look something like Seoul or Tokyo.
A few years ago, researchers proposed the concept of the Metropolis GZM, short for Górnośląsko-Zagłębiowska Metropolia. Rather than a piecemeal approach to developing new industries in the patchwork of former coal-mining hubs that dot central Silesia, Metropolis GZM would unite the urban areas into one, interconnected with railways, bike paths, and corridors of tall buildings.
“In the entire surrounding area, we have about 2.5 million people,” Drobniak said. “We would be the biggest city in Poland.”
Merging would help solve one of the trickier elements of the transition. Bringing the entire region under one municipal planning organization would, in theory, help find ways to bridge the divide between thriving cities like Katowice and declining hinterlands like Bytom.
“People are afraid that they’ll lose their identities because they are connected by generations not with Katowice but with other cities like Bytom,” Drobniak said. “We’d like to put the discussion on a different level and say, ‘There is no Katowice. It will be something new.’ We don’t know what will be the name of this urban structure. But this is a must. We must do this. If not, we will be fragmented and separated, and the metro areas of Krakow and Wroclaw will attract young people from us.”
The critical thing, Drobniak said, is to revive the economy rather than push residents to leave, keeping the youths and workers who draw new industries and stemming the decline of Bytom and other cities.
In former American coal-mining hubs in Appalachia, such as West Virginia, generations of families remain entrenched despite the downward trajectory of the industry and the dangers of a polluted environment. But those roots are shallow compared with Poland’s, said Trefon. Miners in Silesia can trace their families in local history nearly twice as far back as 1777, when the U.S. was founded.
“My family lives here. There are churches with my relatives’ names going back 400 years,” he said. “That’s why we have so much connection to this land. It’s not possible to find another place to remake the mining industry. But we need to find a sustainable way for the development of new economic activity that will stay here.”
It might seem like a dicey time for building decarbonization in the U.S., where edifices and the energy they consume account for about a third of the nation’s annual carbon pollution.
Republicans in Congress have cancelled tax credits that would have helped households save big on clean energy upgrades. The Trump administration is dismantling federal building-decarbonization policies and trying to block states and cities from setting rules that restrict fossil fuel use in homes and businesses. Even some Democrats who once championed such mandates U-turned last year: Los Angeles’ mayor repealed an ordinance that most new construction go all-electric, and New York’s governor delayed a similar statewide law previously slated to go into effect last week.
These are very real headwinds, but they’re not the whole story. Several key barometers suggest that building decarbonization is poised to pick up speed as consumers grow more worried about energy affordability, installers get familiar with electric tech, and policymakers and building owners alike recognize the health, comfort, and financial benefits of ditching fossil fuels.
Let’s dive into seven indicators — and a few bonus figures — that show why the momentum behind climate-friendly buildings may be unstoppable.
According to the Bureau of Labor Statistics, the consumer price index for piped gas ballooned more than twice as fast as that for electricity, and nearly four times as fast as overall inflation for all tracked items. That makes utility gas one of the leading causes of inflation, which could give customers pause on whether to depend on the fuel in the future.
The price surge is partly thanks to the fact that the U.S. has been increasing its exports of liquefied natural gas, squeezing the domestic fuel supply and driving up costs at home, said Panama Bartholomy, executive director of the nonprofit Building Decarbonization Coalition.
Gas customers are also shouldering growing infrastructure costs. Utilities have massively ramped up gas-system spending since the 2010s — a result of increased safety investments in response to some high-profile explosions that decade, as well as a sense of urgency stoked by state climate laws, Bartholomy said.
“Many [utilities] view this as a race against time,” he noted in a December interview. “We now have 15 states since 2020 that have started future-of-gas proceedings, where they’re actually [taking] a regulatory approach to how they’re going to wind down the gas system in their state.”
In utility territories across 46 states and Washington, D.C., existing gas customers cover the cost of hooking up new customers to the system. The fees add up to $2 billion to $7 billion each year, according to an August 2025 analysis by the Building Decarbonization Coalition.
Policymakers and utilities in six states have reformed these “line extension allowances” to stop incentivizing growth of the gas system as well as to lower customer bills. Of the six, California, Colorado, and New York have eliminated the subsidies statewide. Another six states and D.C. are considering ending them.
Putting an end to gas-hookup subsidies is a fast-acting affordability measure, Bartholomy said. “States [that] stop subsidies in 2026 … are going to save people money in 2027.”
The majority of homes — both single- and multifamily abodes — are now built with electric heating, according to the U.S. Census Bureau. That’s a big change over the last decade for single-family homes especially; in 2015, 60% were equipped with gas or propane heating, and just 39% were heated electrically.
Among multifamily buildings, electrically heated units accounted for 63% of new construction in 2015. In 2024, the share rose to 76%.
The agency doesn’t break down how many newly built homes have super-efficient heat pumps. But the next stat shows that the appliances are increasingly popular.
Heat pumps beat out gas furnaces (3.1 million shipped in 2024) by their biggest margin ever, 32%, that year, according to data from the industry trade group Air-Conditioning, Heating, and Refrigeration Institute. The numbers for 2025 through October, the latest available, show heat pumps in the lead yet again.
These appliances, which provide both heating and cooling, are also steadily gobbling up the market share of conventional air conditioners. In 2015, ACs outsold heat pumps by two-to-one. By 2024, the gap had shrunk to 35%, with ACs still pulling ahead.
Bartholomy of the Building Decarbonization Coalition predicts that margin could shrink to just 20% in 2026.
Lawmakers in 13 states have approved bills that encourage gas utilities to reinvent themselves as utilities that provide carbon-free thermal energy instead of fossil gas. Some of these laws require gas companies to pilot thermal energy networks, which can decarbonize entire neighborhoods at once by replacing gas pipeline systems. Others unlock financing or establish regulatory frameworks that allow utilities to recover costs for these projects from customers.
Thermal energy networks that make use of geothermal heat, found tens to hundreds of feet deep, are also the rare climate solution that the federal government is incentivizing. Geothermal networks are eligible for a tax credit of 30% to 50% until 2033. The appliances that harvest underground heat and store it for later — geothermal heat pumps and thermal batteries — qualify for the tax credit, too, as long as eligible commercial customers lease instead of purchase these products.
“In many states, we’re seeing this lease [structure] as a real tipping point, where geothermal becomes less expensive than the status quo for the builders,” Dan Yates, CEO of geothermal heat-pump startup Dandelion Energy, told Canary Media last year.
That’s according to a survey released in January 2025 by the ACHR News. The same survey revealed that 71% of heating, ventilation, and air conditioning installers expect heat pumps to make up a larger fraction of projects in the next three years. Just 61% thought so the year before.
Contractors may be responding to warming consumer sentiment. About nine out of 10 heat-pump owners would recommend the tech to others, and a growing number of homeowners (32% in 2024 versus 23% in 2023) report having a good understanding of what these systems are, per a survey published in February 2025 by manufacturer Mitsubishi Electric Trane.
Innovation in some contractor businesses could also help the tech gain traction. One vertically integrated startup, Jetson, says it’s cutting the cost of heat-pump installations in half.
That nugget comes from the National Kitchen & Bath Association’s 2025 Kitchen Trends Report, according to a September Forbes story.
“I’m a big fan of induction,” Amy Chernoff, vice president of marketing at national retailer AJ Madison, told Forbes. Compared with gas cooking, an induction stove “keeps your kitchen cooler, it’s easier to clean, better for the environment, and much safer for households with children.”
The above numbers reveal how the markets for efficient, electric equipment — nudged along by policy — are steadily transforming. Let’s see if consumers, contractors, developers, advocates, and policymakers can keep up the building-decarbonization momentum in 2026.
Last year, I made a habit of checking the live feed of a particularly pitiful webcam.
The view showed a muddy gravel lot bisected by a chain-link fence in the coastal marshes of southern New Jersey. No person or vehicle ever entered the frame, though I half expected the site to be bustling with activity as the state transformed it into a billion-dollar port for offshore wind.
Only once when I checked this live feed did I see something different. On a summer evening, I logged on and the camera panned to another angle, which showed an adjacent site where some construction work on the New Jersey Wind Port had started and then stopped. A view of the vast Delaware Bay loomed in the background. I watched the sun set over the half-built, now-abandoned port.
Some metaphors write themselves.
The Garden State megaproject, championed by former Democratic Gov. Phil Murphy, is just one offshore wind project among many that were disrupted by the Trump administration last year. Throughout 2025, the federal government clawed back federal funds, sunsetted wind tax credits, and froze permitting for wind farms. It ended the year with a bang: About two weeks ago, the administration issued a sweeping stop-work order to all five offshore wind farms under construction in the U.S.
The fall of New Jersey’s offshore wind port mirrors the fate of planned wind farms, ports, and manufacturing sites that many states, particularly in the Northeast, had spent decades building up.
Still, multiple experts told Canary Media it was inaccurate to call the industry “dead.” At least one described the state of affairs as a hibernation — and as a key time for “learning” before the next wave of activity.
According to some analysts, it’s not easy to see when — or if — that next wave of offshore-wind activity will come.
When Donald Trump was elected last November, BloombergNEF expected the U.S. to build 39 gigawatts of offshore wind by 2035. BNEF’s latest forecast, released in October, expected just 6 gigawatts to be built by 2035 — an amount equivalent to the capacity of those five wind farms that were under construction and America’s only fully completed project, New York’s South Fork.
Even that may be optimistic if Trump’s late-December stop-work order results in cancellations.
In other words, according to BNEF, it’s possible that no new wind farms will break ground in the U.S. for the next decade. Even with a recent court ruling deeming Trump’s permitting freeze “unlawful,” developers would struggle to finance projects that aren’t already underway, analysts say. It’s also hard to imagine why an offshore wind developer would bother trying to get a new project off the ground while Trump is in office, given the level of turmoil and explicit ire.
“We think the risks are inherent to the Trump administration,” said Harrison Sholler, an offshore wind analyst for BNEF.
The sector also faces cost pressures both related and unrelated to Trump.
Even before 2025, pandemic-related supply chain issues, rising interest rates, and inflation had all made it more expensive to build offshore wind in America, Sholler said. In fact, those pre-Trump macroeconomic conditions caused a few projects to collapse during the Biden administration.
But the cost issue has gotten worse, not better, since Trump was sworn in last January.
Take New Jersey’s wind port, for example: The $637 million state-backed project broke ground in 2021 and was supposed to be a staging area for two wind farms planned for the Garden State’s coastline — Atlantic Shores and Ocean Wind. Days after Trump took office, Atlantic Shores began imploding when co-developer Shell pulled out and the New Jersey Board of Public Utilities declined to grant the projects a power purchase agreement. Both Shell and the utility board cited “uncertainty” over federal actions. And in late 2023, developer Ørsted pulled the plug on Ocean Wind and its port commitments because of rising costs. The port’s fate is uncertain, and its webcam appears frozen.
Overall, “offshore wind has gotten one-third more expensive based on our modeling, and that doesn’t include the effects of tariffs,” said Sholler, who explained that the cost increases in BNEF’s latest calculations were driven by Trump’s July move to phase out federal tax credits much earlier than the date previously set by the Biden administration.
Offshore wind, as a sector, has had bad timing in the United States.
The Biden administration started issuing full project approvals about a year into the Covid-19 pandemic, which had scrambled supply chains and sent interest rates soaring. Amid these economic hurdles, the U.S. charged forward with offshore wind anyway.
Elizabeth Klein, former director of the Bureau of Ocean Energy Management, defended the pace at which the federal government permitted new offshore wind farm projects, even as financial conditions worsened.
“It was incredibly important to get as many projects permitted as possible so we can build some proofs of concept,” Klein said.
But that might have been a mistake, according to Elizabeth Wilson, a wind energy expert and professor of environmental studies at Dartmouth College, who said state and federal leaders should have slowed down wind development during that time instead of leaning in.
“We were building a whole new sector … Building it as rapidly as we had hoped to do was even more ambitious,” Wilson said.
America’s offshore wind industry, Wilson said brightly, is now in a “learning phase.” And considerable learning, she argues, has already happened: State governments are currently more equipped to grow and manage offshore wind power than they were five years ago.
Wilson and three colleagues published a study this month demonstrating that U.S. states, even prior to Trump 2.0, were already “drawing lessons” from the challenges they encountered while trying to launch the nation’s first offshore wind farms.
In New York, for example, state regulators adapted the way they price power purchase agreements to better account for rising costs. In New Jersey, an early oversight in transmission planning led to new requirements for offshore wind developers to show how they would better coordinate transmission across the regional power grid. And throughout the Northeast, state governors — working with federal regulators — identified better processes for compensating fishermen for lost revenue due to wind farm construction.
It’s unclear what learnings will arise from Trump 2.0, but Wilson offered a few preliminary suggestions.
First, regulatory stability is paramount, especially given the industry’s long and cumbersome permitting pipeline. Trump demonstrated how much damage can be caused by a shift in the political winds.
Though it’s impossible to guarantee political stability, Wilson suggested that state and federal regulators could, under a more hospitable future administration, revise the permitting system to at least make it faster and smoother.
After all, European energy developers, who are leaders in offshore wind, were surprised by the fragmented permitting and uncoordinated regulatory landscape they encountered in America, according to Wilson.
This kind of change might address the friction that occurs for projects trying to get approved by multiple governments, which has indeed eroded investor confidence in recent years, according to BNEF’s Sholler.
Klein agreed that coordination between states, counties, and federal agencies could improve, but she also pointed out that the current way of doing things did get results.
“Our permitting process is not broken … We got 11 projects approved,” she said, referencing her time leading the federal branch that regulates offshore wind farms during the Biden administration.
Wilson argues that another “site for learning” would be the Coastal Virginia Offshore Wind project, which, based on its history of strong bipartisan support, could be a “model of success.”
Klein agreed, calling CVOW, “a little bit of a unicorn.”
The project, located nearly 30 miles off the coast of Virginia Beach, Virginia, has the distinction of being America’s largest offshore wind farm and the only one that is getting built by a regulated utility. The project was slated to feed the grid starting this March — and, prior to last month’s federal pause, was progressing on schedule.
Dominion Energy, the utility building the project, operates under a “vertically integrated model,” said Wilson, giving it a long-term stability that is beneficial to slow-moving offshore wind development.
Virginia is also the world’s data-center capital, with tremendous energy demand that offshore wind is especially good at serving, especially in extreme winter conditions. Thanks to CVOW’s careful site placement and community engagement, opposition from fishermen and local groups has been relatively low, according to Captain Bob Crisher, a Virginia-based commercial fisherman.
Still, the project was ultimately not spared the major political obstacle of a Trump administration stop-work order.
Perhaps the biggest lesson, for Wilson at least, is that hyping the offshore wind industry did little good. The target dates and costs estimated were possibly “overhyped,” she said, leading lawmakers and others who turned a blind eye to the reality of offshore wind farms being, ultimately, megaprojects.
Offshore wind is a megaproject sector, and “megaproject dynamics” are well studied in Europe, said Wilson. These social and political processes are predictable, in that costs always go over, timelines typically run long, and environmental impacts are often not well communicated. Over the years, these inevitable outcomes gave influential offshore wind opponents and GOP lawmakers fodder for pushing back on offshore wind.
“This is a useful framework: Megaprojects are hard,” she said.
An enormous and novel energy storage project could soon break ground in California after receiving state approvals just before Christmas.
The startup Hydrostor’s Willow Rock project would store 500 megawatts of power that could be injected into the grid for up to eight hours, totaling 4 gigawatt-hours. That’s more gigawatt-hours than any lithium-ion battery offers, and a rare step forward for a major long-duration energy storage project. Once online, it could prove a crucial tool for California, where intermittent solar generation has become the state’s top source of electricity.
Hydrostor received permission to start building from the California Energy Commission, which signs off on environmental approvals for large thermal power plants. This has become a rarity in an era when the state pretty much exclusively builds solar and battery plants. Hydrostor, however, compresses air in underground caverns and then releases it to turn conventional turbines and send power back to the grid. Its roster of equipment put the project under the commission’s jurisdiction.
“These are the major approvals. It basically allows us to get to a shovel-ready status,” Jon Norman, president of Hydrostor, told Canary Media.
That means Hydrostor can technically begin construction on the 88.6-acre parcel it controls, where rural Kern County hits the Mojave Desert.
But Hydrostor won’t actually start building until it secures paying customers for the full planned capacity. So far, Central Coast Community Energy has contracted for 200 megawatts of Willow Rock’s capacity. Hydrostor is negotiating contracts for another 50 to 100 megawatts, which leaves 200 to 250 megawatts up for grabs.
That uncontracted capacity stands in the way of Hydrostor securing the financing it needs to pay for the roughly $1.5 billion project. Lenders or investors want assurances that the innovative installation will make enough money to pay them back, with a return. Otherwise, the project is exposed to merchant risk: Maybe Hydrostor could build it anyway, bid into the wholesale markets, and make good money. But that’s too risky a bet for most financiers, who want to see firm customer commitments.
Two factors further complicate the pitch to financiers. Because Hydrostor is trying to build a fundamentally new type of storage plant, there isn’t a clear market comparison to benchmark against. And it’s also competing in a fundamentally new type of market niche: long-duration storage.
Many analysts have predicted the physical need for longer-term grid storage as more and more of a region’s electricity comes from wind and solar power. Few regions have developed workable market structures to get ahead of that need, since today’s power markets focus on short-term optimization rather than long-term infrastructure planning.
California, though, has supplemented its power markets with a centrally driven push for long-duration storage. The state’s utility regulator required power providers to procure a collective 1 gigawatt of storage that lasts for eight or more hours. That order prompted Central Coast Community Energy to sign the deal with Hydrostor.
In September, the California Public Utilities Commission recommended a portfolio including 10 gigawatts of eight-hour storage for 2031, as part of the state’s planning for its transition to 100% clean electricity. That means a procurement order could come soon, and Hydrostor, with its permits in order, would be in position to compete for that.
“They’ve identified the need for very near-term procurement, so we’re looking forward to participating in that,” Norman said. “We also know that we’re very competitive.”
He also said it’s “very likely” that Hydrostor breaks ground this year.
That would kick off an estimated four-to-five-year construction timeline, Norman said. The company has created a “pretty sophisticated Joshua tree management plan” to protect the alien-looking vegetation unique to the Mojave, where it will build the project. It also secured a water supply and place to deposit the rock it carves from the earth, and it is currently finalizing an engineering, procurement, and construction contractor, Norman said.
That timeline should put Willow Rock in a good place to help California meet those medium-term storage needs. Given current trends, in five or so years the state will be even more awash in surplus solar generation at midday, and in even greater need of on-demand energy to keep the lights on after the sun sets.
In other words, if the regulator’s numbers are right, California will need many more Willow Rocks to keep up, so it’s about time one of them got going.
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy and the environment. Sign up for their newsletter here.
U.S. energy markets and policy are heading toward the equivalent of a multicar pileup in 2026.
The key factors are consumer frustration with rising energy prices, Trump administration policies that are making the problem worse despite promises to make it better and a growing awareness that investment in AI data centers is part of a bubble that could pop at any time.
I asked seven experts for their outlook on what we’ll be talking about in 2026 and almost all of them touched on this set of intertwined problems. Call it a crisis or a disaster. Or just call it terrible politics for the party in power ahead of November’s midterm elections.
Robbie Orvis, senior director for modeling at the think tank Energy Innovation, said he expects energy affordability to be the major issue of the year. He pointed to the rising wholesale price of natural gas and how that is likely to translate into higher utility bills, since gas is the country’s leading fuel for power plants and home heating.
“I don’t anticipate that people’s home energy bills are going to go down anytime soon,” he said.
The country’s benchmark price of natural gas has risen from an average of $2.19 per billion BTUs in 2024 to forecasts of $3.19 in 2025 (full-year figures for 2025 are not yet available) and $4.01 in 2026, according to the Energy Information Administration’s short-term outlook.
Gas prices are rising for many reasons, including an increase in exports of liquified natural gas, mainly to Europe, and growing demand from U.S. gas-fired power plants.
Orvis also highlighted the Trump administration’s policy of requiring old coal plants to remain online, even when their owners would otherwise have closed them for economic reasons. The administration has done this several times, citing the need to maintain the grid’s reliability during periods of high demand.
The result is that utilities are forced to operate plants they wanted to close, which are dirtier and more expensive than readily available alternatives.
Meanwhile, the least-expensive option for new power plants in most of the world is utility-scale solar. Even if we include the cost of batteries to allow solar to be stored for nighttime use, solar is a low-cost leader, as shown by research that includes a report last month from energy think tank Ember.
The federal government could respond to rising prices by rapidly building new power plants. But the country’s permitting system, supply chains and recent policy decisions are harming the ability to provide relief.
Some of these problems predate the Trump administration. But President Donald Trump has made things worse with executive orders that add restrictions on the development of wind and solar power, including a stop-work order in December that halted construction on five offshore wind projects.
Michael Webber, a professor of engineering and public affairs who studies energy at the University of Texas at Austin, puts this problem in the form of a question:
“Do we return to normal for permitting energy projects or will every project have to price in the risk that the president might impulsively cancel it?” he asked in an email.
He said this risk is a cost driver for developers that will be enough to stop some marginal projects and drive up rates for consumers.
Our crystal balls are not super precise on some topics. For example, several people said the investment in AI data centers and forecasts of rising electricity demand to power them are part of an investment bubble. But it’s unclear if this market will face its reckoning in 2026 or later.
The larger problem is that AI companies are spending tens of billions of dollars to build gigantic, energy-sucking data centers, often without clear plans for how these projects are going to make money.
“There’s a bubble, and what’s going to end up happening is there’s going to be a consolidation,” said Stephen A. Smith, executive director of the Southern Alliance for Clean Energy, an advocacy group based in Knoxville, Tenn.
In a consolidation, the companies with the weakest business plans will go bust and the companies with viable plans and ample cash reserves will pick over the wreckage.
One of the main questions, Smith said, is how much consumers will need to cover the costs of unwise investments to power data centers.
The worst-case scenario would be if utilities make substantial investments to meet data center demand and the demand doesn’t fully materialize, leaving the costs to be paid by households and other consumers.
Some states, including Indiana and Ohio, have adopted rules to try to make data center developers assume much of this risk. But much of the country has yet to thoroughly explore what happens to utilities and their consumers in a data center bust.
State utility commissions have helped set the table for the affordability crisis by approving rate increases and spending that push the limits of what ratepayers can afford.
Commissioners, along with governors and members of state legislatures, “are finally taking heed of their policy missteps,” said Kent Chandler, senior fellow for the think tank R Street Institute and former chairman of the Kentucky Public Service Commission.
Chandler expects that some state-level discussions will focus on introducing competition in areas where utilities now have local monopolies, with the hope that market forces can help contain costs.
At the same time, states and regions that already allow competition in electricity and natural gas markets may go in the opposite direction and explore giving utilities more leeway to build power plants and pass costs on to consumers.
If this sounds disjointed, that’s because it is. The larger point is that officials will respond to frustration with rising prices by wanting to be seen as taking action.
The decision by Congress and Trump to eliminate consumer tax credits for electric vehicles will cast a pall on at least the first half of 2026 and maybe longer. The credit phaseout in the One Big Beautiful Bill Act last summer led to a sudden surge in EV purchases before the incentives expired at the end of September, followed by an expected drop-off in sales.
“We’re going to see sales be a bit more tepid,” said Mryia Williams, executive director of Drive Electric Columbus in Ohio.
The problem is that potential buyers “are not sure what’s going on with anything,” she said.
Automakers have some high-profile EVs coming this year, including the redesigned Chevrolet Bolt and the new Rivian R2. But some companies also are reducing and redirecting their funding for EVs, including Ford, which discontinued the F-150 Lightning pickup as a fully electric model and is replacing it with a gas-electric hybrid.
Williams has concerns that eliminating tax credits sends the wrong message to automakers and consumers at a time when other countries are moving ahead of the United States in building the vehicles of the future. That said, she remains confident that the world will make a near-complete shift to EVs, even if U.S. policymakers decide they want to move more slowly.
It’s normal for the party that’s not in power to gain seats in Congress in the first midterm election after a presidential election. And, considering that Republicans’ majority in the U.S. House is fewer than five seats, it would surprise nobody if Democrats win control of the chamber.
The larger questions are about the scope of Democrats’ gains, including whether the party will pick up enough seats to gain control of the U.S. Senate and make substantial progress in governor’s offices and state legislative chambers.
A big part of the answer will depend on how effectively Democrats communicate their agenda in terms of voters’ affordability concerns, said Caroline Spears, founder and executive director of Climate Cabinet, an advocacy group that supports pro-climate candidates in state and local races.
“Voters are angry about rising prices, and we have an undercurrent of instability in the economy that has become more of a feature rather than a bug in the last few years,” she said.
Spears’ organization is focusing on states such as Arizona, Michigan, Minnesota and Pennsylvania, where flipping just a few seats could make a big difference on climate and energy policy.
She highlights Arizona as a state with a huge upside in terms of Democrats being close to having enough control to unlock more of the economic benefits of solar power.
“The extreme anti-clean energy legislation we’re seeing out of the sunniest state in the country is just astonishing,” she said.
To underscore this point, she noted that Massachusetts has more solar power jobs than Arizona, a fact that should be upsetting to Arizonans.
Now it’s time for the closer: Amory Lovins, an engineer and cofounder of RMI, has done about as much as anyone to foster research and advocacy about energy efficiency and conservation.
I saved him for last because the discussion of rising energy demand should, and could, turn into one about the need for greater efficiency.
Efficiency can take many forms, including batteries with higher energy density, solar panels that can capture more sunlight and computer servers that require less electricity to perform the same tasks.
He expects to see progress in 2026 but thinks more about how actual progress compares to what could be achieved with the right investment, research and policy support.
The obstacles aren’t technical or economic, he said. They’re mainly cultural and institutional.
“This is not low-hanging fruit that you harvest and then it gets scarce and expensive,” he said. “This fruit has fallen off the tree and is mushing up around our ankles, rotting faster than we can harvest more.”
He didn’t discuss efficiency in partisan terms, but I will. We have a president who has taken steps to weaken government requirements that products become more efficient, casting this as a matter of consumer choice. Trump said in his “Unleashing American Energy” executive order that he is safeguarding “the American people’s freedom to choose from a variety of goods and appliances” including lightbulbs, dishwashers, washing machines, gas stoves, water heaters, toilets and shower heads.
While Trump said this is a consumer-friendly action that will save money, decades of research on efficiency standards show the opposite to be true. The Trump administration has said its actions on the standards will save $11 billion, but this is based on an estimate of the cost of the rules that doesn’t include savings on utility bills. If we consider the costs and benefits, the standards have a net savings of $43 billion, according to an analysis from the Appliance Standards Awareness Project.
So, in an election year amid an energy affordability crisis, one side is actively hostile to energy affordability.
Other stories about the energy transition to take note of this week:
Offshore Wind Developers Seek Quick Court Resolution to Allow Construction to Resume: Ørsted and Equinor, two of the companies building offshore wind farms, have gone to court to seek permission to resume construction of two large projects that were stopped by a Trump administration order, as Diana DiGangi reports for Utility Dive. This is in addition to Dominion Energy’s request that a court allow it to resume work on a separate offshore wind farm, which will be the subject of a hearing next week. Interior Secretary Doug Burgum had ordered a stop to construction last month, saying there is new evidence that offshore wind could pose national security risks, but he didn’t go into detail about the risks.
Negotiations on Permitting Reform Hit a New Roadblock: The Trump administration’s stop-work order for offshore wind has made Senate Democrats pause negotiations on a measure that would streamline the federal process for approving construction of new energy projects, according to Sen. Shelden Whitehouse, D-R.I., as reported by Kelsey Brugger of E&E News. Members of both parties have been working on this proposal, but there remain some major sticking points, including the fact that House Republicans want the legislation to favor fossil fuel projects and Democrats are asking for limits on the Trump administration’s ability to pick and choose which projects happen.
EVs Take a Back Seat at Consumer Electronics Show: The Consumer Electronics Show, taking place now in Las Vegas, has become a showcase for new EV models and technologies in recent years. But this year, automakers are not planning any major debuts of new EVs, signaling a shift in emphasis for manufacturers in response to the Trump administration cutting incentives for the vehicles, as Abhirup Roy reports for Reuters. Instead, much of the emphasis this year is on AI, robotics and self-driving vehicle technologies.
Inside Clean Energy is ICN’s weekly bulletin of news and analysis about the energy transition. Send news tips and questions to dan.gearino@insideclimatenews.org.
Federal regulators are demanding that PJM Interconnection, the country’s biggest power market, find a faster way to connect data centers to the grid without spiking energy costs or threatening reliability.
Those regulators and other energy experts increasingly believe that a practice known as flexible interconnection is key to juggling those imperatives — and a recent study offers compelling supporting evidence.
Flexible interconnection is simple in principle: Power-hungry customers like data centers supply their own power during the handful of hours per year when overstressed grids can’t handle their needs, allowing them to get online much faster and also save money for customers at large.
But to date, only a handful of utilities and grid operators have developed the technical and regulatory structures to make flexible interconnection a reality.
Astrid Atkinson, CEO of Camus Energy, and Carlo Brancucci, CEO of Encoord, whose companies aim to enable flexible interconnection, say that PJM could deploy the practice on a large scale. That argument is backed by a unique analysis of real-world conditions — modeled across every hour of the year on the same transmission grids that PJM manages — conducted by Camus, Encoord, and Princeton University’s ZERO Lab.
Their December report looks at six sites in mid-Atlantic states served by PJM. It concludes that a 500-megawatt data center using flexible interconnection and providing its own power during times of peak demand could connect three to five years faster than one that has to wait for grid upgrades and new power plants to be built in order to support its full power needs. By paying for the resources to cover any peak demand deficits, these flexible data centers would avoid passing those grid and generation costs on to customers already struggling with rising energy bills tied to data center growth, the report contends.
What’s more, the methods used in the report can be used by grid operators and utilities in PJM and across the country to enable other real-world flexible interconnection studies using standard interconnection tools and datasets, Brancucci said. “Everything else flows from that — what type of interconnection you need, what type of flexibility you need, what kind of contracts and agreements you need.”
“Our companies both offer commercial products that can do this,” said Atkinson, who co-founded Camus in 2019 after leading the team that maintains reliable computing for Google, the report’s sponsor and the preeminent tech giant working on real-world flexible interconnection projects today. In fact, she said, “we’re doing commercial modeling of similar sites right now.”
Data center flexibility is a hot topic. Recent reports from Duke University, think tank RMI, and analytics firms GridLab and Telos Energy all explore its viability and benefits.
But the report from Camus, Encoord, and ZERO Lab differs in a few ways that make it a far more practical blueprint for flexible interconnection, Atkinson said.
The first thing that distinguishes their report is that it uses in-depth, real-world data.
To approve flexible interconnections, utilities, grid operators, and data center developers must have data on power flows from generators across high-voltage transmission grid networks to giant power users. “You do need privileged data access to do this,” Atkinson said — and other research teams haven’t had that access.
But Camus, which provides grid orchestration software for utilities across the United States, including Pennsylvania’s PPL Electric Utilities and Duquesne Light Co., has that data for the six sites it modeled, Atkinson said. She wouldn’t reveal which utilities provided the data or the location of the sites, which in the report were given animal names such as Koala, Pony, Shark, and Whale. But she did confirm that they represent realistic targets for flexible interconnection.
The second thing that sets the report apart, according to Brancucci, is that it integrates the real-world operating conditions and constraints of the transmission networks serving data center sites. To do that, they used Encoord’s software platform, which simulates how real-world transmission networks operate during all 8,760 hours of the year.
“A 500-megawatt demand will have major impacts on any utility,” said Brancucci, who co-founded Encoord in 2019 after working as a senior research engineer at the National Renewable Energy Laboratory in Colorado and as a researcher at the European Commission’s Joint Research Centre. “That will change the way power flows. And when power flow changes, you need to consider different security constraints.”
Such analyses consider not just business-as-usual conditions but also emergencies when power plants or transmission lines fail and grid operators must act quickly to prevent widespread outages. “This is the type of transmission analysis any ISO or utility is going to do when considering new load,” he said, and it’s a must-have for approving a new 500-megawatt customer.
Encoord works with transmission system operators and utilities struggling to ensure reliable service under a variety of conditions, including during winter storms when fossil gas systems fail. “If 10 utilities and 10 hyperscalers came to us and said, ‘We want to interconnect across 10 sites,’ we could redo this easily,” Brancucci said.
The results for the six sites in the December report show that transmission constraints would force four of them to curtail significant portions of their 500-megawatt peak power demand or build enough on-site generation and battery storage to cover these gaps — but only for less than 35 hours per year. The other two sites did not have transmission constraints.
The third thing that distinguishes their report is that they were able to tap into a model developed by researchers at ZERO Lab and MIT to assess how adding data centers to the grid would affect the amount of generation capacity that PJM needs to cost-effectively meet peak electricity demand.
That model enabled them to analyze how individual data centers could secure a mix of faster-to-build power sources, including solar power, wind power, and hybrid renewable-battery systems, as well as secure commitments from other customers willing to lower their power use to cover data centers’ needs through demand response or virtual power plants.
Ultimately, the new data underscores in the most definitive terms yet that flexible interconnection is viable in PJM, Atkinson said. And if PJM were to allow it, data center developers would likely be more than willing to take on the responsibility of securing their own resources to relieve those rare constraints, she added. Doing so could allow them to get online in two or three years, rather than needing to wait five to seven years for new transmission or generation.
“Data centers are willing to pay more if they can connect, in many cases, because the opportunity costs” of being forced to wait for years “far outweigh the costs of capacity,” she said. “They just need to know how much they need to build.”
And once they’re armed with that knowledge, data centers can take on the cost of securing their own resources, which would almost completely eliminate the need to build more grid infrastructure and power plants, reducing costs for all PJM customers, according to the report.
PJM isn’t the only grid operator or utility facing data center–driven cost pressures. But its challenges are more acute than most. PJM has a massive interconnection backlog that has created multiyear delays for new generation seeking to connect to its grid. And its capacity market structure is forcing up utility rates today to cover the future costs of serving forecasted data center demand.
PJM hasn’t been able to gain consensus from stakeholders — including utilities, power plant owners, big corporate energy users, and data center developers — on how to fix these problems, even as the more than 67 million customers that get power from PJM’s system face spiking utility bills to cover those costs.
That lack of consensus has prevented PJM from developing a key policy that could allow flexible interconnection to happen, Atkinson said. In order for the method laid out in the December report to work, PJM and member utilities would need to allow data centers to interconnect via something called “conditional firm” grid service.
In simple terms, this means blending traditional, “firm” service for the portion of power needs that can be supplied without grid upgrades and “conditional” service, which requires data centers to cut their power use or supply their own electricity needs during critical hours.
PJM doesn’t provide this kind of option for customers — though it may have it soon enough. In December, the Federal Energy Regulatory Commission ordered PJM to create structures that would allow data centers and other big customers to connect to its grid in more flexible ways. That order set out a variety of methods for PJM to pursue, including a structure called “interim non-firm transmission service,” which closely approximates the conditional firm service that Camus and Encoord envision.
“At its core, the FERC order moves PJM away from ‘full freight’ assumptions and toward studying and serving large loads based on their actual time-varying grid use,” Brancucci said. “That’s exactly the premise behind the conditional firm service model we analyzed in a few locations in PJM.”
Similar innovations are being pursued by grid operators in the Midwest and Texas, Atkinson noted. The Department of Energy has ordered FERC to launch a fast-track rulemaking to require grid operators and utilities to expedite data center interconnections.
“Today, no market really allows you to have a mix of grid power and on-site power that’s reasonably managed,” Atkinson said. But a growing number of grid experts agree that flexible interconnection is, as she put it, “the only practical way to meet these requirements.”
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy and the environment. Sign up for their newsletter here.
Venezuela has the world’s largest oil reserves, but the South American country’s heavy oil deposits also stand out for another reason; on a barrel-for-barrel basis, they pack the most climate pollution.
Following the capture of Venezuelan President Nicolás Maduro by U.S. forces, President Donald Trump said, in a social media post on Tuesday, that the country would turn over 30 to 50 million barrels of high quality crude oil to the U.S. However, Trump himself previously stated that Venezuela’s oil is “the dirtiest, worst oil probably anywhere in the world.”
Venezuela’s “extra-heavy” crude is a thick, tar-like substance that typically must be heated to bring it to the surface and diluted with other chemicals before it can move through pipelines.
“It takes a lot of energy to heat the stuff and get it out of the ground and then get it to move and flow, and then turn it into normal products,” said Deborah Gordon, senior principal in the Climate Intelligence Program and head of the Oil and Gas Solutions Initiative for RMI, a nonprofit focused on clean energy. “And every energy input means a lot of emissions.”
Greenhouse gas emissions from heavy crude oil production, refining and use are, on average, 1.5 times higher than those of light crude oil, according to a 2018 study published in the journal Environmental Research Letters. The study, co-authored by Gordon, assessed the climate impact of 75 different crude oils worldwide.
Heavy crudes are also low quality oils that require more refining, which further increases the energy used to bring the fuel to market and its associated emissions, said Adam Brandt, an energy science engineering professor at Stanford University and the lead author of the study.
Oil from Venezuela, the majority of which is extra-heavy crude, has the second-highest carbon intensity of oil from any country, a policy paper published in 2018 by Brandt, Gordon and others in the journal Science concluded.
An updated analysis by RMI’s oil and gas climate index, based on 2024 data, found that oil from Venezuela had the highest carbon intensity among 55 leading oil-producing countries.
“Just because this hydrocarbon exists doesn’t mean that it should be marketed or taken out of the ground,” said Gordon, who is the author of No Standard Oil, a book that looks at the varying climate impacts of different crude oils. “If there is demand, there are far better places to go than Venezuela.”
Leaks and intentional venting of methane gas associated with oil production in the country contribute to its outsized climate impact. Methane is a potent greenhouse gas. On a pound-for-pound basis, it is more than 80 times worse for the climate than CO2 over a 20-year period.
Venezuelan oil had the second-highest methane intensity among leading oil producing countries in 2023, according to the International Energy Agency. The country’s high leak rate is due in part to ongoing oil and gas sanctions, which have led to poor resource management, Gordon said.
A lack of proper maintenance has also led to frequent oil spills. Venezuela’s state-owned oil company Petróleos de Venezuela, S.A., reported more than 46,000 oil spills between 2010 and 2016. The company hasn’t reported any spills since then. However, in 2020, the head of Venezuela’s Unitary Federation of Petroleum and Gas Workers, a labor union, estimated that oil spills occur almost daily in some states.
Despite Trump’s pledge to open Venezuela’s oil reserves to U.S. companies, that may not result in increased production.
Simply maintaining current production levels in Venezuela would require $53 billion in new energy infrastructure investments according to an analysis released Tuesday by Rystad Energy, an independent energy research and business intelligence company headquartered in Oslo, Norway.
Kirk Edwards, president of Latigo Petroleum, an independent oil and gas producer based in Odessa, Texas, called the U.S. government’s recent actions in Venezuela a “nothing burger” for oil markets.
“This is not ‘drop a rig and up comes the bubbling crude,’” Edwards wrote on LinkedIn. “Any real turnaround would require $50–100 billion of sustained investment, modern infrastructure, and years of political stability.”
Edwards said companies are unlikely to make that investment given current low oil prices.
Gordon said Venezuela’s oil and gas sector will continue to have an outsized climate impact, whether production increases or remains in its current state of disrepair.
“They’re just basically throwing stuff into the air,” Gordon said of current methane emissions.
Ohio’s largest utility wants to slash compensation for rooftop solar owners — which would affect not only future investments but also thousands of regulated utility customers who have already installed panels on their homes based on existing rules.
Later this year, the Public Utilities Commission of Ohio will decide whether to keep its statewide net-metering rules intact or whether to switch ratepayers to a less lucrative program proposed by American Electric Power’s Ohio utility.
The changes put forth by the utility are drastic and would raise costs and discourage others from going solar, a broad range of critics say.
“In a time that people are struggling to pay their bills, they are trying to gut net metering, which is one of the ways folks who are able to [can] save money by putting solar on their rooftop,” said Nolan Rutschilling, managing director of energy policy for the Ohio Environmental Council.
AEP’s proposal will be considered as part of the PUCO’s ongoing five-year review of the state’s net-metering rules. Parties’ case filings were due last month, although public comments can still be submitted.
The rules apply to the state’s investor-owned utilities: AEP’s Ohio Power Company, Duke Energy Ohio, AES Energy Ohio, and FirstEnergy’s three Ohio utilities. Ohioans have added more than 20,000 residential solar projects statewide since the current net-metering rules took effect about seven years ago, according to data from the sustainability consulting group Unpredictable City.
In effect, AEP wants to include distribution charges for all electricity flowing into a solar-equipped household, even if a big chunk winds up going back to the grid. The company describes the change as a shift from net usage to net billing. And it wants to limit net metering to customers who don’t pick their own electric generation supplier or take part in a community aggregation program.
The reduced compensation could substantially lengthen the payback period for rooftop solar investments.
“Residents that have already invested in solar have taken on the upfront capital cost because of the long-term utility savings supported by net metering requirements,” Casey Shevlin, director of sustainability and resilience for the city of Akron, wrote in a comment. “Their consumer rights need to be protected from net metering changes that could result in them benefiting less from solar investments they have made.”
Battles over net-metering rules have played out recently across the United States, including in the leading rooftop solar market of California.
There and elsewhere, critics of net metering argue that it forces the average customer to overpay for rooftop solar’s extra energy and that net billing is a fairer system. Supporters of net metering say that it provides systemwide cost savings by increasing distributed energy and that it’s a proven tool for deploying and democratizing clean electricity.
Among utilities, only AEP has formally opposed the recommendation by the commission’s staff to keep net-metering rules in place. The company’s proposal is supported by the Ohio Consumers’ Counsel, which said it wants to ensure there’s no “cost shifting” to people without rooftop solar.
But the AEP proposal has received massive pushback from environmental advocates, business groups, local governments, and others since its filing on the day before Thanksgiving.
The Citizens Utility Board of Ohio, Interstate Gas Supply, the Retail Energy Supply Association, Solar United Neighbors, the Ohio Environmental Council, and the Environmental Law & Policy Center have all filed formal replies with the PUCO, urging regulators to reject AEP’s arguments and to keep the current net-metering rules in place for all ratepayers.
AEP’s Ohio media relations office wrote via email, “Under net metering, a portion of the distribution-related charges are essentially shifted to other customers when the charges are calculated only for the net portion of the electricity delivered,” because infrastructure costs “are designed to be spread across the customers the system was built to serve.”
The company did not respond to Canary Media’s request for data showing how it or other regulated utilities would be hurt by net metering for customers who pick competitive energy suppliers or take part in community aggregation programs. The company has come after net metering before — and ultimately lost.
More than a decade ago, AEP took its arguments to limit net metering to the Ohio Supreme Court. The court ultimately dismissed that case after the PUCO released new rules that generally favored the company. A year after hearing lawyers’ arguments urging it to reconsider those rules, however, the commission changed course.
The current policy, adopted in December 2018, requires regulated utilities to compensate all rooftop solar customers for excess power, but it does not allow credit for distribution charges or for any avoided capacity charges.
AEP’s gambit to change the rules now surprised advocates for renewable energy, such as Mryia Williams, Ohio program director for Solar United Neighbors. “The PUCO staff had already concluded that net-metering rules are working as intended, and they didn’t think any changes needed to be made,” she said, referring to a Nov. 5 administrative law judge’s order in the rules docket.
The utility has not offered any data or other detailed assessment to justify its proposed changes, Williams said. And many rooftop solar owners relied on the current regulations when calculating whether to make the investment. “Everybody is just wanting to make sure that what’s already been promised is continued,” she said.
Plus, rooftop solar customers already pay for equipment to feed excess power to the utility. Levying distribution costs for electricity that customers wind up feeding back to the grid would, in effect, charge them for supplying the utility with distributed energy. Other energy suppliers don’t have to pay that expense, so it shouldn’t be something utilities can charge residents for either, said Nat Ziegler, manager of community solutions for Power a Clean Future Ohio.
Moreover, reducing net-metering compensation and limiting who can get it would discourage more people from adding rooftop solar, said Joe Flarida, executive director for Power a Clean Future Ohio.
“More generation on the grid will help limit the amount of price increases we’re seeing,” Flarida explained. “Certainly, if we can encourage more distributed energy, that would offset the amount of added power we need on the grid.”
Power a Clean Future Ohio is among the hundreds of groups and individuals who filed public comments with the PUCO, in addition to the formal party filings. That level of response represents a big change from a decade ago, Rutschilling said, noting increased interest in rooftop solar over the past few years.
People’s electricity bills have already jumped dramatically as grid operators like PJM have sounded the alarm about needing more electricity to meet demand from data centers, increased electrification, and other factors. And results of the most recent auction will almost certainly increase costs even more.
A bill introduced last fall would declare it state policy to “ensure affordable, reliable, and clean energy security,” with “clean energy” specified as meaning electricity from nuclear or natural gas, with no reference at all to renewables. But any new nuclear power requires years of review, and even with expedited permitting, Rutschilling noted, orders for new natural gas plant turbines have lag times of several years.
“We need as much generation as possible,” he said. “We need to have things like distributed energy.”
Almost a year ago, President Donald Trump declared that the United States was experiencing an “energy emergency.”
At the time, the U.S. was beating national and world-historical records for oil and gas production, as well as for wind and solar generation. But since then, the threat of an energy emergency really has emerged, in large part thanks to Trump’s own interventions in the power sector.
The Trump administration has blocked construction of renewable power sources, rescinded billions of dollars allocated by Congress to expand the grid and clean energy, and helped pass a law that vaporized federal tax credits for wind and solar projects.
These actions have compounded long-running challenges in connecting projects to the grid. All the while, the AI arms race — an avowed Trump priority — has pushed the need for new power production to dizzying heights.
Electricity demand will clearly outpace supply in the coming years, and concerted federal efforts are further reducing that supply. So, does that mean we are inevitably headed for an energy crisis? Nearly everyone I spoke with for this story believed the crisis was coming, if not already upon us.
“The mismatch just grows every day, with every new project cancellation and every new data center,” said Jesse Lee, a senior adviser at Climate Power, which advocates for action on climate change. “When you mismatch supply and demand that way, you get prices going through the roof.”
Indeed, residential electric utility rates rose by 13% from January to September of last year, and pressure on consumers became a major electoral issue in November’s gubernatorial elections in New Jersey and Virginia.
Longer term, the mismatch could result in regional energy shortfalls and threaten hundreds of billions of dollars in AI investment if the grid simply can’t keep up.
“Many parts of the country will have rolling blackouts in the next few years if we aren’t intentional about solving this crisis,” said Costa Samaras, who directs the Wilton E. Scott Institute for Energy Innovation at Carnegie Mellon University and worked on clean energy innovation in the Biden White House.
Somewhat dire stuff to kick off the new year with. But the very recognition of the problem is laying the groundwork for tackling it. And the looming menace of AI’s energy consumption just might deliver our best bet to convert energy scarcity into abundance.
This current energy predicament stands out from its predecessors because so many of the decisions constraining U.S. energy supply are being made domestically rather than by foreign adversaries.
Since resuming office, Trump has overseen continual supply-reducing moves, including:
“There is a crisis. It’s like we’re back in the ’70s, but instead of OPEC squeezing us, it’s us squeezing us,” said Armond Cohen, executive director of the Clean Air Task Force.
All told, 266 gigawatts of planned electricity generation projects fell through in 2025, according to analyst Michael Thomas. Thomas’ data platform, Cleanview, tracks more than 10,000 clean energy projects — a tricky task because developers often advance speculative projects to see if they can win a grid connection. But offshore wind tends to involve less speculation, given the hurdles to secure rights, Thomas said, and there’s been a clear trend of offshore wind cancellations this year in response to the administration’s hostility.
Other cancellations stem from issues that precede Trump’s directives, such as regional grid operators asking developers to pay exorbitant rates to connect to the network and local opposition blocking a project.
“So many of these challenges of how we build the necessary infrastructure to make the world better,” Thomas said, are “playing out county by county in these little battles of ‘Do we build a wind farm here, do we build a solar farm here?’”
Not all clean energy developments are under threat. The budget law Trump signed in July preserved Biden-era tax credits to install on-demand clean energy sources like batteries, geothermal, and nuclear, even as it did away with credits for wind and solar generation.
A Department of Energy spokesperson did not respond to questions about what the administration is doing about the declared energy crisis. The DOE has made some moves to expand electricity supply: It loaned $1 billion to help restart a nuclear reactor at Three Mile Island, and it kicked off a challenge to build new modular reactor designs by July 2026 — though these nascent technologies will take many years to secure regulatory approvals and enter commercial deployment.
Most intriguingly, Trump Media & Technology, the parent company of Trump’s own social media platform, Truth Social, announced in December that it would pursue a merger with nuclear fusion startup TAE Technologies. TAE hopes to generate clean baseload power in the early 2030s, though scientists consider cracking commercially viable fusion to be more technically challenging than running a niche and unprofitable social media platform.
Meanwhile, tech giants’ ambitions for AI computing construction have ballooned. Thomas said that while 20 to 30 gigawatts of data centers are operating today, 100 gigawatts are trying to connect in the next five years. Analysts at BloombergNEF predicted in December that data centers will consume 106 gigawatts by 2035; that number grew by 36% from the company’s tally just seven months prior.
Rep. Sean Casten, an Illinois Democrat and a leading energy wonk in Congress, said he worries about the current federal leadership’s capacity to respond to a full-blown energy crisis.
“Tell me how much volatility is coming down the pike, and it’s sort of like you’ve got a JV baseball team that’s working the ER shift tonight — if nobody checks into the ER, we’re gonna be fine,” he said.
Even so, Casten thinks widespread blackouts are a low-probability outcome because energy regulators have such a bias toward protecting reliability.
“The state utility commissions, the regional transmission organizations, they don’t always make good decisions, but they generally do prioritize reliability,” he said. “Having said that, the energy crisis that I think we should be super concerned about is on the price side.”
The Trump administration has raised the cost of energy not just by reducing supply. The delays it has caused for offshore wind projects have racked up hundreds of millions of dollars of unforeseen expenses, even before the most recent attempt to stop them from finishing construction. The interruptions also signal to foreign investors that billion-dollar projects in the U.S. are susceptible to extralegal disruption by the government, chilling future investment. Trump’s DOE has repeatedly invoked emergency powers to force old coal-fired plants to keep running beyond their planned retirement, leaving customers to foot the bill for tens, if not hundreds, of millions of dollars.
Those are system-level cost increases. On a more individual scale, when Republicans demolished the Inflation Reduction Act, they removed incentives for families to upgrade household energy efficiency, the Scott Institute’s Samaras noted. “Those save the homeowner money, but they also reduce the peak electricity demand when you really need it.”
The Trump administration could tackle the crisis by simply allowing American energy, including clean technologies, to flourish.
“Just get out of the way and stop blocking solar and wind permits,” said Shannon Baker-Branstetter, senior director of domestic climate and energy policy at the Center for American Progress. “If they believe in all of the above, really let it be all of the above.”
But that seems unlikely. Instead, the Trump administration is promoting gas power, though it has not taken steps to deal with the five-or-more-year waitlists to even buy gas turbines or their rapidly inflating costs. Its exotic nuclear bets won’t pay off for years, if ever.
Americans will have to look elsewhere for a remedy, and after so many pessimistic conversations, I finally found someone who was not only unfazed by recent developments but also optimistic about the future.
Pier LaFarge hails from Alabama and runs a startup called Sparkfund, which works with utilities to tap the benefits of clean and distributed energy. He speaks the language of the cleantech world but sees things differently than many in that cohort do.
We won’t crash headlong into an energy crisis, LaFarge assured me, precisely because everyone’s talking so much about crashing headlong into an energy crisis. This point recalled the Heisenberg uncertainty principle from my high school chemistry days: The act of observing something changes the thing that is observed.
Utilities and data center developers, LaFarge said, are coalescing around the understanding that demand during a relatively small number of hours in the year is constraining the AI buildout.
For decades, utilities built out the grid to meet the few hours of the year when demand peaks. That leaves capacity — in terms of power plants and transmission and distribution lines — wildly underutilized much of the time. The energy crisis won’t materialize, LaFarge argues, because it will catalyze the power sector to improve utilization of the existing grid.
Solve for a few moments of stress, and AI’s voluminous consumption of kilowatt-hours can support the fixed costs of running the grid for everyone else.
“Cheap batteries and data centers solve all of it,” he said. “You charge up when there’s excess, you drop it on the transmission and distribution corridors, you serve the data centers, downward pressure on rates, you win the future.”
In Oregon, an AI customer is already directly paying for grid batteries that will be used to benefit all of Portland General Electric’s customers. LaFarge said he has seen other confidential AI energy service agreements that will put multiple billions of dollars of downward pressure on utility rates for regular customers.
That’s more or less what Energy Secretary Chris Wright was talking about on his December publicity tour, though he attracts skepticism from clean-energy analysts when his idea for smart capacity investment amounts to forcing aging coal plants to stay open and hemorrhage money that other people have to pay for.
But if AI companies procure batteries, or portfolios of distributed energy and controllable demand, the economics change drastically. This would, in fact, achieve the cleantech sector’s long-held dream of an interactive and decentralized energy system.
This rosy scenario could fail to materialize for myriad reasons — states and regions failing to build grid infrastructure, regulators letting utilities dump billions of dollars into gas-plant construction at inflated costs instead of targeted battery investments, local leaders giving data centers sweetheart deals instead of demanding they pitch in.
But if batteries are allowed to play, the AI-fueled energy crisis could join the long list of energy crises that never came about. It’s comforting to know that’s at least a possibility.
As someone who spent several years as a workers’ rights organizer, Fredy Amador is intimately familiar with the financial struggles people face in the current economy. Northern Illinois’ skyrocketing energy bills make the situation even tougher.
Now, Amador has become an evangelist for something that can provide a modest measure of relief: a community solar project, built on a Superfund site too polluted for much else in the city of Waukegan where he lives, about 40 miles north of Chicago.
Residents who subscribe to get energy from the solar farm are guaranteed to see savings on their energy bills, under a state program incentivizing solar in low-income areas.
The 9.1-megawatt Yeoman Solar Project, which went online last month, can provide energy for about 1,000 households, as well as the Waukegan school district, which owns the land.
The school district bought the site in the 1950s hoping to build a new high school. But the land proved too swampy, and from 1958 to 1969 it was used as a dump for industrial and municipal waste. The highly contaminated Yeoman Creek Landfill was finally cleaned up 20 years ago, and now the district receives lease payments from CleanCapital, the national solar-investment company that owns and operates the solar farm.
Such brownfields are attractive locations for solar installations because of “existing electrical infrastructure, lower-cost land, and community acceptance,” noted Paul Curran, CleanCapital’s chief development officer. Incentives from the state initiative Illinois Solar for All helped make the project financially viable, even given extra costs incurred from building on a Superfund site.
It’s an example of how state policy can drive clean energy development and cost savings, even as federal tax credits for solar are being cut. The project also shows how solar can turn a community liability into an asset.
“The Yeoman Solar Project encapsulates so much of solar’s promise,” said Andrew Linhares, senior manager for the central U.S. at the Solar Energy Industries Association, a trade group. “The project instills new life into the Yeoman Creek Landfill Superfund site like only solar can.”
As an unlined pit amid wetlands, the Yeoman Creek Landfill leached toxic chemicals into the environment, including its namesake creek. In 1989, the landfill was added to the Superfund list, the federal program that requires companies responsible for pollution to clean it up.
The remediation was completed in 2005, though gas release, groundwater, and sediment are still being monitored.
“Since then, it’s been vacant,” and discussions started in 2012 regarding the fate of the land, said LeBaron Moten, deputy superintendent of Waukegan Community Unit School District No. 60.
“There were not too many options on the table for this specific site. We couldn’t build anything on it,” Moten said. “Our main objective was to keep people off it.”
Representatives of the school district, the city, and the group of companies involved in the cleanup decided to pursue putting a solar farm on the site, and in 2017 the school district issued a request for proposals. A national developer experienced in building solar on landfills, BQ Energy, was selected. In 2022, it was acquired by CleanCapital, which launched construction of the project.
Moten said the lease payments from CleanCapital and the energy savings from solar power will be helpful for the district, which serves over 13,000 students, the majority of whom are Latino and 68% of whom are considered low-income. The school district will be the project’s anchor tenant, using about 40% of the energy produced.
Seven of the school district’s buildings have rooftop solar arrays, which are referenced in sustainability lessons in the classroom. Moten said he hopes Yeoman Solar will similarly factor into educating students about clean energy, and potentially preparing them for jobs in the industry.
A longtime industrial hub, Waukegan is home to five Superfund sites. The city still has a lot of manufacturing, and until 2022 a large coal plant operated on the shore of Lake Michigan, not far from residents’ homes. That location remains contaminated with toxic coal ash. The community organization Clean Power Lake County and local activists have long demanded a just transition for Waukegan, in which economic opportunities and renewable energy benefit residents who have suffered from pollution.
Installing solar on brownfields is one way to accomplish this.
Solar is a good fit for sites that are too polluted for housing or other types of development, noted Curran. Under the terms of the Superfund remediation, residential use is prohibited at the Yeoman Creek site.
But installing arrays on landfills or other remediated areas does entail some challenges.
The U.S. Environmental Protection Agency reviews solar developers’ plans for Superfund sites, Curran said, to be sure the construction won’t damage caps over contaminated soil or otherwise release pollutants. The EPA examines “every single step of construction from how big ballasts can be, to stormwater protection, to how we’re going to revegetate,” he added.
Even mowing the grass below solar panels — a normally mundane process — can pose risks when a landfill lies underneath.
“The lawn is basically what’s holding the land in place, so you don’t get erosion,” Curran said.
An Illinois law passed in October and awaiting the governor’s signature creates a rebate for community solar paired with battery storage. Curran said that batteries would likely be too heavy to locate on a landfill, but CleanCapital may explore putting them on firmer ground nearby.
The company has developed solar on brownfields and landfills in other states, including a new 822-kilowatt site in Maryland. Curran said community solar should be built on more of the nation’s thousands of closed landfills.
Policies like those in Illinois help facilitate the process. A 2017 law created robust incentives for community solar. Since then, more than 700 community solar projects totaling over 1,800 megawatts have been built through the Illinois Shines incentive program. Another 33 projects representing 64 megawatts have been subsidized by Illinois Solar for All, a program for low-income and environmental justice areas (separate from the federal program of the same name that was ended by the Trump administration).
The Illinois Power Agency, which acquires power on behalf of utilities, procures solar built on brownfields. The Illinois EPA also provides low-interest loans and other resources for brownfield redevelopment.
Amador found out about Yeoman Solar from local clean energy leaders after he helped launch a Waukegan branch of the Chicago Workers Collaborative, which organizes and advocates for temporary workers. (He is no longer with the group, though he still lives in Waukegan.)
Community solar makes clean energy accessible to people who can’t or don’t want to install solar on their own homes — like Amador himself.
“I live in a condo building, and if I bought a house I probably would not have solar panels. I don’t like how they look on rooftops,” he said.
He often gets the same reaction when he tells people about community solar. “At first they think I’m talking about installing solar on their homes — they don’t want that.”
But after explaining and extolling the community solar model, Amador has recruited dozens of family, friends, and members of his church to subscribe to Yeoman Solar.
“It will help their wallet and help the ecosystem too,” Amador said.
The Yeoman Solar subscriptions will cover more than 90% of a household’s energy needs, said Ryan Libby, director of subscriber acquisition for PowerMarket, which CleanCapital contracted to recruit subscribers. Amador expects to save about $300 a year through his subscription, which equates to about 5 kilowatts of solar panels.
“That money can pay for utilities, for food, for other bills,” Amador said. “With how bad this economy is, it’s an important impact.”
Yeoman Solar is the largest community solar array in the territory of ComEd, the utility that serves northern Illinois. It reduces the amount of energy the utility needs to provide, and ComEd has praised the project. While any ComEd customer can subscribe, Curran said CleanCapital is prioritizing outreach to Waukegan residents.
Amador indeed feels it represents a new path for the city.
“All the pollution, the coal plant, the disinvestment — communities like Waukegan should be prioritized for projects like this,” he said. “I’d like to encourage people to ask questions — go to meetings, find out how these projects work, try to sign up. That will help them to save some money, and if we all participate, we’re stronger.”
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