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Essentially everyone agrees: Americans shouldn’t pay higher electric bills to feed AI data centers’ insatiable demand for power. But what will it actually take to prevent cost spikes?
Lots of states have decided the answer is a “large load tariff” — an unsexy term that basically translates to special utility rates and requirements designed for huge energy users, like data centers.
As of late 2025, more than 65 such tariffs have been proposed or approved in over 30 states, according to data tracked by the Smart Electric Power Alliance and the North Carolina Clean Energy Technology Center.
These efforts are largely trying to solve the same problem: The explosive growth of AI data centers is outpacing utilities’ ability to build power plants and upgrade the grid. If data centers don’t show up and stick around to buy all the power that’s justifying those investments, other customers could be trapped paying them off for decades to come.
This puts enormous pressure on regulators to “hold the line on ensuring that these large-load customers carry the costs that they bring,” said Jay Griffin, executive chair at the Regulatory Assistance Project. The nonprofit last month launched a report series to help regulators and policymakers navigate these complexities.
The trend of states adopting data center–focused large load tariffs began to take off in 2024, led by early movers like Ohio and Indiana. More such tariffs were approved in Kansas, Michigan, and Virginia last year, and now Illinois and Wisconsin are debating their own proposals. With roughly a year and a half of data on how different states have tackled the problem, “there’s enough time and transparency into decision-making that commissioners are able to make appropriate decisions,” Griffin said.
Progress is decidedly mixed, said Louisa Eberle, a senior associate at the Regulatory Assistance Project who co-wrote its first data center report. “Some are just getting started. We haven’t reached full ‘best practices’ anywhere — but we have found better practices.”
Those start with contracts requiring these giant new customers to pay a minimum amount of money for power for a set period — usually 10 to 15 years — whether or not they end up being built or staying open that long. This offers some insurance against data centers pulling out and leaving customers at large holding the bag, although some advocates fear those terms aren’t lengthy enough to cover the cost of power plants and grid investments, which must be paid off over decades.
Some tariffs also lay out what kind of power such massive customers must use — namely, clean energy. These can match up nicely with both state climate targets and the clean energy goals of the tech giants, like Amazon, Google, Meta, and Microsoft, that are driving the AI boom — although plenty of utilities and data center developers are going big into fossil gas–fired power as well.
And on the cutting edge of large load tariff policy, some utility regulators are asking data centers to “bring their own” generation or grid capacity, Eberle said. The idea here is to make developers play a more active role in sourcing and contracting for new energy resources for their computing facilities. That might not be utilities’ favorite option, since it cuts into the profits they earn from investing in power plants and power lines. But it’s an opening for data center developers willing to pay a premium to get onto the grid faster.
These negotiations aren’t easy, Griffin said. Tech companies are asking utilities to invest billions of dollars to serve power demand equal to that of entire cities springing up on their grids over just a few years. The sheer scale and speed of the boom have overwhelmed regulatory processes built for slow and low growth.
And the future is highly uncertain. Tech companies keep upping their AI spending plans, even amid mounting signs that the sector is a bubble about to pop. The Trump administration’s call in recent months for data centers to build their own power plants as a means to protect utility customers from rate increases conflicts with hard limits on how quickly new generation can be built and connected to the grid.
As the former chair of the Hawaii Public Utilities Commission, Griffin knows that regulators are constantly balancing the risk of letting utilities build too much power with the risk of preventing them from building enough. The former threatens to burden customers with unnecessary costs, while the latter can constrain economic growth and even endanger grid reliability.
Right now, public opposition to data centers is squarely focused on the financial and environmental dangers of overbuilding. Laws passed in Minnesota, Oregon, and Texas last year, and bills being debated in states including Florida, Georgia, Illinois, Virginia, Washington, and Wisconsin, propose everything from stripping tax breaks for data centers to imposing full-on construction moratoriums.
However, data centers that cover their costs and finance more-sustainable resources could help in “reducing cost for everyone,” Griffin said, both by increasing utility revenues to cover shared expenses and by pushing “innovation for emerging technologies,” such as virtual power plants and on-demand clean energy resources like geothermal power. Tech giants “have the demand for power and the need for speed to drive those in a way we’re probably not going to see for another generation,” he said.
While no two large load tariffs are exactly alike, many share common characteristics, as think tank RMI highlighted in a November review.
About a third of the 65 large load tariffs on deck as of late 2025 require big customers to make minimum payments over a set period of years, whether or not they remain operational over that time. More than half include some form of collateral requirements or other credit risk protections. And roughly half require large customers to pay fees if they exit their contracts early.
These requirements can help cull the speculative data center proposals now crowding utility interconnection queues, whether from companies with projects that are highly unlikely to win financing or from major developers “shopping” single projects across multiple utility territories. American Electric Power’s Ohio utility, for example, saw its large load pipeline drop from 30 gigawatts to 13 gigawatts after it instituted a large load tariff last year. In that sense, “not only do strong tariffs help protect customers, they also help the utility in forecasting what’s coming,” Eberle said.
But the tariffs might not be sufficient to pay off the cost of power plants and grid investments that last for decades, said Ben Hertz-Shargel, global head of grid edge at research firm Wood Mackenzie. Last year, he ran an analysis that found none of the large load tariffs on the books at that time were sufficient to fully recover the cost of new gas-fired power plants that would need to be built to serve big energy users.
The scale of fossil fuel build-out being contemplated to serve the high side of the AI bubble would be ruinous on both cost and climate terms. The Sierra Club is tracking a startling 248 gigawatts of gas-fired power plants being planned across the U.S. as of the first quarter of 2026, nearly five times the amount planned in 2021. Data center expansion is the primary driver of that increase, including for build-outs planned in Georgia, Louisiana, and North Carolina— states that have yet to impose large load tariffs.
“There are some utilities that are starting to creep up and charge for what it takes to build a new power plant today,” Hertz-Shargel said. “But it’s still uneven.”
Nor can tariffs guarantee that data centers will pay for transmission built to accommodate their impact on regional grid networks, he said, since those costs are allocated via complex structures that make it hard for utilities to force expenses on individual customers. The Illinois attorney general’s office has raised that issue in challenging utility Commonwealth Edison’s proposed transmission service agreements for data centers.
Even tariffs specifically designed to force individual data centers to cover the costs of utility investments expose customers to financial risk, said Jeremy Fisher, principal adviser on climate and energy with the Sierra Club’s Environmental Law Program.
He cited Wisconsin, where utility We Energies has proposed two tariffs meant to isolate the cost of building power plants and transmission grids to the gigawatt-scale data centers being planned in its territory. Those tariffs allow data centers to pay for new solar, wind, and battery storage. But they also offer an option for the facilities to contract for power and capacity from two gas-fired plants that the utility is planning to build. Under that latter option, everyday customers would remain responsible for paying for 25% of the cost of building these plants, as well as for the fuel they burn.
Meanwhile, two of the planned data centers in We Energies’ territory will consume as much power as the utility’s entire residential customer base, Fisher noted. “I don’t know how you quantify the concentration risk of two customers doubling the size of your load,” he said. “We’ve never seen anything like this.”
Hertz-Shargel added that the risk of a handful of customers driving most new demand is compounded by the nature of AI growth. The sector is fueled by hundreds of billions of dollars of debt financing and circular deals that could unravel if one or more major players fail to deliver.
“If the utility is going to have half of its assets caused by and paid for by a small number of customers, you need to be very concerned about that level of business risk,” he said.
That’s why Hertz-Shargel and other clean energy advocates are pushing a solution adopted by only a handful of utilities and regulators so far: requiring data centers to contract for their own clean energy and capacity.
The concept goes by many names — one of the catchiest is BYONCE, for “bring your own new clean energy.” But Hertz-Shargel uses the term “clean transition tariff,” a phrase coined by Google and Nevada utility NV Energy for a tariff approved by state regulators last year. That agreement allows the search giant to directly tap a geothermal plant being built by startup Fervo Energy.
Last week, Google announced a plan with Minnesota utility Xcel Energy that expands on this premise. Like Google’s agreement with NV Energy, it is a one-off deal rather than a tariff that applies to other large-load customers. But under it, Google will pay for the construction of 1,400 megawatts of wind, 200 megawatts of solar, and 300 megawatts of energy storage, and cover the grid infrastructure costs to bring it all online. It will also invest $50 million in the utility’s proposed Capacity*Connect distributed battery program.
“All parties should love it,” Hertz-Shargel said. “Data center companies get to choose the generation technology that supplies them, generation developers can play in new markets, and utilities get to sleeve the agreements between them.”
Utilities that profit from building power plants may not be as enthused, he conceded. But they already have enormous investments to make in distribution and transmission. “Adding on power plants to serve data centers would add additional revenue, but at enormous political cost,” he said.
Utilities can also squeeze more clean capacity out of the existing grid, Eberle noted. That could look like improving energy efficiency, paying customers to use less power when demand is high, and leveraging rooftop solar systems and home batteries to ease strain on the grid. These strategies “can be scaled up quickly and cheaply,” and they “will be useful even if the load doesn’t emerge,” she said.
Data centers could also agree to strategically reduce their own power use when the system is strained or to install batteries that can relieve near-term grid pressures.
How can large load tariffs tap into this kind of clean and flexible capacity? Fisher highlighted last year’s settlement agreement between Kansas utility Evergy, which has some significant data center projects in its territory, and groups including the Sierra Club, the Natural Resources Defense Council, Google, and the Data Center Coalition.
The tariff allows data centers to earn credit for flexibility they contract directly, Fisher said. But it also gives them the option to contract for renewables, energy storage, or efficiency programs in Evergy’s integrated resource plan, the regulator-mandated process to determine the mix of new power plants and programs the utility can invest in.
That’s an important wrinkle on the “bring your own” concept, Eberle said. It allows data centers to “engage with the utility and say, ‘We really like this resource that you identified but didn’t select — we’d like to pay for it.’”
Another option under the tariff would allow Evergy to seek out and directly charge a developer for the capacity needed to allow a data center to come online, she noted.
Griffin highlighted that these kinds of collaborative agreements take more time and require concessions from utilities and data center companies alike. But “you’ll be more successful if you give commissioners and stakeholders time and space to do the vetting — and that should support the more sound business models,” he said.
As for data center developers trying to push their costs onto consumers, Griffin said, “the more you force commissions to stick their neck out — well, you don’t get that pass many times.”
A clarification was made on March 4, 2026: This story has been updated to clarify that the Smart Electric Power Alliance’s data on large load tariffs was compiled in partnership with the North Carolina Clean Energy Technology Center.
China is accelerating its efforts to clean up heavy industry, allocating money for the first time last year to help hard-to-decarbonize sectors increase the use of fuels such as green hydrogen. The push comes as the country continues building more solar panels, wind turbines, and nuclear reactors and expanding its grid faster than anywhere else in the world.
Those two trends are converging to spur the greening of aluminum in particular — a commodity that requires so much power to manufacture that it’s nicknamed “congealed electricity.”
Aluminum production hit a record high last year in China as demand for the alloy, which is used in virtually every kind of electrical application, soared in tandem with the country’s data center boom, according to numbers the National Bureau of Statistics released in January. Prices of the globally traded commodity have spiked by nearly 35% in the past year, meaning that aluminum produced with clean electricity, which comes with a green premium, is more competitive.
At the same time, Beijing’s latest policies to steer its world-leading aluminum smelters away from coal are just taking effect. While the most recent national statistics showed steel production at a seven-year low — a result of the shift away from housing construction — analysts say the surging demand for aluminum could speed up the pace of that industry’s transformation.
“I do expect green aluminum production to pick up, even as other commodities retrench,” said Xinyi Shen, the head of the China team at the Centre for Research on Energy and Clean Air, a Finnish nonprofit that tracks Chinese heavy industry. “In China, aluminum decarbonization is progressing … showing stronger policy momentum than steel at the moment.”
There are limits to how quickly the shift can take place. China has for the past decade maintained a cap on aluminum production to prevent smelters from oversupplying and destabilizing the power grid. New production to meet surging demand is quickly approaching that limit, according to a December analysis from the bank ING. But already, the industry is starting to reorient production toward decarbonization.
One way China’s aluminum industry is going green is through recycling. Producing secondary aluminum requires only about 5% of the energy needed to produce primary aluminum, meaning that carbon emissions are typically up to at least 80% lower. Between 2015 and 2024, China’s recycled aluminum output grew by about 6.25% per year, reaching nearly 11 million metric tons in 2024. In March 2025, Beijing set a target of more than 15 million tons of recycled aluminum by 2027.
“This pathway is already cost-competitive and relatively insulated from power-price volatility, so it’s likely to keep expanding even in a softer macro environment,” Shen said.
The other way is by transitioning existing smelters to using clean power. Since nearly 70% of primary aluminum production relies on coal-fired or natural-gas-fired power plants, the sector produces about 2% of global greenhouse gas emissions. The rest is largely powered from hydroelectric dams, next to which older smelters were traditionally sited.
The power-intensive smelting process involves blasting a molten bath of cryolite with an electrical current that separates out dissolved aluminum and yields a molten metal that can be cast into ingots, billets, or bars. In China, where most of the world’s aluminum is produced, the vast majority of that electricity has historically come from coal. Under its new regulations, Beijing wants most of the power that smelters consume to come from renewables.
Last year, aluminum became the first energy-intensive industrial sector subject to a new renewable power mandate requiring green electricity to supply 70% of smelters’ electrons, up from just over 25%.
“Compliance is expected to be met increasingly through green power contracts and renewable-energy certificates, partly in response to both China’s domestic climate goals and emerging international green trade standards,” Shen said.
China has begun shifting its smelting capacity to provinces with excess hydropower or room for wind and solar arrays to offset coal- and gas-fired production.
Even before Beijing mandated that aluminum producers use more renewable power, smelters were already “looking at moving to hydro-rich regions” such as Yunnan province, David Fishman, a Shanghai-based analyst who tracks the Chinese electrical industry at the Lantau Group consultancy, wrote in a thread on X last month.
Wind and solar trailed behind hydropower, nuclear, and coal in the list of the lowest retail power prices in China, Fishman wrote. But he said that buying renewable energy credits was just as valid a solution if those certificates come from vetted, reputable sources in places with expanding production, such as Inner Mongolia or Xinjiang. Still, he noted, relocating to renewables-rich regions “isn’t just about cheap power.”
“It’s also about reducing uncertainty around long-term compliance with rising clean power quotas, which is becoming a C-suite level strategic variable,” Fishman wrote. “This is as true [if] you’re moving the smelter to Yunnan (for all its hydropower) or Xinjiang (where you’re going to have to pursue a wind/solar solution).”
A big open question is whether Chinese companies will start operating new smelters in other countries, and whether those facilities will be powered with renewable electricity, said Seaver Wang, the director of the climate and energy team at the Breakthrough Institute, a research nonprofit in California.
“The next big story in global aluminum is whether Chinese firms start developing overseas, particularly in Indonesia and Vietnam,” Wang said, noting that Indonesian advocates he’d spoken to feared that the facilities would use coal. “With aluminum capacity in China capped, where is the industry spilling over into?”
Rising demand globally for lower-carbon products is spurring on Chinese industry. That’s particularly true now that the European Union’s carbon tariff — the first in the world — took effect in January. Brussels is considering establishing a way to selectively exempt industries from the levies. But the bloc has so far vowed to keep requiring importers to buy carbon certificates to offset the emissions produced during manufacturing.
The China Nonferrous Metals Industry Association rolled out updated rules last year for the certification and trading of “green electricity aluminum,” in a move Shen said was “intended to ensure that low-carbon aluminum carries recognized commercial value in the market, rather than being merely a reporting label.”
Last summer, a Chinese steelmaker scheduled its debut shipment of green steel to a buyer in Italy, carving out the start of a supply chain that would comply with the EU’s carbon tariff. In November, top steel trade associations in Europe and China agreed to work together to create uniform standards for what qualifies as green.
If China’s experience with solar panels and batteries — in which its efforts to meet domestic demand led to a flood of cheap exports — is any indicator, the global market could soon have an influx of green aluminum.
Geothermal startup Quaise Energy is pushing to build out its first “superhot” power plant this year as more money flows to next-generation geothermal projects.
The Houston-based company says it’s developing a 50-megawatt plant in central Oregon that will tap into significantly hotter geothermal resources than its competitors do, using the firm’s novel rock-melting technology. Quaise broke ground on that site, called Project Obsidian, last year and plans to drill a well this year that will allow it to validate the subsurface conditions, which are expected to reach over 300 degrees Celsius (572 degrees Fahrenheit).
“That’s really in full swing in Oregon,” Harry Kelso, the communications manager for Quaise, told Canary Media.
Quaise is seeking $100 million in Series B financing to support its first commercial plant in Oregon, as Axios first reported last week and Kelso confirmed. The company is looking to secure another $100 million in grants and debt for the project, which it plans to bring online by 2030. It has already signed a power-purchase deal for the initial 50 MW with an undisclosed customer and is working to ink agreements for an additional 200 MW in future capacity, he said.
Eight-year-old Quaise is riding the wave of interest in cutting-edge geothermal technologies.
The United States is clamoring for new sources of electricity, particularly from projects that can produce power around the clock and without carbon emissions. Next-generation geothermal, a broad umbrella that includes a variety of improvements on conventional systems, promises to deliver that — but the sector is still in the early stages of development.
Already this year, investors have closed major funding rounds for startups Sage Geosystems and Zanskar. Fervo Energy, which aims to bring an initial 100-MW enhanced geothermal system online in October, filed for an IPO in January. Just last week, the Department of Energy announced $171.5 million in funding to support field-scale tests of next-gen technologies.
Strong Republican support for the industry also spurred Congress last year to keep tax credits in place for geothermal, even as the Trump administration revoked incentives for wind and solar.
This year “is by far the most exciting time for geothermal in a while, because you have an insatiable need for power,” said Curtis Cook, founder and CEO of Rodatherm Energy Corp., referring to demand from data centers and electrification more broadly. His Salt Lake City–based geothermal startup closed a $38 million Series A funding round last fall to develop its “closed-loop” geothermal pilot plant on federal lands in Utah.
As more startups advance projects this year, potential investors and lenders will gain a better understanding of the capital and operating expenses associated with these emerging technologies. “That’s an inflection point for meaningful growth within the industry,” Cook said.
In Oregon, Quaise’s Project Obsidian will initially use conventional drilling tools to begin building an enhanced geothermal plant near the Newberry Volcano. This approach involves fracturing rocks and pumping them full of water to create artificial reservoirs, which harness Earth’s heat to drive steam turbines on the surface.
Fervo and the government-backed Utah Forge initiative are also developing enhanced systems. But Quaise says it could be the first to operate a commercial plant in superhot rock. These resources are not only dramatically more efficient at generating energy but are also widely available — so long as your equipment can withstand the scorching and corrosive conditions.
To that end, as early as next year, Quaise aims to start deploying its novel millimeter-wave drilling techniques at its power plant. The technology uses high-frequency beams to melt and vaporize rocks, with the goal of accessing hotter resources that are typically found several miles below where traditional drilling equipment can reach.
Quaise has raised a total of $120 million so far from investors to accelerate testing and development, including from Mitsubishi and the oil-and-gas drilling contractor Nabors Industries.
Last year, Quaise said it successfully used its tech to drill to a depth of around 330 feet at a test site near Austin, Texas. Now, it’s gearing up to drill to nearly 3,300 feet later this year. For context, that’s less than half as deep as the vertical wells at Fervo’s first project, a 3.5-MW enhanced geothermal plant in Nevada. But Quaise says it’s working to advance the technology and reach depths of 16,000 feet and far below at the Oregon site.
“We’re bringing those two factors together — superhot geothermal and the drilling technology — so that we can do this just about anywhere” in the world, Kelso said. “That’s the whole ambition, and why this year is so important.”
This story was originally published by CalMatters. Sign up for their newsletters.
If you’re a California homeowner and you’ve been feeling chilly this winter, there are plenty of reasons to go get a heat pump.
An all-electric, energy-efficient alternative to gas-burning furnaces, heat pumps are widely seen as the climate-friendly home heater of choice.
They can do double duty as both home heaters and AC units and are pretty good at maintaining a constant temperature inside a home without the blast-then-cool-off cycle typical of a furnace.
What about a guaranteed lower monthly utility bill? Not in California.
Call it California’s heat pump conundrum.
On the one hand, California has hyperambitious goals to reduce greenhouse gas emissions in an effort to curb the worst effects of a changing climate. Most experts see the electrification of buildings — swapping furnaces, water heaters, stoves, and ovens that run on burning fossil fuel with appliances plugged into California’s increasingly green electrical grid — as a necessary step toward meeting those goals.
California has built one of the most aggressive heat pump strategies in the country. The state aims to install 6 million heat pumps in homes by 2030. Lawmakers are also moving this year to boost heat pump adoption — proposing to streamline permitting and make it easier to electrify homes.
On the other hand, California’s residential electricity prices are among the highest in the country — expensive even compared to its also pricey natural gas. That makes heat pumps a tough sell to many Californians.
A new Harvard University study maps exactly where that reality bites — and tries to explain why some places are more heat-pump friendly than others.
The public is “overwhelmed with these sorts of plans now for decarbonization: ‘This by 2030,’ ‘this by 2050,’” said Roxana Shafiee, an environmental science policy researcher at Harvard University. “But then you scratch the surface a bit more and you look at things like electricity prices.”
Reaching those goals amid such high prices is a tough circle to square, said Shafiee.
By looking at residential energy costs, usage, and winter temperatures in every county in the United States, Shafiee and Harvard environmental science professor Daniel Schrag found in a recent paper that typical households living across the American South and the Pacific Northwest would likely see lower utility bills by making the switch to a heat pump.
Average homes in northern Midwestern states, in contrast, would see their bills increase. That’s partly because heat pumps work by extracting heat from outdoor air, compressing it, and piping it indoors, a thermal magic trick that’s harder to perform in places with subzero winters. It’s also thanks to the region’s relatively cheap gas.
Then there’s California: a surprisingly mixed bag.
Though the state’s temperate coast is ideal for heat pump adoption, high residential electricity prices can make swapping a gas furnace for a heat pump a pricey proposition. That’s especially true in counties where homes tend to be larger, winters are colder, or electricity is costly.
Quentin Gee, a manager at the California Energy Commission, said the advantage of heat pumps comes down to thermodynamics. Unlike a gas furnace, which burns fuel to create heat, a heat pump compresses and expands a refrigerant, like a refrigerator in reverse. That moves heat from outside into a home — allowing it to deliver several units of heat for every unit of electricity it uses.
Even in Pacific Gas & Electric territory, where electricity rates may be some of the highest in the U.S., Gee said that efficiency can allow heat pumps to compete with — and in some cases beat — gas on operating costs, depending on local rates and home characteristics.
In lower-cost municipal utility regions such as Sacramento’s Sacramento Municipal Utility District, he said heat pumps can be a clear financial win.
“Gas prices have also gone up over time as well — so both are tricky when it comes to heat pumps versus, say, a gas furnace,” Gee said.
Between 2001 and 2024, average retail gas prices have gone up by 80% in California, according to federal data. Retail electricity rates, padded out with wildfire prevention costs and state-mandated social programs, have increased by twice as much.
Even in parts of California where the average home isn’t likely to save with a heat pump, there are plenty of exceptions. Smaller, well-insulated homes can often stay warm with minimal output from a heat pump.
For some homeowners, solar panels have helped bridge the gap. Doug King, a green building consultant in San Jose, installed his first heat pump in 2021 alongside a new rooftop solar system; those panels more or less covered the monthly cost of running the heat pump. A second unit installed last year has pushed his bills higher. “But that’s fine, I don’t mind,” he said. “I was willing to pay a bit of a premium for using electricity over gas anyway.”
Homes that already use old-fashioned electrical baseboard or space heaters are guaranteed to save on monthly costs by switching since that entails swapping an inefficient electrical heating system that uses a ton of energy (“basically like heating your home with a toaster,” said Shafiee) for heat pumps that use up to 60% less.
But for all of California’s reputation as a climate champion, most of its homes don’t rely on electric heat. Nearly two-thirds use natural gas, well above the national average of 51%.
That isn’t surprising, said Lucas Davis, a University of California, Berkeley, energy economist.
Looking at 70 years of home heating data across the country, Davis’ research has found that the best predictor of whether a household uses electricity to stay cozy in the winter is the price of energy.
“To this day, where do we see that electric heating is the most common? Throughout the Southeast,” said Davis. “What do we know about the southeast? Cheap electricity.”
The consequences of costly electricity extend well beyond any individual household’s ambitions for a heat pump or its utility bill. Using fossil fuels to heat up water, warm indoor air, and cook food inside homes and businesses was responsible for 13% of the country’s greenhouse gas emissions in 2022, according to the U.S. Environmental Protection Agency. Gas-powered cars and trucks used for private use make up another 16%.
Heat pumps are a 19th-century invention and started popping up regularly in American homes in the 1960s, but you would be forgiven for thinking they’re a new technology.
Spurred on by concerns over climate change and policies meant to address it, heat pumps have outsold gas furnaces each year since 2021, according to the Rocky Mountain Institute, a clean-energy research nonprofit. Demand saw a particularly sharp spike after 2022 thanks to the Inflation Reduction Act, the Biden-era law that threw rebates and tax credits at homeowners.
Installation costs can reach into the tens of thousands of dollars, which is why most federal and state policies promoting heat pump adoption have focused on defraying them. In California, the push runs through multiple agencies:
This year, state lawmakers are considering bills to speed up the local permitting process for heat pumps and to require gas utilities to offer homeowners cash to electrify their homes in lieu of replacing an old gas line.
Even as the federal supports subsided with President Donald Trump’s return to the White House, installation costs are “pretty competitively priced with traditional units, especially since in most cases, you are installing two appliances for the price of one,” said Madison Vander Klay, a California policy advocate for the Building Decarbonization Coalition, a national nonprofit which represents appliance manufacturers and utilities.
That may not be the case for all homeowners.
Many homes need new wiring, larger breakers, or a full panel replacement, and some require upgrades to the service connection to the grid, said Matthew Freedman of The Utility Reform Network. Costs rise quickly when homeowners electrify more than just heating, he said.
Customers often underestimate how complex and costly that electrical work can be, he said, another uncertainty on top of the potential for long-term rate savings.
Installation costs aside, month-to-month electricity costs remain an obstacle.
Last year, the Legislative Analyst’s Office released a report warning that California’s residential electricity rates are among the highest in the country — nearly double the national average — and rising much faster than inflation.
The report, authored by LAO analyst Helen Kerstein, cautioned that those high rates could undermine the state’s climate strategy by discouraging households from switching to electric cars and appliances like heat pumps from gas-powered ones.
“If I’m a consumer, I’m going to be thinking about — not just, ‘Is this good for the environment?’ That’s certainly one consideration, but also, ‘Is this something I can afford?’” Kerstein said. “Unless folks are saving money on the operating cost, it often doesn’t pencil out.”
An upheaval is underway in the nation’s electricity sector, and Virginia is ground zero. As the data center capital of the world, the state faces surging demand, ballooning utility bills, and a bottlenecked grid — all challenges that policymakers are navigating while maintaining a legally mandated course toward carbon neutrality.
Now, the state is poised to become the first in the nation to quantify and examine ways to reduce waste on the electric grid — a potentially monumental move toward reining in rates and speeding the clean energy transition. Maximizing usage of our existing network of power lines and related infrastructure, backers say, could also help close the gap between the public interest and that of investor-owned utilities.
House Bill 434 would direct Appalachian Power Co. and Dominion Energy, the state’s two predominant vertically integrated utilities, to gather and report detailed data on their grid utilization. The measure won final approval from Virginia’s Democratic-controlled legislature this week and now heads to the desk of Gov. Abigail Spanberger — a Democrat whose victory in November was fueled in part by anxiety over rising electricity costs. As one of the earliest proposals Spanberger offered after her election to address energy affordability, the bill looks certain to become law.
Many experts say the information the measure would require is itself meaningful: Utilities have long resisted gathering and reporting such metrics, in part because doing so could hurt their case to build out more infrastructure that pads their bottom lines.
But advocates for HB 434 say its real impact could come after the utilization data has been reviewed by regulators, who must then establish a timeline for utilities to optimize grid usage. The bill directs officials to give special consideration to “non-wires alternatives” like batteries and line sensors.
“The fact that Virginia became the first state to introduce this sort of legislation is pretty significant,” said Charles Hua, the founder and executive director of PowerLines, a nonprofit that aims to lower utility bills and supports HB 434. “But this would just be the first step of a long journey.”
The legislation is premised on an incredible reality: Roughly half the electric grid goes unused about 99% of the time. Poles, wires, substations, and other components are built out to deliver electrons during periods of maximum demand, such as during the recent cold snap brought on by Winter Storm Fern. But those peak events are rare.
“This is where this conversation has been stuck for 20 years,” said Pier LaFarge, the co-founder and CEO of Sparkfund, which helps utilities deploy and manage distributed energy sources. “We’ve built the grid to peak … then said, ‘How much space is left?’ But what’s amazing is, the grid only is at peak 50 to 200 hours a year out of 8,760.”
Another factor is that some kilowatt-hours are lost as they travel from the point of generation to the customer, especially along lower-voltage AC distribution lines.
“Local poles and wires, that is, the distribution grid, is really not that efficient,” Hua said. “But you never would really know, because there’s not a ton of transparency around spending.”
HB 434 would prompt Appalachian Power and Dominion to examine and quantify these utilization gaps and inefficiencies as part of a regulatory proceeding this fall. The state’s utilities commission would then review and approve that data and direct the companies to increase grid utilization.
The measure requires regulators to evaluate key technologies — from energy storage to synchronous condensers, which reduce line loss — to improve use of the grid. It also opens the door for regulators to weigh grid utilization when considering utility proposals to instead expand their infrastructure.
In theory, these steps should lead to lower rates for customers. “Electricity rates are a math equation,” Hua said, where the top of the fraction is the cost of grid infrastructure, among other investments, and the bottom half is the number of kilowatt-hours sold.
Increasing grid utilization divides the fixed cost of the poles and wires — roughly the same numerator — by more electrons, a much higher denominator. “Therefore, you’re lowering the per-unit price of electricity,” Hua said, “and you’re lowering utility bills for all consumers.”
Exactly how significant this “denominator effect” will be isn’t clear yet – not without the data HB 434 requires utilities to compile. But experts say that growing the bottom of the fraction is a win for both customers and the investor-owned utilities, which make more money the more kilowatt-hours they sell.
Grid optimization also gives these utilities a pathway to making capital investments that earn them a guaranteed profit more quickly than building new power plants. That pathway runs through grid-scale batteries, according to LaFarge.
“Batteries have enormous value to the grid because they’re electron time machines. You can charge them up when there’s plenty of energy on the grid and no congestion or scarcity,” LaFarge said, and then discharge them when demand is at its height. “It creates more room on the grid using the grid you have. That unique nature of batteries is their superpower.”
While storage technology has been around for a decade, until very recently it was more expensive than building poles and wires and harder to justify to regulators.
“What has changed in the last 18 to 24 months is batteries have gotten staggeringly cheap,” LaFarge said, and utilities can invest in them and improve their bottom lines. “This is one of our most important messages around utilization: Utilities can earn more on capital assets [and] have higher revenue while delivering cheaper power to people.”
LaFarge’s company has worked with Dominion on other forms of distributed generation, including EV charging. For batteries, he said, “the Virginia utilization bill certainly creates an even bigger opportunity.”
To be sure, increased grid utilization is far from the only step Virginia lawmakers can take to tamp down skyrocketing electricity costs. Tying rates to performance metrics such as affordability and efficiency, increasing targets for batteries and other cheap sources of clean energy, and enabling more large-scale solar projects are among a host of legislative proposals that would also help lower prices — and that all could also become law this year.
It’s also true that the one-page HB 434 is more suggestion than mandate, and its speedy passage through the Virginia General Assembly — including by a nearly unanimous vote in the House of Delegates — raises questions about its impact. And the onus will be on the state’s utilities to measure, report, and improve grid utilization, albeit with prodding from regulators.
Still, Jigar Shah, a longtime energy entrepreneur and the director of the U.S. Department of Energy Loan Programs Office under former President Joe Biden, believes the legislation will put utilities on the hook, even as it gives them leeway to collect and analyze utilization data.
“What’s not acceptable is for folks to say, ‘It’s not possible and rates are going up 9% a year,” said Shah, who helped shape and advocate for the bill as an adviser to the nonprofit Deploy Action. He also pointed out Spanberger’s support and regulators’ engagement in the bill.
“It’s not something that we expect to be buried in a [utility] filing and it goes to die,” he said. “I think there’s actual interest in it from folks on the commission to continue moving it.”
For LaFarge, the broad consensus around the legislation is a reason for optimism, not skepticism.
“This is a bipartisan idea that really is having its moment, and we’re excited to see the successes of this bill replicated in dozens of states,” LaFarge said. “I think the regulated utility compact is about to surprise people with its ability to solve these problems to the benefit of the climate, the economy, and people who use energy in their daily lives.”
Disclosure: Charles Hua is a member of Canary Media’s board of directors. The board has no influence over Canary Media’s reporting.
Artificial intelligence’s bubblitude fizzes with circular transactions, risk concealment, and exotic real-estate debt finance. In a frenzy to build AI data centers, Big Tech recently borrowed and bonded more money in 11 weeks than in the previous three years combined. More than a thousand new data centers are under construction or planned nationwide. Though they don’t yet know how many of those facilities will eventually materialize, energy suppliers are using AI data centers’ ravenous appetite for electrons to justify vast new investments in gas and nuclear power plants and the revival of uneconomic coal plants, claiming that all are needed to win the AI arms race and keep the lights on.
This trillion-dollar surge is transforming not only equity and capital markets but also the future U.S. power mix, locking in decisions that will shape energy affordability for decades. Smarter, cheaper, cleaner, less-risky options for powering data centers exist — if decision-makers choose them.
To meet all the expected new electricity demand, the U.S. has rapidly proliferated its gas-fired capacity under development in 2025. For context, at the start of 2024, only 4 gigawatts of gas-fired power in the U.S. development pipeline were explicitly earmarked for powering data centers. Today, over 100 gigawatts are.
And developers are proposing to invest over $400 billion to build more than 250 gigawatts of new U.S. gas-fired power plants — nearly tripling the gas power pipeline in a year, mostly driven by speculative AI projects subsidized by 37 heavily lobbied state governments.
Some data centers are even being mandated as “critical defense facilities” to be built on federal land, alongside otherwise uneconomical nuclear plants exempted from strict Nuclear Regulatory Commission scrutiny, all at taxpayer expense. This is happening, ironically, in Texas — the nation’s free-enterprise leader in solar, wind, and batteries. These renewable resources totaled 97% of its 2025 capacity additions, while fossil fuels amounted to 3%, and nuclear 0%. But in the past two years, planned gas plants in Texas nearly quadrupled, to 80 gigawatts. Only China has more gas plants under development than Texas, and nearly half the Texas plants are meant to power data centers directly.
We’ve seen this movie before. A quarter century ago, the coal industry warned that the Internet would overwhelm the grid without massive new coal capacity. Demand proved to be over tenfold lower. The dot-com bubble burst in 2000, permanently vaporizing $120 billion of electricity investments and embalming another $80 billion in infrastructure built long before it was needed. Today’s AI mania rhymes: Gas and nuclear vendors that can’t beat energy efficiency and renewables in competitive markets are leveraging hype into mandates and subsidies to rescue their losers.
Yet capital markets increasingly fear that AI looks like a bubble set to pop. That’s because each new data center effectively bets against at least 10 plausible outcomes that make the investment unwise: Scaling large language models could fail to achieve superintelligence; customer revenue could disappoint; inaccuracy may persist; smaller and leaner models might keep outperforming giants; copyright infringements may have to be paid for; data centers may go on quadrupling their energy efficiency every year; and flexible interconnection might stretch existing grid assets to serve all new demand.
Each new power plant also bets against the ways that data centers may access cheaper electricity, such as adding pop-up microgrids, colocating renewables and storage at idle gas plants, and buying efficiency, flexible load, storage, and clean supply from other customers. Betting against any one of these realities is risky. Betting against all of them strains credulity.
Many utilities are already trimming projections toward reality. Regulators in data-center hot spots are scrambling to shield customers from accelerating and politically sensitive rate hikes — already up 16% in Illinois, 13% in Virginia, 12% in Ohio, and 6% nationwide. Meanwhile, actual data-center demand still barely shows up in national totals. U.S. weather-adjusted electricity use fell in 2023, then rose by 2% in 2024, about one-twentieth due to new data centers. Nearly all the growth comes instead from air conditioning, electrifying buildings and vehicles, and reshoring industry. These needs can all be more cheaply met by better efficiency, and by another vast and potent competitor to fossil fuels: renewables.
Globally, data centers — roughly one-ninth of which are devoted to AI — use about 1.5% of today’s electricity. The International Energy Agency forecasts they’ll grow in this decade while renewable supplies grow 11 times more. Thus, solar and wind power, now swiftly displacing costlier fossil-fueled and nuclear power, dwarf the AI boom. Speed to market is paramount for AI developers, so many smart tech companies choose renewables to get their data centers built and running quickly and cheaply.
However, other AI firms have rushed for gas power, and that stampede has doubled gas-plant costs and backlogged gas turbine deliveries to past 2030, to the point that two-thirds of gas-plant project proposals have no named turbine manufacturer. This jam has pushed about a fifth of projects to substitute off-grid gas power, often using adapted aircraft jet engines. These turbine generators are easily available but engineered to meet peak demand, so they’re inefficient, noisy, and dirty. Running them constantly to power data centers would quickly inflate electricity costs and magnify public health damages. U.S. data centers were already projected to cause more than $20 billion per year in asthma and cardiopulmonary disease costs by 2030. Communities will not welcome additional pollution, water stress, noise, and rate hikes.
Gas markets magnify the financial risks of turning to gas to power data centers. New gas wells decline faster than old ones, while falling oil prices can make new drilling and refracking unattractive. At the same time, exuberant exports of liquefied American gas (and gas pipelined to Mexico) are pushing gas toward both global glut and domestic scarcity. The analysts at BloombergNEF predict that new gas-fired AI power could tip the 2025–30 U.S. gas surplus into a deficit, making volatile gas prices for heating, industry, and utilities spike. Indeed, BloombergNEF says wholesale gas futures for 2028–30 are unsustainably priced below production cost. And whatever the gas price, new gas-fired power plants are likely to become underutilized, subsidized assets that burden electricity customers long after today’s AI ebullience fades. While many data centers will be built, many won’t, and many won’t actually run at full tilt for decades to come — stranding gas plants and pipelines built to power them.
Even as national policy reinforces a gas lock-in, power choices that can scale at AI speed already dominate actual markets. Renewables captured over 92% of the world’s new generating capacity in 2024 and (including storage) about 90% of U.S. additions in 2025, with 93% expected in 2026. They are far cheaper than gas power, keep getting cheaper, sell on constant-price contracts for decades, and finance like low-risk annuities. They’re virtually unlimited and deploy at industrial speed.
Last May, China added 1 gigawatt of solar and wind power roughly every six hours around the clock. Pakistan displaced 30% of its utility power with solar in four years. Vietnam added solar equivalent to half of its coal generation in two years. South Australia generates 75% of its annual electricity from renewables and will reach 100% by 2027, driving 37 firms to propose relocating there to secure stable, low-cost power. Global metals giants Rio Tinto and BHP are relying on “renewable baseload” power to smelt aluminum and mine copper. Apple’s data centers have run on fully renewable energy for more than a decade. Google just announced that on-site solar, wind, and battery power will get its new 850-megawatt Texas data center online in 18 months, not five-plus years.
Critics have long claimed that variable renewables are too unreliable: The wind doesn’t always blow, and the sun doesn’t always shine. But evidence shows that intermittency concerns are now generally unfounded. Ten proven carbon-free balancing methods already make high-renewable grids reliable and economic in many countries. One of those methods, batteries, costs 96% less today than it did in 2010. BloombergNEF finds that battery-firmed solar and wind deliver steady power more cheaply than any new fossil or nuclear plants, and many operating ones. That’s why three-fourths of India’s new firm capacity today is solar-plus-storage.
Renewables also offer essential speed. In Sparks, Nevada, the world’s largest solar-powered microgrid continuously powers modular data centers. Solar panels laid on desert ground feed hundreds of second-life electric-vehicle batteries joined to form a superbattery. It was all built in four months and delivers electricity that’s cheaper, quieter, and more reliable than grid power; uses virtually no water; emits nothing; and is even portable. This is what clean, scalable, market-speed power looks like. Gas isn’t it.
AI does have some valuable applications. No one yet knows, though, if its revenues can repay the immense and swiftly depreciating investments required. But while markets are answering that trillion-dollar question, the AI boom must not be allowed to undermine American energy affordability and security.
Utilities and regulators can protect existing customers with a simple safeguard, giving teeth to vague qualitative pledges: Sell power to new data centers only under “take or pay” contracts that repay the entire electricity investment regardless. Those agreements should be backed by robust bonds or insurance, priced by capital-market risk experts (not by developers), to ensure that if an AI venture collapses, losses fall on the developer, not on households and small businesses.
If markets, and not mandates, determine the outcome, the conclusion is already clear. Gas, coal, and nuclear are too slow, too costly, and too risky to anchor the next wave of U.S. power demand. The only technologies that scale quickly enough, cheaply enough, and reliably enough for AI already dominate global additions. Policy will now decide whether Americans will enable the new energy system or protect the old — and whether they’ll pay for stranded gas plants or profit from the cheapest and most secure electricity in history.
See more from Canary Media’s “Chart of the week” column.
President Donald Trump claimed in his Tuesday night State of the Union speech that Americans worry that “we are winning too much” under his administration. That assessment does not apply to everyone in the U.S., judging by recent public opinion polls, but it rings surprisingly true for the clean energy sector in 2026.
Each year around this time, the federal government releases its expectations for new power plant construction. The latest data drop shows clean energy is going to dominate this year, just as it has for many years running. Even as the Trump administration has employed novel and at times legally dubious means to block renewable energy growth, the power sector keeps choosing clean energy again and again — attracted by its low costs, speed to build, and climate and environmental benefits.
This year, solar will provide 51% of the new utility-scale electricity capacity slated to come online, batteries will deliver 28%, and wind will add 14%, according to the U.S. Energy Information Administration. Fossil gas, one of the polluting fuels most supported by the Trump administration, makes up only 7% of that new capacity. Coal, the other polluting fuel favored by the White House, does not appear in the ranks of power plants under construction.
This clean energy success is all the more notable because of the massive amount of total power plant capacity that developers are set to build in 2026: 86 gigawatts, more than the U.S. has ever added in a year. The U.S. constructed 33 GW less in 2025, which was the biggest yearly power plant build-out since 2002. Clean power plants are consuming nearly all of a vastly expanded pie, while gas gets a scant sliver.
Still, gas dominates the existing power plant fleet, producing about 40% of annual generation, compared with less than 10% percent from solar. But the renewable energy source’s odds of dethroning gas improve with each year that solar delivers such a lopsided share of new construction. In California, home to the world’s fourth-largest economy, ascendant solar generation is poised to imminently eclipse the gradually declining portion provided by gas.
The Trump administration’s anti-renewables machinations could slow this trend in coming years. Courts threw out an order to stop construction at five fully permitted offshore wind farms, but an effective blockade on new permits for projects touching federal lands could kill or delay installations that would otherwise get built in the late 2020s. Even so, solar developers hope they can keep the success going by serving the AI sector’s overwhelming demand for quick-turnaround power sources.
Whatever tumult comes after 2026, the U.S. will face the situation with tens of gigawatts of brand-new solar, wind, and batteries in its arsenal.
An energy-affordability bill approved yesterday by the Massachusetts House of Representatives could speed solar permitting, strengthen protections for many electricity consumers, and boost EV charging infrastructure. It could also pull the rug out from underneath the state’s nation-leading energy-efficiency programming.
The legislation, passed in a late-night session on Thursday, takes a wide-ranging approach to combating rising power bills in the state, which faces some of the highest rates in the U.S. What has drawn the most attention, however, is its proposal to cut $1 billion from the energy-efficiency program Mass Save through 2027 in an attempt to lower the fees customers pay to fund it.
Bill sponsor Rep. Mark Cusack, a Democrat, argues that any cuts would target administration and marketing expenses and that Massachusetts would still be spending more per capita on energy efficiency than any other state. Opponents of the measure, though, say it would undermine job growth and slow progress toward the state’s emissions-reduction goals, while doing little to lower electricity costs now or in the future.
“I have to assume it’s going to mean layoffs in the energy-efficiency industry, and it’s going to mean a whole lot fewer heat pumps,” said Larry Chretien, executive director of the Green Energy Consumers Alliance.
Massachusetts has been grappling with rising energy costs for years, but the issue has taken on increasing urgency in recent months. And even in the Democratic-dominated state, the conversation around this bill reflects debates that are happening throughout the region — and the country — about whether to compromise climate and affordability goals for the possibility of savings.
Last May, Democratic Gov. Maura Healey proposed a sprawling affordability package, which received a hearing in June and proceeded no further. In November, Cusack introduced legislation that included many of the measures from Healey’s bill, but also called for slashing the Mass Save budget by $330 million, reinstating incentives for high-efficiency gas heating systems, and making the state’s 2030 emissions-reduction goals nonbinding.
The reaction from consumer and climate advocates was immediate and fierce: The bill would eviscerate the state’s decarbonization progress and do little to help residents struggling with high bills, they said.
Despite these concerns, the Telecommunications, Utilities, and Energy Committee voted in favor of the bill, sending it to the House Ways and Means Committee for further revision. There, lawmakers removed many of the contested measures from Cusack’s original proposal but tripled the proposed Mass Save funding cut, an escalation that has rankled members of the renewable energy community.
“Legislators are feeling the pressure to deliver immediate savings and are cannibalizing programs that actually function to lower electricity costs over the medium to long term,” said Ben Underwood, co-CEO of Boston-based solar company Resonant Energy.
The bill now moves to the state Senate energy committee, whose vice chair Sen. Michael Barrett, a Democrat, has a track record of assertive climate and clean energy action.
Mass Save is run by the state’s major utilities according to a three-year plan approved by regulators. Its offerings include home energy assessments, low-cost insulation for income-eligible households, rebates on heat pumps and energy-efficient appliances, and no-interest loans for implementing these measures.
The proposed $1 billion cut represents about 22% of the program’s existing three-year, $4.5 billion budget, but the fallout would be more severe than those numbers suggest. The current budget period runs from 2025 through 2027; by the time a bill could be enacted, more than half of the planned programming would likely have been executed. The $1 billion would therefore come out of a much smaller pool of money, and the impact would likely go well beyond the administrative and marketing costs the bill prioritizes, opponents said.
“It would really, absolutely cripple the program,” said Kyle Murray, director of state program implementation at climate nonprofit Acadia Center.
Such a drastic reduction in funding would trade significant long-term financial benefits for short-term savings, he said. Mass Save spent almost $12.4 billion from the beginning of 2010 through the third quarter of 2025, and generated $42 billion in benefits for the state’s residents and businesses. The fees that fund the program make up roughly 7% to 8% of the per-kilowatt-hour charge on the average electricity bill, which would mean a household with a $200 monthly bill would save little if the fee were lowered.
“It seems like I am most likely going to save $12,” said Mary Wambui, a member of the council that drafts Mass Save’s three-year plan, upon analyzing the impact the legislation would likely have on her own monthly electricity costs. “You tell me why a bill should be called ‘energy affordability’ if it doesn’t do anything for my energy bill?”
The funding cut could also result in lost jobs if business slows down for Mass Save’s network of thousands of home energy assessors and heat pump installers.
Despite the alarm bells set off by the Mass Save portions of the legislation, other provisions are receiving more support. Solar, clean energy, and climate groups praised the bill’s passage.
The bill calls for strengthening restrictions on third-party power suppliers, which sell electricity directly to customers who don’t want to get their energy from traditional utilities. These companies routinely charge higher prices than default service, often targeting lower-income households, according to studies by the Massachusetts attorney general’s office. The legislation would allow municipalities to ban third-party suppliers from operating in their city or town, limit suppliers’ ability to offer variable rates, and increase the penalties for regulatory violations.
Solar power would also get a boost. The bill would require the state to establish an online permitting platform to speed up the process of municipal approvals for solar projects. It would also allow residents to install portable solar — do-it-yourself kits that send power into a home through standard outdoor outlets — and would double the limit for how much net-metered solar an individual municipality can own, from 10 megawatts to 20 megawatts.
Other bright spots include support for virtual power plants, geothermal networks, and EV charging infrastructure that lets battery-equipped vehicles both consume power and send it back to the grid. Still, advocates say they will now be focusing on defeating the Mass Save funding cuts as the bill moves to the state Senate for consideration.
“If the Senate can fix that, maybe 2026 won’t be so bad,” Chretien said.
This analysis and news roundup come from the Canary Media Weekly newsletter. Sign up to get it every Friday.
No matter how you feel about data centers, we all rely on them: for reading this email, for scrolling through TikTok when you should be asleep, for streaming last night’s “Traitors” finale, and so on. And as AI becomes more powerful and more widespread, tech companies are building more of these power-hungry facilities — though exactly how many, and how much energy they’ll need, is unclear.
That fuzzy future is what makes data centers so complicated. Utilities that are rushing to meet data centers’ massive projected demand run the risk of building too many power plants, locking in more greenhouse gas and health-harming emissions, and passing unnecessary costs on to households.
It’s a dilemma that lawmakers on both sides of the aisle are finally waking up to. In the early years of the data center boom, governors and the federal government created tax breaks and other incentives to secure a slice, betting that the facilities would create jobs. But just last week, Illinois Gov. JB Pritzker (D) announced a two-year pause on tax incentives for data centers in his state. Similar rollbacks have been proposed in Maryland, Michigan, Oklahoma, and Virginia, Stateline reports.
Pennsylvania Gov. Josh Shapiro (D) has meanwhile called for data centers to make sure their power demand isn’t saddling residents with unfair costs. It’s a message with bipartisan support: U.S. Sens. Josh Hawley (R-Mo.) and Richard Blumenthal (D-Conn.) introduced a long-shot bill earlier this month that would ensure each new data center has its own power supply that doesn’t connect to the grid that the public relies on.
The idea that data centers should pay their own way is gaining traction with the White House, too. In his State of the Union address on Tuesday, President Donald Trump said he will push tech companies to promise that their data center build-outs won’t leave Americans with higher power costs. This “ratepayer protection pledge” wouldn’t be binding, however.
It’s a conversation worth following as congressional primaries begin this month, including in the data center hotbeds of Illinois, North Carolina, and Texas. A handful of Democratic candidates are already looking to differentiate themselves from crowded primary fields by going hard on data centers’ energy impacts, E&E News reports. And we can expect that Pritzker, Shapiro, and other governors and senators will do the same as they gear up their reelection campaigns for November — and as they consider running for the White House in 2028.
Will these fossil-fuel plants ever shut down?
The Trump administration’s push to keep fossil-fueled power plants running past their prime is stretching into a new year.
Just this week, the Department of Energy ordered Pennsylvania’s Eddystone oil and gas plant to keep operating for another three months, stretching its life nearly a year past its planned retirement. It’s one of several fossil-fuel plants that were supposed to retire last year but are now racking up millions of dollars in costs for grid operators to contend with.
Those cost battles are coming to a head in the Midwest. Federal energy regulators already agreed to spread the cost of keeping a Michigan coal plant running across 11 states served by the Midcontinent Independent System Operator. And in Indiana, the owners of two coal-fired plants forced to stay open are currently looking for a similar arrangement.
The problem is only likely to grow this year as the Trump administration forces gigawatts’ worth of fossil-fuel generation to keep operating with no end in sight.
Supreme Court considers a major climate case — with a catch
The U.S. Supreme Court agreed this week to take up the fossil fuel industry’s attempt to shut down city and state climate lawsuits — but it could face a surprising obstacle.
The case centers on a challenge brought by the city and county of Boulder, Colorado, against two oil and gas companies. After the Colorado Supreme Court ruled in Boulder’s favor last year, the companies appealed to the U.S. Supreme Court. And now, the case could determine the fate of several dozen other local climate lawsuits.
But the EPA’s recent repeal of the endangerment finding could pose a problem for the fossil fuel companies it was intended to help. Because the rollback effectively erased federal climate and emissions regulations, legal experts tell E&E News, it could be harder for oil and gas companies to make their case against local protections.
Virtual popularity: Virtual power plants — which tie batteries, solar panels, and other resources into energy management systems — are gaining popularity across the U.S. as states look to curb rising power prices without the need for grid upgrades. (Canary Media)
Shifting gears: The U.S. EPA will“revamp” the Clean School Bus program and shift $2.3 billion in remaining funds away from electric buses and likely toward vehicles powered by natural gas, biofuel, and hydrogen. (Inside Climate News)
Solar finds a spark: A growing number of states are considering legislation to allow for “balcony solar” systems, which can plug in to conventional outlets and help users lower their utility bills. (Canary Media)
Escaping eternal limbo: The Interior Department is reviewing at least 20 commercial-scale projects that have been stuck in permitting since Trump took office, including the massive Esmeralda project in Nevada. (E&E News)
Resilient rebuilds: While Oregon loosened building codes for families rebuilding in the wake of devastating wildfires, state incentives have still encouraged some residents to opt for resilient, energy-efficient new homes. (Canary Media)
New federal funds: The DOE has announced a $26.5 billion loan, its largest ever, to help Southern Co.’s Georgia and Alabama subsidiaries build new gas plants and transmission lines and upgrade existing power plants. (Associated Press)
“Coal has become its curse”: A small Pennsylvania coal-mining town is on the verge of collapse under the pressure of noxious, smoldering underground fires; pollution; and economic challenges. (Morning Call)
Nuclear who? The Trump administration is considering awarding a $25 billion contract to little-known nuclear power company Entra1 Energy, which appears to have just a handful of employees, to build new energy infrastructure using money pledged by Japan to avoid tariffs. (Politico)
One of the world’s largest steelmakers has deployed a novel heat battery at its plant in India to curb emissions from its dirty, energy-intensive operations.
Tata Steel is using the 20-megawatt-hour thermal-storage system, developed by the German startup Kraftblock, at a massive steel mill in Jamshedpur, in the eastern state of Jharkhand. The technology captures waste heat that’s generated during an early stage of the steelmaking process, then repurposes that heat to replace fossil gas used within the plant.
On Friday, the companies announced the project for the first time and shared the initial results. Kraftblock has been operating the heat battery since last May as part of a one-year test run with Tata Steel.
Based on how well the system has performed so far, the cleantech firm expects its thermal-storage technology will reduce the site’s carbon dioxide emissions by 22,000 metric tons per year — about the same as taking 5,100 gas-fueled cars off the road — and will eliminate about 110 gigawatt-hours of fossil-gas use per year.
“It’s performing better than we calculated,” Martin Schichtel, Kraftblock’s CEO and co-founder, told Canary Media.
The project is likely the first of its kind within the steel industry, experts say. But manufacturers in other industrial sectors are increasingly testing out thermal-storage technology as they look for cleaner ways to produce the scorching heat they need to make ceramics, chemicals, dairy products, and processed food and drinks.
Some of these systems draw electricity from the grid to generate and store heat in specialized bricks, rocks, or salt. They then supply that heat to industrial furnaces and boilers whenever companies need it. Kraftblock, which launched in 2014, operates a system like this at a PepsiCo factory in the Netherlands, where heat batteries are used instead of fossil gas to deliver steam and hot oil for frying potato chips. The company has developed a “stonelike” storage material from byproducts such as steel slag and copper-mine waste, Schichtel said.
Kraftblock’s system in India charges up using the excess heat from industrial processes, not electricity. Schichtel said that hard-to-decarbonize sectors like steelmaking have a “huge” potential to harness more of their waste heat, which is typically just lost to the air.
At the Tata Steel site, two Kraftblock units are connected to the “sinter” plant by a maze of thick silver pipes. Sintering is a highly energy-intensive process in which iron ore, limestone, and other materials are heated together to make lumps that are fed into blast furnaces — the hulking coal-fueled facilities that produce iron, the main ingredient in steel.
Tata Steel primarily uses fossil gas to generate heat to make the sinter, and later runs the finished product through large circular equipment to cool it back down. Kraftblock’s technology gathers the thermal energy that the cooled-off sinter releases and stores it in the batteries — at up to 500 degrees Celsius (932 degrees Fahrenheit). Tata Steel can then tap those batteries to warm the water needed for the sintering process.
Kraftblock’s system “enables us to significantly reduce our fossil energy consumption and emissions while improving process efficiency,” Subodh Pandey, Tata Steel’s vice president of technology, R&D, new materials business, and graphene, said in a statement to Canary Media. “This project is a significant step towards a greener, more energy and cost-efficient steel industry.”
Kraftblock declined to say how much its 20-MWh system cost to build or operate. But Schichtel said the project was developed without any subsidies, a fact that reflects the growing regulatory pressure facing Indian steelmakers. India is set to launch a carbon-credit trading scheme this year, and the European Union recently enacted a carbon-border tariff on polluting imports, which applies to metal from India.
Such policies are “definitely supportive” of clean technologies like Kraftblock’s, Schichtel said.
Globally, steelmaking accounts for between 7% and 9% of human-caused greenhouse gas emissions. Most of that pollution comes from heating coal in blast furnaces — a chemical process that can’t be directly replaced with thermal-storage systems. Steelmakers are pursuing other low-carbon methods instead, including producing iron using green hydrogen or with novel electrochemical processes.
Tata Steel, for its part, recently announced plans to invest $1.2 billion in advanced technologies at its Jamshedpur plant that are designed to reduce coal use in the ironmaking process and will capture carbon emissions from the steel mill.
Still, heat batteries like Kraftblock’s could provide a key way for steelmakers to start cleaning up their existing facilities today, even as they work to solve the much harder, longer-term challenge of fully decarbonizing, said Kaitlyn Ramirez, a senior associate in the Climate-Aligned Industries Program at RMI, a clean energy think tank.
Curbing steelmakers’ energy use is especially crucial, given how much renewable power cleaner steel mills are expected to need for steps like producing green hydrogen and operating electricity-driven furnaces and reactors. “Every amount of energy that we can reduce or make more efficient … makes the ultimate transition to near-zero [steel] production easier and much more feasible in the near term,” Ramirez said.
Kraftblock is part of the climatetech accelerator Third Derivative, run by RMI. The startup joined last year’s “industrial innovation cohort,” along with other industrial-heat-focused companies such as Advanced Thermovoltaic Systems, HyperHeat, and Noc Energy.
Nick Yavorsky, a senior associate at RMI who works with Third Derivative cohorts, said his team thought that Kraftblock was “on a very successful commercial pathway.” The startup had already raised 20 million euros ($23.6 million) in Series B financing when it joined the accelerator, and it had already deployed its thermal-storage technology at the Netherlands PepsiCo plant and at a ceramic manufacturing facility in Germany.
The Tata Steel project is “kind of a beacon” for thermal-storage startups looking to break into the steel sector, Yavorsky said. He added that he sees significant potential for scaling Kraftblock’s technology. Beyond the carbon-intensive blast furnace, steelmaking involves over a dozen upstream and downstream processes that require lots of energy and generate plenty of heat.
Worldwide, steelmakers operate over 480 integrated iron- and steelmaking facilities, according to Global Energy Monitor. India’s steel sector is growing particularly fast, and much of that new capacity is still expected to rely heavily on coal, underscoring the need to slash steel-related emissions wherever possible.
Schichtel said that Kraftblock and Tata Steel could consider expanding the heat-battery project after the full year of operations. He noted that the startup’s technology can store and manage heat up to 1,300 degrees Celsius (2,372 degrees Fahrenheit) — much higher than the sinter plant requires — which enables its technology to harness waste heat from a wide range of industrial processes.
“Not all steel mills will convert to hydrogen [ironmaking] within the next five or 10 years, right?” he said. “So each step you can do to minimize emissions, to increase energy efficiency for existing systems, is highly value-added.”
A correction was made on March 2, 2026: This story originally said that Third Derivative was run by RMI and New Energy Nexus. While New Energy Nexus co-founded Third Derivative, it is now run solely by RMI.
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