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We’re tracking the seven fossil-fuel plants the Trump admin has required to operate past their retirement dates — and which facilities could be hit next.
It was shocking back in May 2025 when the Trump administration took the unprecedented step of forcing an old coal plant to keep running, mere days before the facility was slated to retire.
And then the orders just kept coming.
Here’s what you need to know about the plants forced to stay open so far.
J.H. Campbell in Michigan
This more than 60-year-old plant on the banks of Lake Michigan was the first to be hit with a stay-open order by Trump’s Department of Energy in May 2025, a week before the facility was slated to close.
Democratic state attorneys general from Michigan and the nearby states of Minnesota and Illinois, along with environmental groups, have filed legal challenges to try and block the J.H. Campbell order. Oral arguments took place before a federal appeals court in May 2026, and a ruling could occur as soon as August 2026.
Eddystone in Pennsylvania
The second stay-open order, also in May 2025, hit oil- and gas-fired units at Eddystone installed in the late 1960s. Plant owner Constellation Energy says the facility has operated infrequently since last year but has contributed to grid reliability, WEKU reported in July 2026.
Environmental groups have sued the DOE over its stay-open order. In Kentucky, a utility and the state’s Republican attorney general are taking federal energy regulators to court, arguing that customers in the state shouldn’t have to bear the cost of keeping Eddystone online.
R.M. Schahfer in Indiana
By the time the DOE ordered the roughly 50-year-old Schahfer plant to keep running, in December 2025, the facility was already half-broken. Filings from the plant’s owner, Northern Indiana Public Service Co., estimate that repairing the broken unit and continuing to operate the plant could cost more than $1 billion through 2027. The plant went offline for repairs in February 2026, and NIPSCO said in May that it likely wouldn’t run again until fall 2026. In other words, the plant could not help with grid reliability even if it were needed.
The Schahfer stay-open order was also a devastating turn for the neighbors of the plant who hoped to finally be free from the pollution it spews into the air. Environmental groups have filed a legal challenge to the DOE order, as have the Democratic state attorneys general of Minnesota and Illinois.
F.B. Culley in Indiana
CenterPoint Energy, the company that owns Culley Unit 2, has described it as its “smallest and most inefficient coal unit.” But that didn’t stop the Trump administration from ordering it to stay open in December 2025. In February, the company specifically asked the Trump administration not to renew its stay-open order for the plant, describing it as unreliable and unnecessary for grid reliability. The DOE reupped the order anyway.
Environmental groups have filed a legal challenge to the DOE order, as have the Democratic state attorneys general of Minnesota and Illinois.
Centralia in Washington state
The more than 50-year-old plant owned by TransAlta was slated for a retrofit that would turn it into a gas-burning facility before Trump’s stay-open order in December 2025. Although TransAlta says it’s still committed to that plan, it’s also seeking tens of millions of dollars in reimbursement for costs incurred to keep the coal plant online — a move that’s frustrating utilities in the region since the plant has sat idle in the months since the DOE’s order. Electric customers might be on the hook regardless.
Washington state’s Democratic attorney general and environmental groups have legally challenged the DOE’s Centralia orders. Washington’s Democratic governor also signed legislation that would impose hefty costs on TransAlta if Centralia began running again.
Craig in Colorado
Utilities in Colorado had been planning for about a decade to retire Craig Unit 1 at the end of 2025, but the Trump administration forced it to remain online. In February 2026, two cooperative utilities that co-own the plant filed a petition asking the DOE to reconsider its stay-open order, arguing that it will force their members to bear unnecessary costs. The agency has not relented.
Already, the plant’s owners have had to take on the costs of repairing a faulty valve that sent the plant offline in December 2025, and some estimates project that running the plant for a year beyond its retirement date could cost up to $150 million.
Environmental groups and Colorado’s Democratic attorney general have filed legal challenges to the DOE order.
Stanton in Florida
Unit 1 at the Stanton coal plant got its stay-open order in June 2026. The Environmental Defense Fund estimates that propping up the nearly 40-year-old facility could add an average of $21 to monthly electric bills if the costs are solely assigned to customers of the Orlando Utilities Commission, the municipal utility that owns the plant.
Are we missing any of the latest details on Trump’s coal stay-open orders? Let me know at kempe@canarymedia.com.
SB 905 would curb returns on wildfire costs, seek new financing, and explore performance metrics to curb sky-high electric rates. Can it overcome utility opposition?
California lawmakers are once again contending with how to curb the state’s high energy costs as they hurtle toward the end of this year’s legislative session on Aug. 31. So what’s on the table for utility rate reform in the final stretch?
Enter Senate Bill 905, a complicated package of proposals that are likely to face intense opposition from utilities, which tend to reflexively resist rules that could crimp their profits. But California voters are demanding reform, according to state Senator Josh Becker, the Democrat who wrote the bill.
Californians rank cost of living as a top concern, and most blame the state’s three big utilities for rising electricity rates that are now roughly twice the U.S. average. And when it comes to California’s climate strategy, “it’s going to be really hard to convince people to install heat pumps and switch to EVs, or get a factory to switch to electricity rather than natural gas, if the price of electricity is too high,” he said.
Becker was speaking at a July 14 webinar hosted by the University of California at Berkeley’s Center for Law, Energy, and Environment (CLEE) to promote its latest research on the causes of the state’s electricity cost crisis. As that report highlights, there are no easy fixes.
Climate change and wildfire risks are forcing Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric to invest more in their aging and strained power grids. The California Public Utilities Commission, which regulates those utilities, is loath to rein in spending that expands the grid, brings more clean energy online, and reduces the risk of wildfires.
But the sheer amount of spending planned by utilities threatens to overwhelm the ability of their customers to pay for it. PG&E is seeking state regulator permission to spend $73 billion through 2030, and Southern California Edison has told investors it plans to spend from $38 billion to $41 billion through 2030.
SB 905 seeks to tackle utility spending in three key ways:
“Lowering electricity rates is a hard problem with no silver bullet,” Becker said. “But if we get this right, we can start a virtuous cycle.”
California lawmakers have been trying for years to pass utility reforms. In 2024, most of their efforts failed. But last year, Senate Bill 254, also sponsored by Becker, managed to make it through the legislative gauntlet.
SB 905 represents an important, if somewhat incremental, next step on those efforts, said Matthew Freedman, senior staff attorney at The Utility Reform Network (TURN), one of the state’s most vocal utility ratepayer advocacy groups and a sponsor of the bill. Among the bill’s provisions, a “lower return on equity is a pretty big one,” he said.
Utilities earn guaranteed rates of profit on capital investments, which puts upward pressure on customer rates. Anything that can reduce that rate of “return on equity,” or ROE, could help limit those increases, he said. A number of states are targeting utilities’ ROE to combat rising rates — and utilities are, not surprisingly, fighting back against the idea.
In a nod to the challenging politics, SB 905 proposes assigning a lower ROE only to key categories of utility spending, Freedman said. The biggest category is the tens of billions of dollars utilities are investing in burying and hardening power lines to eliminate the risk of sparking wildfires. SB 905 would also limit ROE for utility capital costs in “balancing” and “memorandum” accounts over which regulators have waived their typical authority for a “reasonableness review” to examine and claw back spending, usually for costs that can’t be predicted in advance of ratemaking proceedings.
Both these types of spending help reduce risk for utilities, which can lower the cost of financing as they go out to Wall Street to raise investment and procure debt, Becker said during the July webinar. That means utilities get “other benefits besides the pure financial return” from those investments, he said — and that justifies reducing how much they get to charge customers to recover those costs.
SB 905 also seeks to curb costs by forcing utilities to borrow money themselves, or rely on state-issued loans, to pay for some of their costs, Freedman said.
The math is fairly simple, he said. Borrowing money to pay for costs via a process known as securitization allows utilities to reduce the amount of money going into the “rate base” of capital investments on which they earn a guaranteed return. Utilities must collect money from customers over time to pay back those loans, but up-front impacts on customer rates are lower.
Tapping into state-backed bonds for utility projects that benefit the state at large — say, building transmission lines to allow more clean energy to be constructed and connected to the grid — could reduce costs even further, since governments can borrow more cheaply than utilities.
Last year’s SB 254 required the state’s big three utilities to securitize the first $6 billion in their ongoing grid wildfire-safety investments and created a state “transmission accelerator” to provide public funding for new transmission projects.
SB 905 would “require the PUC and the utilities to continue evaluating ways like that to lower financing costs,” Becker said, with an end-of-2028 deadline to report to the legislature on findings and recommendations.
It will take time for savings from this shift to borrowing to show up, said Sam Uden, co-founder and managing director of Net-Zero California, a Sacramento-based environmental policy group. He cited the example of the transmission accelerator, whose initial funding awaits final state budget negotiations.
“Then the goal would be for the accelerator to fire up next year, and launch public financing,” he said. “This is a multiyear transition.”
Curbing the return on investment and requiring utilities to borrow more both target the “capex bias” of regulatory structures that reward utilities with guaranteed profits on the capital expenditures. But what if utilities could be financially rewarded more directly for doing a better job on the things their customers and regulators really care about?
For decades, utility regulators and lawmakers have attempted to structure performance-based regulations to accomplish this. Some noteworthy examples include a long-running implementation at Hawaiian Electric and an abortive effort from Connecticut’s former head utility regulator that led to a bitter fight with utilities and her eventual departure from the agency.
SB 905 would set a Jan. 1, 2028, deadline for the California Public Utilities Commission to launch an effort to establish clear performance metrics for tasks such as making the grid more reliable, reducing greenhouse gas emissions, and speeding up the process of connecting new customers and renewable sources. “This will make clear what our expectations are for good performance, and hold utilities accountable for delivering safe, reliable, clean, and affordable power,” Becker said.
To be clear, SB 905 doesn’t authorize the commission to offer any financial incentives for meeting or exceeding whatever metrics it comes up with, Freedman said — at least, not yet. “We’re worried about a performance-based regulatory approach that the utilities can game and earn excessive profits from,” he said, as happened with Illinois utility ComEd over the 2010s.
“Let’s see how it goes for a few years. If we like it, the legislature can change the law and attach some incentives around that,” he added.
One big performance metric that SB 905 would establish, and which Virginia and other states have already implemented, is “grid utilization,” or squeezing more of the power grids that utilities already have. That’s a good way to drive down utility costs, which are based on “dividing the total costs of running the grid by the total amount of energy delivered to customers,” Becker said.
“We need to control the numerator of that equation — the costs. But if we can increase the denominator of the energy sold, then rates will go down,” he said.
California has plenty of load growth coming, whether from data centers, EV charging, or heat pumps and air conditioners for homes and buildings, Becker noted. The right combination of cost controls along with that can “make EVs look cheaper to drive, and make heat pumps look more cost-effective versus gas furnaces,” he said.
Right now, SB 905 is in the state Assembly appropriations committee, where it could undergo a number of amendments that won’t become known to its author until it is released for further consideration via a process known as “suspense.” Similar last-minute amendments gutted key provisions from another of Becker’s bills last year — before it was vetoed by Gov. Gavin Newsom.
Meanwhile, a late-breaking push by Newsom to reform California’s wildfire liability system — one of the state’s key drivers of utility costs — is likely to add more pressure on lawmakers trying to negotiate on a plethora of energy and climate issues, ranging from what to do about data centers to how to manage budget pressures tied to the state’s carbon cap-and-invest program.
Will SB 905 make it into law? “You know, utilities are fighting it fiercely,” Becker said. “But as we learned from last year, big things come down to the final wire, and I hope we’re going to get it through.”
Power stations that recharge from the sun, a car, or a home outlet can keep appliances going in an outage. Some can even help lower electric bills.
When the power goes out, a home battery can keep you going.
Energy storage, often paired with rooftop solar, has taken off in the U.S. in recent years as households look for ways to lower their utility bills and stay comfy during grid blackouts. But professionally installed partial- and whole-home battery systems aren’t right for everyone: They’re not only hardwired into a home — a change renters don’t usually have the authority to make — but also pricey. You should expect to pay at least $15,000 for one of these setups.
Luckily, there’s another option: portable batteries that can recharge from a standard home or car outlet or from portable solar panels. Although typically much less powerful than their whole-home counterparts, such DIY systems are far cheaper — and don’t require an electrician to set up. The rapid proliferation of the tech, known as portable power stations or solar generators, is democratizing clean, gas-free backup power more than ever.
These plug-and-play batteries, which range from the size of a toaster to a carry-on suitcase, have ports where you can plug in a few devices and appliances. They retail for several hundred to a few thousand dollars, depending on their storage capacity, and are widely available online and at big-box stores like Best Buy, Costco, and Home Depot. Some products, via their apps, can even shave your electric bill by automatically banking grid electricity during off-peak hours when it’s cheap, so you can pull the stored power during high-demand periods when it’s more expensive.
The market for portable batteries “has seen so much growth,” said Brian Essenmacher, North America head of business development for EcoFlow, which has manufactured this type of equipment since 2017. “They’re clean, they’re safe, there’s no maintenance, and they’re emissions-free. They can really be used by anyone to power the critical devices in the home.”
Portable power stations are mid-sized in the backup-battery bestiary. With a storage capacity of about 500 watt-hours to 4,000 watt-hours, these products are larger than power banks (roughly 7.5 Wh to 75 Wh), which can recharge a phone or a laptop, but typically more diminutive than batteries paired with home solar, like the 13,500-Wh Tesla Powerwall 3. Blurring the lines, though, some power stations can be expanded with additional battery packs to grow into 60,000 Wh or larger behemoths.
The portable tech can power a wide array of devices you might need during an outage. At home, that includes phones, computers, refrigerators, window air conditioners, “micro” heat pumps, TVs, fish-tank aerators, CPAP machines, baby monitors, Wi-Fi routers, sump pumps, and power tools. With some creativity, it can even be used to top off an EV.
The tech also enables outdoor activities, like filming, DJing, movie-projecting, camera-charging, water-boiling, and grilling. In recent years, the systems have pulled off a quiet revolution among the van-life and RV communities, who are increasingly picking batteries over polluting gas generators.
Ellen Vig, a semiretired registered nurse whose home base is in Billerica, Massachusetts, loves to boondock her minivan-turned-camper at the beach. And she’s never without her portable power station to keep her in comfort while she’s off-grid.
“It’s so nice to have a refrigerator and be able to use fans and charge your phone,” said Vig, who goes by “Electric Ellen, The Power Lady!” on YouTube and travels to RV and van-life meetups around the country answering people’s questions about portable backup power. “I’m a glamper, not a camper.”
For short-term use, Wirecutter recommends the Jackery Explorer 300 (293 Wh) at $279; for maximum battery life, the EcoFlow Delta 2 Max (2,048 Wh) at $949; and for a system that could be expanded to whole-home backup, the EcoFlow Delta Pro Ultra (6,000 Wh) at $3,999.
These products can be a surprisingly good value on a per-energy-unit basis. A $15,000 Tesla Powerwall 3 is $1,111 per kWh. The EcoFlow Delta 2 Max is $463 per kWh — less than half the Tesla tech.
Which portable power station is right for you? The first step is figuring out what you want to back up and thus how many watt-hours you need. List the devices you plan to power and a few of their attributes: their average and maximum power draws (in watts, and often listed in a label on the product itself or searchable online) and how long you plan to run them on backup power (in hours). Vig put together a handy template worksheet to crunch your total demand. Just copy it to edit.
I tried it — and was flabbergasted at my home’s energy decadence. Backing up just the essentials — window heat pump, fridge, laptop, and Wi-Fi router — for a day would take a whopping 14,000 Wh. A system that big would bust my budget, so I’m thinking something smaller will have to do.
Here are some key features besides size to look for in portable batteries:
Some other things to consider include how many outlets (AC, DC, and USB) the system has, the maximum watts each outlet can handle, how loud its internal fans get, how weatherproof the system is, how fast it charges, and if the company uses proprietary cables for connecting to solar.
The backup tech is rapidly improving. “Power stations are getting lighter, smaller, and more powerful, and they’re charging faster,” Vig said. A 1,024-Wh system would have taken her six or seven hours to recharge in the past, she noted. Now, she has one that charges up in roughly an hour.
Companies are also rolling out sleek new form factors. In the last few months, Bluetti, Jackery, and Pila Energy began shipping briefcase-size systems that can sit on top of a fridge to conveniently provide the appliance with backup power.
More innovation is on the horizon to get daily use out of portable power stations. Most products available in the U.S. can’t deliver electricity into a building’s outlet; they can only draw power from it. But, as with plug-in solar, plug-in batteries that can push electricity into your home are already available in Europe and are starting to pop up here.
These devices can power appliances plugged into the wall, providing a seamless way to share stored energy across different rooms while taking advantage of favorable electricity rates. It’s important to note that this functionality won’t work during a blackout, though, to prevent any risk of shocking lineworkers; instead you’d need to manually plug appliances into the battery’s AC outlets to keep them going.
Eight states have now passed plug-in solar laws, which allow power to flow into a home outlet, opening the door to plug-in batteries, said Rachel Stotts, senior public relations manager at Jackery. Competitor EcoFlow has begun to sell its plug-in Stream Ultra power station in the U.S., but has so far limited shipping to Utah and Maryland, two of the first states to legalize balcony solar. As of Monday, the product was sold out.
Jackery, which sells these two-way batteries in Europe, plans to bring them to the U.S. market once it decides how to accommodate different state regulations, Stotts said.
The company doesn’t have a release date, she noted. But “we’re hurrying.”
New electric rates for heat pump owners helped more than 140,000 Massachusetts households save money on their heating bills this winter.
Massachusetts consumers with home heat pumps saved some $37 million on their power bills — an average of more than $250 per customer — for the period from November 1 to March 31, compared to what they would have paid without the new seasonal rates. The seasonal rates are in effect until the end of April.
The state Department of Public Utilities is mulling a proposal to make its winter heat pump rates even lower.
In at least two additional states, conversations are happening about the possibility of creating discounted rates for customers using the fossil-fuel-free technology. Rhode Island is actively considering heat pump rates, and a new report from climate think tank Switchbox outlines the policy’s potential in New York.
“This was a big deal, for Massachusetts to be the first state to implement these rates with all of the major investor-owned utilities,” said Amanda Sachs, state policy manager at electrification nonprofit Rewiring America. “It really helps our case for electrification being a key part of energy affordability.”
Massachusetts, Rhode Island, and New York all have ambitious climate targets, cold weather, and lots of drafty old homes that use fossil-fuel heating. Heat pumps, which create no carbon emissions other than those associated with the electricity used to run them, are vital to decarbonizing each state’s buildings.
All three already have financial incentives in place to help residents with the up-front cost of installing heat pumps. Worries about high electricity rates, however, have been a more stubborn barrier to adoption, particularly for homeowners heating with natural gas, which has long been a less-expensive option.
Heat pump rates attempt to eliminate that obstacle by discounting the price of electricity for all the power consumed by houses using the equipment.
For example, even without special rates, nearly 45% of Massachusetts households would have saved money by switching to a heat pump, according to an analysis released last year by Switchbox. That number jumps to 64% with the existing heat pump discount and could go up to almost 82% if the deeper proposed cuts are implemented. Recent surges in oil prices could boost savings for homeowners using heating oil.
The logic behind these discounts is that traditional electricity rates overcharge heat pump owners for their share of grid construction and upkeep.
The delivery portion of a residential electric bill pays for the poles and wires needed to carry power to customers. Most of this charge is paid volumetrically: The more electricity you use, the more you pay. So if a homeowner installs a heat pump, their power consumption, and thus their delivery charges, will go up significantly.
It might seem to make sense on the surface, but it’s actually quite unfair, said Juan-Pablo Velez, Switchbox’s executive director.
That’s because the grid is built to work at the moments when demand is highest — those hot summer afternoons when everyone turns on their air conditioning at the same time. During the winter, demand is lower, and there’s plenty of room on the system for electrons to flow to heat pumps without the need for infrastructure improvements. So, delivering power to a growing number of heat pumps doesn’t really cost the utilities more in grid maintenance or upgrades, but consumers are still paying a lot more.
In New York, for example, it costs utilities 2% more to deliver energy to heat pump users than to other homes, but heat pump households pay more than twice as much in delivery charges as their neighbors who warm with fossil fuels, according to the new Switchbox report.
“Heat pump customers using the system in the winter are not driving the same infrastructure costs as the summer peaks,” Sachs said. A heat pump rate “fixes that mismatch to make electrification more affordable.”
These rates are not a permanent fix. As heat pump adoption grows, the grid will eventually experience peak demand in the winter, rather than the summer, upending the logic that supports the discounts. For now, however, this approach makes sense financially and environmentally, proponents say.
Massachusetts was the first state to require all of its major electric utilities to provide seasonal heat pump rates, knocking from 4.3 cents to 7.5 cents per kilowatt-hour off the standard winter price; during the summer, rates are the same for those who own heat pumps and those who don’t. Customers who received heat pump incentives from Mass Save, the state energy efficiency program, were automatically enrolled.
The state’s Department of Energy Resources and climate advocates would like to see even more of a discount. The energy department has asked utility regulators to approve a seasonal rate that would save heat pump owners from 12 to 17 cents per kilowatt-hour. At that level, houses switching to heat pumps from other sources would save a median of $687 each winter, according to Switchbox’s 2025 analysis.
“The current rates are still overcollecting from heat pump customers,” Velez said. “They didn’t reduce the rate enough.”
The case is still pending before regulators, who have said they intend to decide the matter in time for any potential new rates to take effect for the 2026–2027 heating season.
The action on heat pump rates is at an earlier stage in New York. There are no proposals before regulators yet, but Switchbox is attempting to jump-start the conversation with its new report on the potential for the state. That analysis finds that 72% of current natural gas customers would save money by switching to a heat pump if discounted rates were adopted, up from 27% under current rates. The organization plans to file the report as part of New York’s “Grid of the Future” proceedings, in which utility regulators are considering policies to prepare the grid for growing demand.
Rhode Island could be following in the footsteps of its northern neighbors as soon as this year. A climate action plan released in December identifies “ambitious adoption of heat pumps” as a key strategy in reaching the state’s emissions targets, a goal that dovetails nicely with heat pump rates, said James Rhodes, clean buildings director for Conservation Law Foundation, an environmental advocacy organization.
“If that’s our strategy, the first thing you have to do is make that an affordable decision,” he said. “The cost to serve a heat pump customer should not be multiple times higher than the cost to serve a non–heat pump customer.”
Rhodes had been tracking the progress of Massachusetts’ rates and promoting the idea to Rhode Island energy officials and the state’s major utility, Rhode Island Energy, but getting little traction. So the foundation intervened in Rhode Island Energy’s ongoing rate case, and earlier this month filed a proposal that would reduce delivery rates for heat pump owners by 5.8 cents per kilowatt-hour, according to analysis by Switchbox. Customers without heat pumps would see a rate increase of 0.29 cents per kilowatt-hour — for an average of $1.57 a month — to ensure the change is revenue-neutral for the utility.
A decision should be made in the case by the end of August, Rhodes said.
“This seems like a slam dunk,” he said. “I like to think this is going to be an inflection point, and I hope it is for the positive.”
If the war in the Middle East has proved anything over the last month, it’s that fossil fuel prices are extraordinarily unstable. But global conflict isn’t the only catalyst that can send the cost of oil and natural gas reeling. Factors such as extreme weather, policy changes, and pipeline outages can also set off a price roller coaster.
In North Carolina, all this volatility is prompting calls for change. Advocates want the state to join the handful of others that require electric utilities to absorb a fraction of fossil fuel prices — rather than saddling customers with all of them, as the companies do now.
The point of the policy, called fuel-cost sharing, is twofold. It can bring utility bills down for average consumers, who are increasingly angry about ballooning expenses. And it can aid the clean energy transition: If the state’s predominant utility, Duke Energy, knows that its shareholders will take a hit when fuel prices rise, the company may scale back its dependence on polluting gas plants and instead rely more on emissions-free, fuel-free forms of energy, like wind, solar, and batteries.
The notion of fuel-cost sharing is still very much in its nascence here, where Duke wields incredible power over the Republican-controlled legislature, and neither lawmakers nor regulators have pushed the company to invest in cheap, clean energy.
But proponents of the idea say the conversation is still worth having.
“Fuel dependence creates vulnerability — whether it’s gasoline for your car or natural gas for your power plants,” said Josh Brooks, chief of policy strategy and innovation for the North Carolina Sustainable Energy Association. “Tying costs to volatile commodities means a lot of risk exposure for ratepayers. That’s an issue both regulators and policymakers should take up.”
North Carolina is far from unique. Most states with vertically integrated utilities allow them to pass 100% of fuel costs to their customers. Utility shareholders don’t earn a return on those outlays in the same way they profit from building new power plants, but they’re insulated from the wild price swings inherent in the global fossil fuel market. Consumers are not.
Ratepayers, for instance, bore the full brunt of spiking gas prices after Russia invaded Ukraine in 2022. Confusingly for customers, Duke doesn’t specify these fuel charges on their bills; instead, the charges are incorporated into a nondescript line item, leaving consumers to ferret out on their own what they’re paying for fossil fuels.
The lack of clarity around fuel costs adds to customers’ outrage about rising bills. One example of the widespread frustration: A Change.org petition calling for Duke to submit to an independent audit and refund its customers for any improper charges has drawn more than 73,000 signatures so far.
“Unexpected and unexplainable increases in Duke Energy bills have become a major concern for many families,” the petition begins. “When bills rise without reasonable justification or transparency, it impacts our ability to plan and manage our household finances effectively.”
The average household Duke bill has risen by nearly 45% since 2020, according to an analysis from the Energy and Policy Institute, because of a confluence of factors. The cost of natural gas is a major one.
Research from the Environmental Defense Fund shows that fuel costs accounted for 67% of rate increases from 2017 to 2024 in Duke’s central North Carolina territory, and for 46% of the hikes in the rest of the state. While fuel costs did dip last year, they’re still about double what they were in 2017.
“Fuel costs have stayed high since the 2021-22 price spike,” Will Scott, the environmental group’s North Carolina policy director, said in a written response to Canary Media. “At the same time, Duke has become more natural gas reliant, with even more new gas plants on the way.”
Indeed, with the state’s 2030 climate goal gone, and the Trump administration aggressively propping up coal and gas, Duke has every incentive to pursue a massive buildout of fossil fuel infrastructure: Shareholders will profit from the plants and suffer no adverse consequence if gas prices continue to rise.
As Jeremy Kalin, a fuel-cost sharing expert and clean energy finance lawyer, put it, “The utilities are the ones that have all the power, all the visibility, all the expertise — and none of the risk.”
Fuel-cost sharing would shift the balance. In a February report, clean energy think tank Rocky Mountain Institute evaluated one way that North Carolina could structure such a policy: Duke would tell regulators how much it expected to spend on fuel over the course of a year. If the utility went over that estimate, investors would cover 10% of the extra cost — up to a small cap. If fuel ended up costing less than expected, investors would get to pocket 10% of the savings.
The policy, said Oliver Tully, RMI’s carbon-free electricity manager and one of the report’s authors, would “reduce some of the risk exposure that customers have — and essentially give utilities some skin in the game.”
With the 10% sharing scenario in place from 2020 to 2024, RMI concluded, Duke’s roughly 3.8 million customers in North Carolina could have saved a total of $100 million in 2021, 2022, and 2023 — a small but meaningful fraction of the fuel cost increases that followed the pandemic and the invasion of Ukraine. Duke investors, meanwhile, would have gained an extra $9.9 million in 2020 and $1 million in 2024. The net benefit to customers over the study period: $89 million.
Tens of millions in consumer savings is meaningful in and of itself, Tully and other experts stress. But the policy also gives utilities an incentive to reduce their fuel expenses, both in the long term by building fewer gas plants and in the near term by relying less on coal and gas during periods of high demand.
“They have a lot more control, especially compared to ratepayers, over overall fuel costs,” Tully said. “They can decide how much gas-fired generation to build or control. They can choose to invest in resources that don’t have fuel costs, like renewables.”
Ideally, Tully and other experts say, the cost-sharing policy would create a win-win situation that aligns Duke’s incentives with its customers’. Both investors and customers pay more when fuel costs are high and save when fuel costs are low.
“The goal is to get shareholders and customers on the same rope,” Kalin said, “pulling in the same direction.”
Nine states have implemented some form of fuel-cost sharing, according to RMI. Five are in the Northwest, including ruby-red Idaho and Wyoming. Last year, lawmakers in Nevada authorized regulators to study the policy, and Virginia just enacted a law doing the same.
Despite its advantages for customers and even shareholders, the cost-sharing policy’s prospects in North Carolina are uncertain.
The North Carolina Sustainable Energy Association pushed for a study of fuel-cost sharing last year at the North Carolina Utilities Commission as part of its annual deliberation on the fuel charge itself. But regulators rejected the idea, saying they lacked the authority to order such an analysis — at least in the context of a fuel proceeding.
“The commission has historically had a pretty conservative view of its statutory authority,” the association’s Brooks said.
Still, his group plans to raise the issue as part of Duke’s active bid to regulators to increase residential rates by 18% over two years. Proponents will also look for ways to advance the policy during the state legislative session that begins next month, even while expecting that lawmakers will focus their time on other matters.
“That’s not going to stop folks from advocating for some kind of change,” Brooks said.
This article originally appeared on Inside Climate News, a nonprofit, nonpartisan news organization that covers climate, energy, and the environment. Sign up for their newsletter.
In Alabama, a yearslong battle over one of the nation’s highest backup fees for residential solar customers may have finally come to an end.
A federal judge ruled last week that Alabama Power can continue charging its small solar customers one of the highest standby charges in the nation, dismissing a lawsuit that argued the fee was illegal under the Public Utility Regulatory Policies Act.
“I am frustrated that Alabama Power solar customers like me have to pay an extra monthly fee in order to reduce our power bills,” Mark Johnston, one of the plaintiffs, said in a news release after the ruling.
Solar advocates in Alabama say the fee, which charges customers with an average residential solar array around $39 per month, significantly stifles the residential solar market in the state by nearly doubling the payback time for a solar installation.
Alabama ranks 51st in residential solar capacity among U.S. states plus Puerto Rico and the District of Columbia, trailing only North Dakota, according to the Solar Energy Industries Association, a solar industry trade group. Per capita, Alabama ranks last.
Alabama Power, which provides power to roughly two-thirds of the state, charges its customers that generate their own electricity a monthly fee of $5.41 per kilowatt of capacity installed.
The average size of a U.S. residential solar array in 2024 was 7.2 kilowatts, according to the Lawrence Berkeley National Laboratory. The fee would add $38.95 each month to the customer’s bill regardless of how much electricity the customer consumes or puts back on the grid.
Alabama Power says the fee is needed to cover costs of maintaining the grid when the solar panels aren’t producing, at night or in cloudy weather.
“Customers who rely on the grid must help pay for the grid,” the company said in an emailed statement. “We are pleased the court agreed with the Public Service Commission’s determination that customers who choose to use Alabama Power for backup service should pay their share of costs to maintain the grid.”
Johnston, an Episcopal priest and retired executive director of Camp McDowell, pays about $32 per month for his 6 kilowatt system.
“This charge discourages additional residential solar systems in the state, a source of clean, renewable power that decreases the use of fossil fuels,” Johnston said. “I want lower electricity bills and a better environment for my children and grandchildren.”
The Southern Environmental Law Center and Ragsdale LLC filed the lawsuit on behalf of customers paying the charge and environmental groups that argued the fee was unlawfully stifling the small-scale solar industry in Alabama.
The Alabama Public Service Commission and Alabama Power filed a motion to dismiss the challenge, granted Wednesday by Judge Annemarie Carney Axon, in the U.S. District Court for the Middle District of Alabama.
The SELC said it is examining the decision and its clients’ legal options.
“This is a disappointing day for Alabama Power customers who want to use solar energy to get relief from some of the highest electricity bills in the nation,” said Christina Tidwell, a senior attorney in SELC’s Alabama office, in a news release. “Not only are we missing out on the bill savings that could be realized through installing rooftop solar, but we’re also missing out on opportunities for job creation and economic development.”
Alabama Power has come under increased scrutiny for its high power bills in recent months.
An Inside Climate News investigation found that Alabama Power had the highest total residential power bills in the country in 2024, and the highest electricity rates in the Southeast.
Environmental advocates have continuously challenged Alabama Power’s capacity reservation charge since it was approved by the Public Service Commission in 2013. The decision was appealed to the Alabama PSC and then to the U.S. Federal Energy Regulatory Commission.
Though FERC did not agree to initiate an enforcement action regarding the fee when it examined the case in 2021, Chairman Richard Glick and Commissioner Allison Clements issued a concurrence to express “concern” that the fee may be in violation of federal utility law, and said the petitioners had “presented a strong case that the Alabama Commission failed to adhere to the regulations set forth in FERC Order No. 69.”
The commissioners were concerned about the way Alabama Power calculated the costs for backup power, saying company had not demonstrated that a solar customer’s profiles were different enough from a nonsolar customer to justify the charge, and the company’s methods had “combined apples and oranges” by relying on actual data and projections to determine the cost difference between solar and nonsolar customers.
The District Court judge ruled otherwise, dismissing the plaintiffs’ suit, saying “the plaintiffs have not presented any evidence from which a factfinder could conclude that Alabama Power violated [PURPA].”
The fee is not the only policy in Alabama that advocates say is holding back solar in the state. Alabama does not offer net metering, where solar customers are credited the same amount for electricity they put on the grid as the electricity they use.
Instead, customers who feed excess energy back onto the grid are only credited the amount of money it would cost Alabama Power to generate the same amount of electricity at one of its power plants, an amount much lower than retail rates.
“Alabama communities are dealing with harmful impacts of our state’s reliance on fossil fuels; meanwhile, Alabama Power and the PSC are chilling clean, bill-reducing solar power,” Jilisa Milton, executive director of the Greater-Birmingham Alliance to Stop Pollution (GASP), said in a news release. “Solar energy offers a unique opportunity for residents of Alabama to take control of their energy costs, reduce their carbon footprints, and contribute to a cleaner environment.”
Alabama Power’s solar fee has long stood out as one of, if not the, highest in the country for small-scale solar users.
Some utility regulators have rejected fees outright, while others have allowed such fees in much lower amounts or have limited fees to systems larger than a certain size.
Georgia Power, also owned by Alabama Power’s parent Southern Company, proposed a fee similar to Alabama’s in 2013. Georgia Power withdrew its proposed fee as opposition mounted in the Georgia Public Service Commission. Alabama’s Public Service Commission approved the fee.
In Virginia, solar customers only pay a standby charge if their array is larger than 15 kilowatts, and that limit is likely to increase soon.
Earlier this month, the Virginia General Assembly passed a bill to increase the threshold for projects that require customers to pay the standby charge to 20 kilowatts, meaning larger projects would be eligible for the standby charge exemptions. The bill is awaiting a signature from Democratic Gov. Abigail Spanberger.
That average standby charge for residential customers amounts to between $25 to $75 a month, but sometimes can be more than $100 a month, according to the Virginia League of Conservation Voters.
“Overall—this model creates a disincentive for Virginians to invest in larger systems that meet their full energy needs, which is how this bill can help,” said Lee Francis, chief program and communications officer of the Virginia League of Conservation Voters.
Alabama Power said its fee is intended to prevent other customers from bearing costs of infrastructure required to serve solar customers when the panels are not producing.
“Alabama Power supports customers who want to install solar or other onsite generation, and we do not charge customers for using rooftop solar,” the company said. “However, if those customers want to stay connected to Alabama Power’s grid to meet their electricity needs when their system cannot, they must pay their share of grid costs so other customers are not unfairly burdened.”
Inside Climate News Virginia reporter Charles Paullin contributed to this report.
The war in the Middle East has spurred the largest oil disruption in history. The Strait of Hormuz, a choke point for much of the world’s oil and gas supply, is functionally closed. Oil prices are hovering around $100 a barrel.
Many Americans are seeing the fallout in the form of higher prices at the gas pump. But in Puerto Rico, a part of the U.S. especially dependent on oil power plants, the conflict also likely means higher electric bills — a painful outcome on an island already beset by an expensive and unreliable grid.
“In the continental U.S., no one’s burning a significant quantity of oil to generate electricity,” said Cathy Kunkel, an energy consultant at the Institute for Energy Economics and Financial Analysis. But that’s not the case in Puerto Rico, where oil-fired plants make up about 60% of generating capacity. The island “just has a lot of old oil-fired power plants that were constructed in the ’60s and ’70s, when oil was obviously a lot cheaper.”
Puerto Rico does not produce oil itself, and so it must ship in every last drop it burns. Given that the U.S. territory’s oil supply contracts are tied to global price benchmarks, Kunkel said that she “can’t imagine a scenario” in which power costs won’t rise in response to the historic oil shock.
“[Puerto Ricans] will see an increase in electricity bills,” said Rodrigo Rosas, a senior research analyst at Wood Mackenzie. The scale and duration of the increase, he said, depend on a “million-dollar question”: How long will the oil market disruption last?
The looming price hikes come amid heated conversation about the future of Puerto Rico’s energy system — and whether it should hitch itself further to imported fossil fuels or focus on transitioning to clean energy.
Puerto Rico relies on fossil fuels for more than 90% of its electricity, with liquefied natural gas as its next-biggest source after oil. For now, the territory is relatively protected from the considerable shocks that the war has sent rippling through the global LNG market, analysts told Canary Media.
That’s because it gets most of its LNG from Trinidad and Tobago and from a facility in Mexico that is fed by U.S. pipeline imports. Those sources both “operate in supply systems that are largely insulated from disruptions linked to the Middle East conflict,” Rosas said.
Puerto Ricans will soon have more specifics on what the war means for their bills in the near term. Every three months, the island’s electricity regulator adjusts prices for fuel costs, a process that is set to happen next at the end of March. That means higher rates would kick in starting in April.
Even a marginal rise in power bills could mean hardship in Puerto Rico, where the median household income is around $26,000 a year, less than one-third of the U.S. median. Already, the island faces some of the highest electricity prices in the U.S.
Faraway energy shocks have caused prices to climb in Puerto Rico before. After Russia’s 2022 invasion of Ukraine sent oil and gas markets reeling, the fuel-cost portion of Puerto Ricans’ electric rates jumped from 15 cents per kilowatt-hour at the beginning of that year to 22 cents per kilowatt-hour in the summer, according to Kunkel. That price jump, she noted, was driven by higher prices for both LNG and oil.
To some, the latest threat of price hikes underscores once again the need to embrace solar, wind, and batteries — all of which produce power unperturbed by global conflict.
Utility-scale renewables provide very little of Puerto Rico’s electricity today. But devastating hurricanes and frequent outages have motivated many Puerto Ricans to install rooftop solar and home batteries in recent years.
In 2023, the Biden administration launched a $1 billion program to boost the buildout of these distributed systems. The Trump administration, however, has clawed back or redirected much of that federal funding. Meanwhile, Jenniffer González-Colón, the Trump-allied governor of Puerto Rico elected in 2024, has supported plans to boost the island’s gas generation and weakened a 2019 law that commits it to ditching fossil fuels by 2050.
In late 2024, the Puerto Rican government approved the construction of a new gas plant on the island, and it’s currently looking to procure another 3 gigawatts of “firm” capacity, which likely means gas plants. Contracts for temporary generators run by LNG and diesel are also advancing, Kunkel said.
“I think the government’s making a huge mistake doubling down on natural gas as opposed to investing more in renewables,” said Sergio Marxuach, policy director at the Center for a New Economy, a Puerto Rican think tank.
In light of that, the island should work “as hard as possible” to insulate its economy from fossil fuels, said Tyson Slocum, director of the energy program at Public Citizen, a nonprofit consumer advocacy group.
“I don’t care what kind of supply agreement you negotiate. I don’t care if you’re getting your LNG from the United States,” Slocum said. “You are going to continue to be vulnerable to shortages and price shocks because of the inherent features of global fossil-fuel supply chains.”
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.”
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.
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.
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