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America’s data centers used a whopping 176 terawatt-hours of electricity in 2023, representing 4.4% of the nation’s total power consumption. Those numbers are only going up as AI tools gain popularity, pushing computing loads higher. By 2028, data centers could gobble as much as 580 TWh of power, or 12% of the U.S.’s total electricity consumption that year, Lawrence Berkeley National Laboratory has projected.
The surge seriously complicates goals set by hyperscalers to slash planet-warming pollution — tensions that Canary Media discussed with Google and Microsoft during last week’s SOSV Climate Tech Summit.
Utilities from Virginia to Nevada are planning to build large numbers of gas-fired power plants and to extend the life of aging coal plants to satiate the tech industry’s rising demand — moves that could spike both utility customers’ bills and carbon emissions. Data centers themselves typically rely on diesel-burning backup generators to ensure our increasingly digitized world runs without interruption.
On the panel, I spoke with Lucia Tian, Google’s head of advanced energy technologies, and Sean James, Microsoft’s senior director of energy and data-center research.
Tian helps lead Google’s efforts to commercialize cutting-edge “clean, firm” technologies that could supply around-the-clock power to data centers. Google was among the earliest backers of Fervo Energy, a startup that’s operating and building next-generation geothermal plants in Nevada and Utah. The search giant has also signed a unique deal with Kairos Power to potentially develop a fleet of small modular nuclear reactors.
Microsoft, meanwhile, has inked a long-term power purchase agreement with Constellation Energy to support the company’s $1.6 billion plan to reopen its shuttered Three Mile Island Unit 1 nuclear reactor in Pennsylvania. James said that, inside its own fenceline, Microsoft is developing cleaner alternatives to diesel generators, such as hydrogen fuel cells and advanced batteries. The tech giant is also improving the design of server racks and other hardware to improve energy efficiency and reduce the need for new power capacity.
Tian and James emphasized the potential for data centers to operate more flexibly — limiting the strain on the broader grid and curbing utility costs. Google, for example, partnered with Omaha Public Power District in Nebraska last year to reduce its machine-learning load during severe weather events. More recently, the tech company signed demand-response agreements with the utilities Tennessee Valley Authority and Indiana Michigan Power.
The two panelists also shared their hopes that long-duration energy storage will eventually be able to commercialize and scale, bottling up enough power from wind and solar farms to provide days’ worth of backup for data centers. Today’s lithium-ion batteries typically only last a few hours, though startups are making progress on medium-term systems that can provide eight to 24 hours’ worth of power.
Companies like Form Energy are trying to push the envelope even further. Canary Media’s Julian Spector spoke with Form’s CEO Mateo Jaramillo about the firm’s 100-hour, iron-air battery technology at last week’s SOSV Climate Tech Summit. You can watch the conversation here.
A correction was made on Nov. 10, 2025: This story originally incorrectly identified an image of the Blue Mountain power plant as an image of Fervo Energy’s enhanced geothermal pilot in Nevada. Fervo’s project sends power to Blue Mountain.
Many households in rugged and rural southwest Virginia are already struggling to make ends meet. But they pay some of the highest electric rates in the nation, with prices that have risen at more than three times the pace of inflation over the last decade and a half.
Last week, residents of the Appalachian region voted to do something about it, joining Americans around the country in electing candidates who made affordability and spiking electricity bills central to their campaigns.
To wit: Voters in Montgomery and Roanoke counties elected Lily Franklin, a Democrat and former schoolteacher from Blacksburg, as their representative to the state House of Delegates. With 51% of the vote, she beat out a Republican incumbent in a district that voted for President Donald Trump three times in a row.
“It is a huge deal that we won this,” she told Canary Media.
The price of electricity wasn’t the only economic issue on voters’ minds as they cast their ballots across Virginia, giving Democrats the governor’s office, a larger majority in the House of Delegates, and a governing trifecta in Richmond. But Franklin said the topic came up again and again in her district, home to Virginia Tech as well as large swaths of mountain countryside.
“I talked to thousands of people across the district, and rising energy bills was a top concern,” she said. “I would hear it time after time — people were like, ‘My bill is almost three times what it was last year, and I haven’t changed anything.’”
Franklin is determined to tackle the problem when she’s sworn in on Jan. 14. “I’m not fixing inflation as a state legislator,” she said, “but I can work on energy in Virginia and bring down people’s bills.”
Of course, that’s easier said than done. But Clean Virginia, a Charlottesville-based nonprofit with a research division and a campaign arm that endorsed Franklin and numerous other candidates, just issued a report that could serve as a guide. The study homes in on Appalachian Power Co., or APCo, the investor-owned utility that serves all but a few patches of southwest Virginia.
“The last General Assembly session on the energy front was really dominated by intensive focus on the cost crisis in APCo territory,” said Brennan Gilmore, executive director of Clean Virginia.
That effort culminated in legislation heavily influenced by the utility that temporarily scaled back some fuel costs for customers, he said. “But it was not a holistic look at what the actual drivers of the crisis were, [or] a holistic look at how to resolve those crises.”
So, Gilmore’s staff spent months digging into regulatory filings in both Virginia and West Virginia, where APCo is headquartered. What they found is that base rates aren’t the main problem. Instead, add-on fees known as riders are the real culprits — and they typically receive far less regulatory scrutiny.
Riders, especially to fund grid upgrades, are hardly confined to APCo territory, rising in multiple jurisdictions nationwide and even sparking a popular internet meme that cheekily sums up the charges: “Distribution fee. Processing fee. … Transmission fee. Fee fee. Fee fi fo fum fee. Might as well fee. … Another dollar won’t hurt fee.”
In deep-red Patrick County, south of Franklin’s district on the border of Virginia and North Carolina, the internet hive mind mostly blames the monopoly-utility model for these costs, with scores of commenters on a local Facebook page bemoaning bills that doubled and even tripled in the span of a month.
The Clean Virginia report authors tend to agree, saying the rising bills overall are propelled by a regulatory system that “incentivizes utility overspending, inflates utility profits, and puts disproportionate costs on residential customers.” But the study also drills down on specifics.
The researchers note that Virginia’s 2020 Clean Economy Act, which requires APCo to sell 100% renewable energy by midcentury, is causing some of these riders. But they’re relatively paltry: Solar and wind generation to comply with the law makes up less than 1% of households’ monthly bills today, the report found, and is expected to comprise just 3% of monthly costs next year.
Riders for fuel costs and for high-voltage, long-distance electrical wires, by contrast, make up nearly half of the average household bill in southwest Virginia. Fuel costs more than tripled between 2007 and 2024. Transmission fees rose fivefold from 2009, when regulators first allowed them as a separate line item.
Fuel costs are closely tied to national markets for coal and gas, which make up over 80% of APCo’s power-generating capacity. Coal prices more than doubled in 2021 alone, the report says. Likewise, natural-gas prices jumped 540% between 2020 and 2022. Since APCo customers pay 100% of fuel costs, they bear the full brunt of these increases, while shareholders bear none, Clean Virginia notes.
“If you’re using generation technology that requires a lot of fuel, customers are going to pay more than if you use a renewable source with no fuel,” Gilmore said. “Add the volatility and the spike in natural-gas prices because of global and other economic issues, then you see a direct correlation between increased bills and fossil-fuel prices.”
But fuel fees appear to be rising for other reasons, too, the study says. The charges include power purchases from other utilities, and last year, the report notes, the Virginia attorney general found that APCo was buying coal power at above-market rates from an affiliate company, Ohio Valley Electric Corp.
“Legislators should urge [regulators] to order refunds if APCo’s interaffiliate power purchases exceed market benchmarks,” the report suggests.
APCo may also be using more coal power than is cost-effective.
Across the country, plant operators have scaled back use of coal-fired units not just because the fuel itself is expensive, but because the aging plants cost a lot to operate and maintain. Last year, the average run time for U.S. coal plants was a little over 40%. But regulators in West Virginia — where APCo operates two coal plants — have ordered the utility to run the facilities at least 69% of the time, the report says, citing testimony from a recent rate case.
Passthrough of volatile fuel costs is a common problem for utility customers, Gilmore said. “But there are some specific APCo elements of this,” he said, “including uneconomic dispatch of their coal plants, and a sort of self-dealing with some of the APCo affiliate-owned coal plants.”
Perhaps the biggest challenge is the utility’s ballooning transmission fees. One problem, according to the study, is that the cost of building and maintaining these high-voltage electric lines in the area’s hilly terrain is spread among relatively few customers. The much larger Dominion Energy, for instance, charges less than half as much in transmission costs per household as does APCo.
Data centers could well be a factor, too. Though virtually none are in southwest Virginia, hubs in Ohio, northern Virginia, and elsewhere are crowding the grid run by the regional transmission organization PJM Interconnection. PJM allocates the resulting costs for upfitting lines across its member utilities, without factoring in where these large electric loads are located.
For its part, APCo said in an emailed statement that “investing in and maintaining [our] generation, transmission and distribution network is essential for minimizing and shortening outages, accommodating growing energy demands and integrating new energy sources.”
Like utilities nationwide, the statement continued, APCo faces high interest rates and inflation, driving up a number of the expenses associated with generating and delivering power, including “higher material and labor costs; … cost recovery for major storms; fuel-related costs not yet recovered through the fuel factor, and cost recovery for investments made in generating plants and distribution infrastructure.”
The company also touted its energy-efficiency programs and noted that a $10 decrease in fuel costs took effect Nov. 1.
The price cut grew out of the law Gilmore said inspired his group’s study, which notes, “given that methane gas prices are projected to double between 2024 and 2026, fuel costs are likely to increase again in the near future.”
Incoming Del. Franklin called the reduction woefully insufficient.
“It’s not a whole lot of relief when your wages haven’t gone up any, your groceries are still more expensive, and your rent’s really high — or your property taxes have gone up,” she said. “We have to have a more substantial plan to bring down rates.”
The recommendations in the plan by Clean Virginia, such as requiring utilities to pick up a share of fuel costs and reducing reliance on riders, echo a recent report that grew out of a bipartisan resolution from the 2024 General Assembly.
But Franklin believes neither party is fully united on how to lower prices.
“There are folks that think if we have an all-of-the-above approach — that is how we bring down costs,” she said. “Then you’ve got some people on both sides that think nuclear is the direction.”
Neither of those are quick fixes, Franklin said, with lead times of five to seven years for new gas plants and even longer timelines for nuclear.
Her own aspirations for office range from sweeping reforms, like prohibiting APCo and Dominion from making campaign contributions, to incremental steps like shifting some of the rate burden from residential customers to industrial ones and providing incentives for rooftop solar.
“And at the end of the day, we’ve got to help the people,” she said, “and that’s what I’m going to remind members of my party.”
Electricity is getting more expensive — and Americans are getting worried.
Just look at last week’s election, when Democratic candidates who put a spotlight on energy affordability won key races in Virginia, New Jersey, and Georgia.
Fortunately, state and local lawmakers, including those just elected, have the authority to do something about this increasingly urgent problem. Here are three immediate steps they can take to save consumers money on their power bills.
State regulators can lower skyrocketing electric bills practically overnight by reducing utility profit rates. Investor-owned utilities earn a guaranteed profit on every dollar they spend. State public utilities commissions set these profit rates, and right now they’re way higher than they used to be.
Former utility executive Mark Ellis estimates the average American household overpays utilities by $300 per year, because the companies extract 3 to 7 cents more on every dollar of investment than they ought to.
Utilities consistently try to scare regulators off from lowering their excessive profits, claiming service quality will decrease or costs will actually rise — but there’s little evidence that doing so will negatively impact consumers.
We know that utilities can maintain high-quality service with lower profit rates because they’ve done it before. Recent research by RMI shows that utilities still received enough capital to build new infrastructure when profits were more reasonable in the late 1970s and early 1980s. Returning profit rates to those lower levels can also more than offset any increases in borrowing costs that might result from impacts to credit ratings.
Lawmakers can save consumers billions by adjusting incentives to pay utilities for performance rather than construction.
Under current rules, utilities profit significantly more from building new infrastructure than from investing in energy efficiency or cheaper upgrades to existing poles and wires. Most analyses of high electricity prices find that utility spending on transmission and distribution infrastructure is a main or major culprit.
The more utilities build, the more they profit, so they build a lot. Every grid problem looks like a nail to a utility that can use a gold-plated hammer to “solve” it — and consumers get bent out of shape as a result.
Customers in New York saved big when, in 2013, the state directed utility Con Edison to prioritize reducing energy demand via efficiency initiatives and solar panel installations. The investment successfully put off a $1 billion substation upgrade, saving New Yorkers $500 million in profits not paid to utility shareholders on top of $800 million in avoided hardware upgrades.
We could significantly reduce electricity use with energy-efficiency investments that routinely cost less than the fossil-fuel power generation favored by most utilities.
Instead, utility grid spending has exploded in recent years, outpacing inflation and electricity sales combined, according to the Energy Information Administration. And for each dollar of capital utilities invest in infrastructure, they’ll extract as much as 50 cents back in profits from customers over the life of the pole, transformer, or equipment.
A few states have comprehensive programs requiring utilities to prioritize cost-effectiveness rather than construction, but only Hawaii has discarded the conventional wisdom connecting utility profits to spending. State legislators can act now to align utility profit motives with performance, or at least efficient investment, and lower electricity bills in the process.
Local solar and batteries make electricity right where people use it, and more of each saves everyone money. Models suggest that dramatically scaling up energy resources like rooftop solar and batteries, and coordinating them with tools like smart thermostats, could cut future grid costs by half a trillion dollars.
But state and local laws, and utilities’ own policies around crucial processes like connecting to the grid, are mostly written to block and slow down small-scale clean energy.
It’s up to lawmakers to enact policies that remove those barriers by, for example, simplifying and automating permitting and zoning requirements, allowing non-utility ownership of solar projects, and fairly compensating solar owners through net metering. They’ll have to overcome vehement opposition from utilities, which see these kinds of policies as endangering their profits and allocate their lobbying dollars accordingly.
Electricity prices are rising at more than twice the rate of inflation. The Trump administration’s obstruction of clean energy and commitment to fossil fuels, particularly coal, are expected to make bills climb even further. Data-center development won’t help either. Most Americans feel this trend happening, and they are concerned.
It’s time to get a handle on the problem.
We’re all tired of paying more for electricity. We can pay less if state legislators and utility regulators seize the moment and act in the interest of consumers — rather than the shareholders of utility companies.
For decades, Puerto Ricans have struggled with a dysfunctional energy system. Now residents are grappling with two very different plans for how to fix it.
President Joe Biden’s administration invested heavily in distributed generation: rooftop solar and battery arrays on homes and businesses across Puerto Rico. But President Donald Trump has rolled back those commitments, redirecting funds toward hardening the grid and shoring up centralized — mostly fossil-fueled — power production.
Energy experts and community leaders say that continued reliance on fossil-fuel power plants is harmful and that sending electricity on transmission lines across rugged mountains plagued by hurricanes is impractical. Distributed generation, they argue, is the best way to supply Puerto Ricans with reliable, affordable power that can withstand natural disasters.
A federal judge’s Oct. 2 ruling on hurricane recovery funds offers a measure of hope to those advocating for this latter vision in the archipelago, which includes the main island and two smaller inhabited islands: Vieques and Culebra.
In September 2017, Hurricanes Irma and Maria battered Puerto Rico in quick succession, devastating homes and infrastructure and causing the lengthiest blackout in U.S. history, leaving some households without power for over a year. The Federal Emergency Management Agency is tasked with rebuilding the island’s energy infrastructure, which still has frequent outages. In 2020, the first Trump administration awarded $9.6 billion for this purpose, and other federal grants bring the pot of FEMA recovery funds for the energy system to over $12 billion.
In its 2020 grid-rebuilding study, FEMA proposed to fix and harden the existing grid and repair fossil-fuel plants. The agency made only cursory mention of distributed solar as supplemental power at critical facilities.
Community groups argued in official comments that instead of rebuilding a grid that has proved vulnerable to disaster, the agency should use federal funds for distributed solar paired with batteries. That would give homes, businesses, hospitals, and schools dependable power even when the grid goes down. FEMA did not incorporate that feedback into its final proposal in 2021, so in April 2023 the community groups, plus the national conservation organization Center for Biological Diversity, filed a lawsuit alleging that FEMA had violated the law by failing to study the environmental impacts of its plan or to consider other alternatives.
Federal Judge Jay A. García-Gregory ruled in the plaintiffs’ favor this October, sending FEMA back to the drawing board to fully study the impacts of various grid-overhaul alternatives, including one based on distributed solar.
“This is a pretty good outcome, an order from a federal district judge requiring FEMA to consider distributed renewable energy for all of this historic amount of funding,” said Ruth Santiago, an environmental attorney who grew up and lives in Salinas, a coastal fishing town located near an oil-fired and a coal-burning power plant.
Under the National Environmental Policy Act (NEPA), before undertaking any project that could significantly affect the “human environment,” a federal agency must release an environmental impact statement after studying the direct and indirect effects the project would have, as well as its cumulative effects with other existing or planned developments. The agency also must take a “hard look” at alternative ways to achieve the same goals.
FEMA argued that its grid-rebuilding plans would not have a significant impact, therefore an in-depth study wasn’t required.
But in their lawsuit, the community groups argued that the impact of FEMA’s rebuilding plans would indeed be massive, and that the agency failed “to engage in meaningful analysis of the environmental effects” of its rebuilding plans.
The judge agreed and ordered FEMA to study the impacts of its plans as well as the alternatives the community groups had proposed: rooftop solar, microgrids that can be disconnected from the main grid in case of a larger outage, and incentives for energy efficiency and power use at times of lower demand.
It’s a measured victory though: FEMA can appeal the decision, take months or years to do the study, and even ignore its own environmental impact statement, as the agency isn’t required to take any action based on its findings.
“If they do an environmental impact statement, it doesn’t mean they will adopt distributed renewable energy options,” said Alfredo Vivioni, a member of the board of directors of the community organization Frente Unido Pro-Defensa del Valle de Lajas (United Front for the Defense of the Lajas Valley), one of the plaintiffs in the lawsuit. “But at least it requires them to make a deeper evaluation of the variables.”
Meanwhile, Trump has threatened to eliminate FEMA altogether, and he has long been skeptical of efforts to mitigate and prepare for climate change.
“When you have a president that says climate change is a hoax, this is going to be interesting,” Vivioni said. “It could also be sad. But you learn to fight and keep on going. You build stamina for this.”
Rebuilding Puerto Rico’s electricity system is a challenge with very high stakes.
More than 4,000 Puerto Ricans died as a result of Hurricane Maria. Lack of electricity was a contributing factor, since residents could not refrigerate medicine or run medical equipment, and ailing people sweltered in high heat and humidity without air conditioning. The Centro de Periodismo Investigativo (Center for Investigative Journalism) in Puerto Rico told the stories of 166 people who died specifically from a lack of electricity.
Advocates for distributed power warn that more fatalities are likely if residents aren’t equipped with solar and batteries to survive future natural disasters. Meanwhile, residents — particularly those on the south coast of the main island — suffer health effects from fossil-fuel generation, and the continued reliance on fossil fuels will contribute to the very climate change–related events that damage the grid and endanger electricity supply, as the community groups pointed out in their lawsuit.
Perpetuating the existing energy system would be an environmental injustice, they argue, since the coal and oil plants on the south coast are located amid some of the island’s poorest communities.
They point to studies showing it is possible to power Puerto Rico with distributed solar while phasing out centralized fossil-fuel plants.
The groups’ lawsuit cites a 2020 National Renewable Energy Laboratory report that found distributed solar could generate more power than the archipelago needs. And it notes that a 2021 Cambio PR and Institute for Energy Economics and Financial Analysis (IEEFA) study found that by 2035, operating a system relying on 75% distributed generation — including rooftop solar, batteries, and microgrids — would be less expensive than operating the current grid, measured in the price of energy per kilowatt-hour.
Rooftop solar paired with batteries, sometimes networked among houses and businesses into microgrids and virtual power plants, has already been invaluable for many Puerto Ricans. Grassroots organizations, tapping federal and philanthropic funds, have installed rooftop solar in communities across the island, as Canary Media chronicled in a 2022 special reporting project.
Biden Energy Secretary Jennifer Granholm touted distributed solar during multiple visits to Puerto Rico, and Biden EPA Administrator Michael Regan talked with residents about the burden of coal power. In December 2022, Biden signed a funding omnibus bill including $1 billion for rooftop solar for low-income households and households with disabilities in Puerto Rico.
As of June 2025, 1.2 gigawatts of grid-connected rooftop solar were installed on homes and businesses, according to the IEEFA, supplying more than 10% of the total energy used.
But the need for more distributed solar is still great. The IEEFA determined that at least 350,000 low- and moderate-income households are unlikely to install rooftop solar without financial assistance, based on 2021 data from the National Renewable Energy Laboratory, leaving them vulnerable during storms.
The Trump administration has gutted such assistance. Federal funding for solar in low-income areas nationwide was canceled, over $156 million of which was promised to Puerto Rico. On Oct. 1, the Department of Energy announced $365 million in Biden administration funds for rooftop solar and battery storage will be redirected to “strengthen grid stability and harden critical infrastructure.”
From his hillside porch on Puerto Rico’s south coast, retired sports medicine professor Miguel Rivera can see a coal-fired power plant, an oil-fired power plant, and an increasingly vast expanse of solar panels stretching across the otherwise lush, green landscape. He is among the residents and experts who say distributed generation is the only real solution for Puerto Rico.
As of spring 2024, 235 megawatts of utility-scale solar were deployed in Puerto Rico, and over 800 megawatts’ worth of such contracts were approved and executed by the federal fiscal control board, which oversees Puerto Rico’s financial affairs.
AES Puerto Rico, the company that owns the coal plant, has installed solar farms on the south coast near Rivera’s home, with the 200-megawatt solar project Marahú scheduled to go online this year. While the installations provide clean energy, they pose the same problem as fossil-fuel plants: The electricity they generate needs to be transported on vulnerable long-distance transmission lines. Meanwhile, the solar panels are being built on swaths of flat, fertile land ideal for farming, which is increasingly scarce on the island.
Though FEMA’s previous energy study did not delve into utility-scale solar, beyond backup power at critical facilities, Santiago said its pros and cons must be considered in the new study.
“What the utility-scale projects, whether renewable or fossil, have in common is that they’re very centralized, and they’re concentrated in one place and then depend a lot on high-voltage transmission lines and towers and substations,” said Santiago. “Distributed renewables on rooftops, parking lots, as close as possible to the point of use — avoid what happened with the existing system after Hurricane Maria. It’s so clear that this is a reasonable opportunity that needs to be considered. Otherwise, we will have more loss of life in the next storm.”
On an October Sunday afternoon a few weeks after the judge’s ruling, Rivera drove through the mountains with his wife, Maridalys Nieves, and friends including José Cora, leader of Acción Social y Protección Ambiental (Social Action and Environmental Protection), a grassroots local environmental justice organization.
They pointed out the broken power lines swinging from poles and lines drooping under curtains of green vines. The well-being and safety of residents in small mountain villages is threatened by the deteriorating power lines. Rooftop solar panels paired with batteries could make these locals largely energy self-sufficient.
But given the median household income of under $25,000 a year in the mountainous regions — Jayuya, Orocovis, and Utuado — that the friends drove through that day, it is nearly impossible for many residents to pay for solar. Cora, an IT professional who maintains computer servers, noted that despite his commitment to clean energy, his family can’t afford to install solar and batteries on their own home.
As the car descended down a mountain, Nieves received a social media alert on her phone that many would not have power because of a problem at the coal plant.
Rooftop solar and batteries are the only way to free residents from such frequent occurrences, the friends agreed. They hope FEMA follows the judge’s orders and does a thorough study, and then funds scores of distributed solar arrays as a result.
A first-of-a-kind project underway outside Portland, Oregon, could provide a model for data centers to connect to the grid without driving up utility bills and carbon emissions.
Silicon Valley startup Gridcare launched in May with a promise that its artificial intelligence–powered software can help actualize one of the hottest concepts in the electricity sector: data center flexibility. Last month, it announced the successful use of its software by utility Portland General Electric (PGE) to bring 80 megawatts of data center load online next year in Hillsboro, Oregon.
That’s not a ton of new computing load, considering the gigawatts’ of prospective data center expansions being planned across the country. But as a real-world example of a utility planning around a data center’s commitment to reduce power use during moments of high demand, the project may well be a breakthrough.
“We’ve moved from the theoretical to the practical,” said Larry Bekkedahl, Portland General Electric’s senior vice president of strategy and advanced energy delivery. “This is our first project where that flexibility really comes into play.”
Around the country, utilities are planning massive investments in fossil-fired power plants and grid capacity because of the boom in power demand from data centers. Those spending plans threaten to impose enormous costs on utility customers already struggling to keep up with rising electricity rates.
Data center flexibility agreements could be an elegant solution. If the facilities can ease off their massive power use during the handful of hours per year that they would otherwise overload the grid, they should be able to get connected to the grid sooner — and utilities could defer costly infrastructure upgrades that in some cases include more fossil-fuel power plants.
Other data centers are testing the use of batteries or flexible computing or a combination of both to reduce the burden placed on the grid. But public announcements of flexibility agreements between utilities and data center developers are few and far between — and the technologies that could allow them to become more common are still emerging.
Amit Narayan, Gridcare’s CEO and co-founder, believes PGE’s use of his company’s software may be the “first project of its kind where a utility has been able to accelerate data center expansion at this scale.”
Narayan said the startup also has projects underway with unnamed tech giants and data center developers, as well as with utilities including California’s Pacific Gas & Electric.
“We have these new tools of real-time visibility and dispatchability and control of distributed energy technologies,” Narayan said. “Why do we have to live with the old assumptions of designing around worst-case scenarios?”
In order to understand how PGE and Gridcare’s approach differs from that of other data center flexibility projects around the country, it’s important to grasp the complexity of the problem PGE is trying to solve for its Hillsboro data center cluster.
Hillsboro, a major hub for chipmaker Intel and a terminus for multiple fiber-optic cables connected to Asia, is experiencing “huge demand for data centers in the 50-megawatt to 500-megawatt range,” PGE’s Bekkedahl said. Those data centers are powered by the utility’s transmission grid, which is structured as a network that shares power across multiple interconnected nodes. And existing electricity demand is already pushing that grid close to its operating limits in the Hillsboro area.
Data centers seeking more power from that constrained grid have put PGE in a bind, he said. Under traditional utility planning, the network would have to be scaled up to provide enough power to serve every customer during times of peak demand.
“But there are only a few peak hours, during maybe five to 10 days a year, that we need to meet those peaks,” he said. Building enough transmission to serve them all would take years, cost hundreds of millions of dollars, and yield a grid that’s far bigger than what’s needed most of the time.
Flexibility projects aim to prevent the need to overbuild by reducing the demand peaks that new data centers cause. But PGE can’t make plans based on what a single data center might do. It has to consider the growth plans of all the customers connected to that part of the grid, during every hour of the year, for years into the future — and then also consider the impact on PGE’s regional transmission network and generation fleet.
Human grid planners simply can’t parse through all those variables at once, Bekkedahl said, even with the help of standard planning software.
“That’s where Gridcare came in and helped us model,” he said. Through Gridcare’s software, PGE identified a combination of flexibility opportunities that could allow data centers to add 80 megawatts of additional power use next year, instead of waiting years for traditional grid upgrades, he said.
Narayan is familiar with complex computing challenges. He founded, built, and sold a semiconductor design company called Berkeley Design Automation in the 2000s. Next, he launched Autogrid, a “virtual power plant” software provider that was sold to Schneider Electric, the French energy equipment and services giant, in 2022 and is now part of utility software company Uplight.
Gridcare applies similar computing techniques to model the interactions of lots of power-hungry customers across a dynamic, networked grid, he said.
“You have a major combinatorial-explosion issue here,” Narayan said. “Instead of analyzing one case and one dispatch scenario, which planning teams do — and which is itself very complicated — you have to analyze 200,000-plus scenarios and contingencies.”
Under traditional grid-modeling methods, “that’s typically done in a sequential way, one project and one scenario at a time,” he said. But that’s a highly impractical approach to finding solutions quickly enough to inform utility decision-making.
As Narayan noted, “We have to look at many different projects, each with its impact on ramp and load, over the next five to 10 years. We have to look at very many different scenarios of flexibility. And we have to do it for every hour of the year.”
Recent developments in AI and computing power have made this complex problem solvable: “We’re able to take all the sources of flexibility that may exist, and then examine all the combinations and permutations that exist, and find the lowest-cost way to manage those constraints.”
Not all utilities are ready to rely on flexibility as an alternative to hard grid upgrades. But PGE has been working for years on modernizing its grid operations to support distributed energy and flexibility and bring in real-time data from AI-enabled smart meters, which has given its grid operators confidence in understanding and managing customer-sited energy resources, Bekkedahl said.
With that expertise to back up Gridcare’s revelation of the options at hand, PGE has been able to approach data centers in the Hillsboro area to propose mutually beneficial commitments, he said.
“Those data centers that are willing to work with us, if they’re willing to be flexible, we’ll put them at the top of the queue” for additional power, Bekkedahl said. “For someone who says, ‘Nope, we’re going to want 100 percent,’ well then, we say, ‘You’ll wait for us to build the transmission.’”
At least one data center has already pulled the trigger on a project identified by the collaboration between Gridcare and PGE. Last month, Aligned Data Centers announced plans to work with energy-storage specialist Calibrant Energy to deploy a 31-megawatt/62-megawatt-hour battery across the street from its Hillsboro data center. It’s the first publicly revealed project that’s part of the scope of work enabling the 80 megawatts of additional capacity that PGE will be able to energize next year.
Once it’s turned on sometime next year, that battery will allow Aligned to expand its computing capacity at the data center years faster than it would have been able to by waiting for PGE to upgrade its grid to supply its peak power demand. Aligned didn’t disclose how many megawatts of increased power demand its expansion will cause, a sign of the highly competitive nature of today’s data center market.
Accelerating that “speed to power” has become an overweening obsession of data center operators seeking to meet tech giants’ AI ambitions, and flexibility is increasingly pointed to as the way forward.
A February report from a Duke University team led by researcher Tyler Norris found that the U.S. has nearly 100 gigawatts of existing capacity for data centers that can curtail less than half of their total power use during peak demand events, which occur about 100 hours of the year. Last month, Energy Secretary Chris Wright ordered the Federal Energy Regulatory Commission to fast-track a rulemaking process to prioritize such flexible interconnections on U.S. transmission grids.
But data centers can’t afford to invest in batteries like this without clear commitments from utilities that those investments will in fact resolve the grid constraints preventing them from getting online faster.
“This is where PGE was a fantastic partner with us,” said Michael Welch, Aligned’s CTO. “They were able to model these scenarios and understand them with a high degree of accuracy, and provide the greatest impact without wasting capacity. As that came into clarity for us, we were able to work within those constraints.”
Bekkedahl emphasized that PGE is taking its time in its work with Gridcare. While the utility hopes to interconnect 400 megawatts of expanded data center load in Hillsboro by 2029, “we’re not putting on 400 megawatts tomorrow,” he said. “There’s a stepping-stone process here. We want to see it in action before we believe it.”
Nor can PGE completely avoid building more transmission and generation to meet its fast-growing demand for power. “We’re going to have to build out. This is just a bridging strategy,” he said.
But any approach that can increase the amount of electricity that PGE sells without adding exorbitant grid costs should help reduce the impact on customers at large, Bekkedahl said. “Bringing down the peak, and bringing up the overall utilization of the system, makes it more affordable for all customers.”
Xcel Energy’s sprawling Sherco Energy Hub will be among the United States’ biggest solar farms when the last of its three approved phases powers up next year. Soon after, the central Minnesota site could also host one of the Midwest’s biggest battery clusters.
In a Halloween filing, Xcel asked the Minnesota Public Utilities Commission for permission to double its planned battery capacity at Sherco while adding a 200-megawatt fourth phase of solar there and deploying about 136 MW of batteries at a separate site southwest of Minneapolis.
The push to build even more clean energy was spurred by rising electricity demand and the looming phaseout of federal clean-energy tax credits under the Trump administration, which has worked to hamstring renewables while attempting to boost coal and gas generation.
If the commission approves Xcel’s proposal, Sherco would host 910 MW of solar and 600 MW of battery capacity by the end of the decade. At peak production, that would go a long way toward offsetting the output of what Xcel representatives have called the “backbone” of the company’s Upper Midwest generation fleet: the roughly 2,300-MW Sherco coal plant, which shut down its first unit in late 2023 and is set to fully retire in 2030.
George Damian, director of government affairs for Clean Energy Economy MN, said the proposal underscores the growing importance of batteries as the grid shifts away from fossil fuels.
“As demand continues to rise, technologies like battery storage are becoming essential to maintaining reliability while integrating more carbon-free generation,” Damian said.
Xcel regional president Bria Shea agreed, saying in a statement that “[w]e’re making a significant investment in battery storage because we see it as a critical part of Minnesota’s energy future.”
The separate 136-MW Blue Lake project would replace retired fossil-fuel capacity, too, boosting output at what’s now a 332-MW gas peaker plant. Xcel retired Blue Lake’s aging oil-fired units earlier this year, leaving two newer gas units operating and freeing up more than 200 MW of grid interconnection capacity.
Minnesota requires its utilities to procure 100% clean power by 2040 and aims to decarbonize its entire economy by 2050, with ambitious targets for building and transport electrification. Meanwhile, developers have proposed at least a dozen large-scale data center projects around the state, including several in Xcel territory. In December, Xcel executive Ryan Long — then serving in Shea’s role — said the company could absorb 1.3 GW of data center capacity by 2032 without derailing its carbon-free power plan, though he added it may need to extend the life of some gas plants to accommodate the load increase.
In the filing, Xcel said it wants to move quickly to expand its generation capacity while there’s still time to qualify for federal clean-energy tax incentives of 30% or more.
President Donald Trump’s One Big Beautiful Bill Act will sunset those incentives several years early, forcing most wind and solar projects to begin construction before July 4, 2026, to qualify for the full value. Energy storage projects qualify for the full credit value through 2033, but Xcel said uncertainty around new foreign-sourcing restrictions taking effect next year increases the urgency to deploy storage soon too.
Xcel says it expects to break ground on the Sherco and Blue Lake battery installations next year and power them up in 2027. It aims to commission the Sherco solar project by 2029.
Rather than contract with independent solar and battery installations in its territory, Xcel wants to build and own all three projects itself. In the filing, it said rules set by Minnesota’s grid operator require company ownership of new energy facilities reusing interconnection rights at retiring power plants. The same filing asks the commission to approve agreements to purchase power from several third-party solar and battery projects that will connect to the grid elsewhere.
John Farrell, the Minneapolis-based codirector of the Institute for Local Self-Reliance and a frequent critic of the monopoly-utility model, said the looming tax-credit cliff creates an unusual circumstance where the need to quickly develop more clean energy cuts against his preference for an open and competitive bidding process that could result in a better deal for electricity customers.
“I am more sympathetic than I would be normally because we are stuck in the regime we’ve got and there’s a lot of money on the table,” he said, referring to the tax credits whose rollback is expected to raise Minnesotans’ electricity bills in the coming years.
To incentivize faster clean-energy deployment ahead of the cliff created by Trump’s megalaw, the Minnesota Public Utilities Commission in August said it would allow projects that meet the deadline for federal tax incentives to also access extended eligibility for state renewable energy credits.
Xcel spokesperson Theo Keith said the utility has “already taken steps to ensure this portfolio of projects will qualify for federal tax credits before they expire.”
But with the North American Electric Reliability Corp. forecasting a “high risk” of capacity shortfalls on the Upper Midwest grid by 2028, there’s a chance that the U.S. Department of Energy issues an emergency order requiring one of the Sherco plant’s two remaining coal units to run past its planned retirement next year, said Allen Gleckner, chief policy officer for Minnesota-based Fresh Energy.
The DOE has already done so for one retiring coal station in the Midwest, Michigan’s 1,420-MW J.H. Campbell plant. Its operator, Consumers Energy, says that order, which runs at least through Nov. 19 and which the DOE says it could extend for much longer, has already cost consumers at least $80 million. It’s unclear whether a similar order at Sherco would affect Xcel’s battery plans, but it would be disruptive to the utility either way, Gleckner said.
“The uncertainty that scenario contemplates is another reason why it would be a terrible idea,” Gleckner said.
Asked if Xcel had reason to expect a DOE emergency order at Sherco and whether that could interfere with its proposed clean-energy deployments there, Keith said only that Xcel is moving ahead with its plans to retire the coal units by 2030.
“We are in regular conversations about Minnesota’s energy future with various stakeholders, including federal, state, and local elected officials,” he said.
When Connecticut Gov. Ned Lamont, a Democrat, first nominated Marissa Gillett to the Public Utilities Regulatory Authority in 2019, he praised the “outsider’s perspective” she would bring to the state’s energy challenges. This September, just months after a bruising reconfirmation process, she stepped down, citing a tangle of acrimonious disputes with investor-owned utilities and lawmakers who bristled at her novel approach to regulation and accused her of inappropriate, even unlawful, bias.
Public utility commissions are essential but largely invisible forces regulating and shaping electricity, gas, and water services at the state level. Traditionally, these boards have been thought of as working in tandem with utilities, rarely challenging their proposals and claims. Recently, though, the tides have shifted, as more states and advocacy groups look at ways for commissioners to advance state energy policy.
The need for decisive action from utility commissions is becoming more acute as electricity prices climb almost everywhere in the country and many states push to meet decarbonization goals. The regulatory status quo just doesn’t lend itself to the systemic changes needed to fight these battles.
Gillett has been hailed by some as an exemplar of the assertive regulator, bringing a decidedly proactive sensibility to her work on the Connecticut commission, commonly called PURA. Following her resignation from the board, Gillett sat down for a conversation with Canary Media about what that involved regulation should look like as states face down a crucial moment for consumers and climate alike.
“Regulators need to roll up their sleeves and figure out how to provide continuous, sustained rigorous oversight,” she said.
The traditional model for investor-owned utilities guarantees them a set rate of return on every dollar spent building new distribution lines, upgrading substations, and other such projects. This dynamic has led to criticism that utilities are prone to overspending on infrastructure that might not be in the interest of customers or the environment, for the simple reason that it will bolster their earnings and please their investors.
A key job of leaders like Gillett is to weigh these utility requests against the need for adequate, reliable infrastructure, and the needs of consumers and the state’s energy policy goals. But for too long, critics say, commissioners have functioned more as umpires calling balls and the occasional strike, approving most utility requests.
Before coming to Connecticut, Gillett worked for seven years at the Maryland Public Service Commission, contributing to the development of initiatives including the state’s electric vehicle programs and its offshore wind plan. After a brief stint with the Energy Storage Association, a trade group, she threw her hat in the ring for the Connecticut commissioner position.
Gillett came into the job ready to be the “change agent” the governor said he wanted. Her aim was to reform an entrenched system that had led to some of the country’s highest electricity rates and mixed progress on climate goals — and to move away from the “balls and strikes” mentality that she found unrealistic and limiting.
“I acknowledge you have to make decisions based on the evidence and record in front of you,” she said.
But she was not willing to accept that the only evidence available was what was contained in utility filings and the responses to them. She offered this analogy: If one party came before PURA saying the sky was green, and another argued it was purple, the board should not be forced to choose between those two options.
To dig deeper into the issues before the commission, she assembled a staff of 80 “who are the best in the business and are very passionate about the work,” a group she hopes stays in place despite her departure.
“It is important who sits in the commissioners’ seats, but it’s also important who staffs them,” she said.
Right from the beginning, she and her staff led PURA in several controversial decisions that left utilities and Republican lawmakers claiming she was creating a hostile and uncertain environment for the state’s two major investor-owned utilities — Eversource and United Illuminating — and their shareholders.
After the utilities struggled to restore power following Tropical Storm Isaias in 2020, PURA ordered Eversource to return $28.4 million to customers in the form of bill credits. In 2023, the commission reduced United Illuminating’s requested $123 million rate increase by $100 million. The utility challenged this move in court, but PURA’s decision was upheld.
Gillett argues she always just applied rules that were on the books but rarely enforced. She points to her track record in court cases: Five times utility challenges have made it to the Connecticut Supreme Court, and five times the court supported PURA’s rulings, she said.
“For years we heard in public that I was acting illegally, making decisions that were arbitrary and capricious,” she said. “I was now holding them to standards they had not been held to. I viewed myself as somebody tasked with implementing state policy.”
While the financial penalties and rate reductions Gillett’s PURA imposed garnered headlines, she also made changes that were less widely noticed, with the goal of prepping the grid to handle more renewable energy. Within Gillett’s first year, the board launched the Equitable Modern Grid initiative, a series of investigations into 11 topics, including advanced metering, energy storage, and affordability. The process yielded ongoing action, including a battery incentive for homeowners and businesses and a program to fund pilots trying out innovative grid technologies.
“Considering how slowly regulatory processes usually work, I think designing and launching those programs in that amount of time was very impactful,” Gillett said.
It’s difficult to assess the effect of Gillett’s philosophy on Connecticut’s energy and climate landscape quite yet: Changes to the utility industry are notoriously slow-moving, and the pandemic added an extra level of disruption to her tenure.
Electricity prices remain high there, as they are throughout the entire Northeast, but Gillett leaves behind programs intended to reduce the energy burden on low-income households. During her tenure, the state implemented its first discount electricity rate for such families and launched an outreach program to help disadvantaged households access assistance offerings.
Gillett does not yet have her next move mapped out, but she does have a degree of optimism that utility regulation is evolving toward the sort of goal-driven, engaged model she brought to her time in Connecticut.
More states are already taking seriously the need to seek out “competent, qualified” regulators with a background relevant to the work, she said. She pointed to a Brown University study that found, nationwide, the share of commissioners with previous work on environmental issues grew to 29% in 2020 from 12% in 2000. States like Maine and Colorado have taken steps to direct their utility regulators to consider emissions, equity, and environmental justice when making decisions.
“As electricity affordability becomes more front-and-center, and folks are looking to who is supposed to be watching out for them, there will be a moment when regulators embrace that philosophy more,” she said.
An Indiana utility has come up with an unusual plan for meeting growing power demand from data centers.
Northern Indiana Public Service Co. is launching a spinoff company, GenCo, that is exempt from many of the regulatory proceedings typically required before power plants can be built in the state. The utility, also known as NIPSCO, says that this will allow the new entity to quickly provide the copious amounts of energy that data centers need without pushing excessive costs onto other consumers.
But the move is raising alarm bells for watchdog groups and other critics, who argue that rather than protect consumers, the plan will mainly enrich the utility’s parent company while interfering with market competition and undercutting important regulatory safeguards. It could also set back the state’s clean-energy transition, advocates say.
As regulators around the country wrestle with how to get a lot of power online quickly to serve “hyperscaler” AI data centers, other utilities may be looking at NIPSCO’s “unique arrangement” as “a model for how to maximize profits while meeting new data-center demand,” said Emily Piontek, a regulatory associate at the nonprofit Clean Grid Alliance.
Indiana is attractive to huge data centers because of its cheap land, ample water, special state tax breaks on equipment and energy, and access to both the PJM Interconnection and Midcontinent Independent System Operator regional electric grids. The State Utility Forecasting Group at Purdue University recently predicted that data centers will almost double Indiana’s energy demand by 2035.
NIPSCO highlighted that boom to the Indiana Utility Regulatory Commission during the case proceedings to create GenCo. Vincent Parisi, president and CEO of both NIPSCO and GenCo, told regulators about the sheer number of requests the utility has gotten from potential “megaload” customers, generally data centers, seeking hundreds or even thousands of megawatts of electricity.
But it’s a competitive business, with other states and municipalities courting the same data centers. NIPSCO says that providing new power quickly, through GenCo, will be key to securing the deals.
The regulatory commission agreed with this reasoning, writing in its September order approving the GenCo plan, “The evidence shows that megaload customers are sophisticated and have many choices available to them when determining where to make developments.” The commission added that relinquishing its jurisdiction over aspects of GenCo “will enable NIPSCO to support Indiana’s efforts to compete with other states to attract this economic development.”
Nationwide, regulators and advocates have grappled with concerns that residential customers could pick up too much of the tab for new generation built to power data centers, especially if the computing warehouses don’t materialize or don’t use as much power as predicted.
NIPSCO says GenCo will protect customers from such costs since it will be responsible for providing the data centers with power. That means those expenses won’t be rolled into the rates paid by other NIPSCO consumers, the utility says.
But Citizens Action Coalition, the state’s main consumer-advocacy group, argues that the GenCo structure doesn’t really insulate customers from the risks of the data-center market.
If GenCo were to lose money, that could affect the finances and credit rating of parent company NiSource and hence impact NIPSCO’s customers, said Citizens Action Coalition Executive Director Kerwin Olson. And he worries some costs of data-center power infrastructure could still be passed on to residential customers, hidden in an opaque process created specifically for GenCo.
In September, the state regulatory commission exempted GenCo from a host of usual procedures. Chief among them is that GenCo does not have to file a detailed plan when it wants to build or acquire new generation. The commission did not set any minimum standards or requirements regarding how power will be provided to data centers, as advocates had hoped. Instead, the commission will review each proposed contract between NIPSCO and a data center, and the related power purchase agreement between NIPSCO and GenCo.
The Citizens Action Coalition called this case-by-case review process unfair and inefficient, making it too difficult for stakeholders to monitor the situation and submit public comments to the commission.
“Every single time a data center comes online, there’s another case; there’s no minimum criteria or boxes that need to be checked,” said Olson. “I know they’re claiming costs won’t be passed on to ratepayers, but we’ve been around the block. When you have what will likely be confidential special contracts, everything redacted, it’s going to be really challenging for stakeholders to dive into the details to ensure that none of these costs are being passed on.”
NIPSCO declined to answer questions but referred Canary Media to a press release quoting Lloyd Yates, NiSource president and CEO, regarding the regulatory commission’s decision.
“This is an important step forward to position Northern Indiana at the center of a fast-growing, economically essential industry,” Yates said.
The Citizens Action Coalition and the Indiana Office of Utility Consumer Counselor, a state agency tasked with protecting consumers, notified the commission that they plan to appeal the approval of GenCo.
Another major concern of critics is that GenCo will have an unfair competitive advantage over other power producers.
Indiana has a regulated energy market, wherein utilities have the right to serve as monopoly producers and distributors of energy, but regulators must approve how much capacity they build or buy and what they charge customers for the power.
GenCo is largely exempt from this structure, acting more akin to a power producer in a state like Illinois, with a deregulated market. But in Illinois, power producers compete to sell their energy to utilities, whereas GenCo has a guaranteed customer in the form of NIPSCO, and the two sister companies — which share the same parent — set the price NIPSCO will pay GenCo for power.
“The utility affiliate is being treated like an unregulated independent power producer while retaining the guarantee of a monopoly market enjoyed by regulated utilities,” Piontek said. “Essentially, the arrangement insulates GenCo from market forces, and [it] is not subjected to rate regulation. It’s going to be a very profitable arrangement for the parent company and its shareholders … by providing the affiliate with an unearned competitive advantage.”
The Clean Grid Alliance — made up of renewable-energy developers, environmental groups, and other stakeholders — and Takanock, a data-center developer, told regulators in a joint brief that GenCo “turns the federal paradigm which encourages competition … on its head by proposing that GenCo, and only GenCo, provides generation services to NIPSCO to serve its megaload customers.”
In testimony, Takanock founder and CEO Kenneth Davies told regulators about problems his company has had trying to acquire power from NIPSCO for a planned data center. Davies described the NIPSCO-GenCo relationship as “anticompetitive,” and lamented that NIPSCO will not allow new data-center customers to buy power on the open market themselves, as some existing industrial customers are allowed to do. Davies said NIPSCO seems to be “picking and choosing” which data centers to prioritize, and he is worried Takanock could be treated unfairly, since confidential contracts would make it difficult to compare the arrangements other data centers are getting.
Davies and other stakeholders say there are ways for NIPSCO to protect customers from data-center costs without creating a new market entity with an unfair edge.
Takanock and the Clean Grid Alliance, in their filing, criticize GenCo for failing to explore the more common method of pricing tariffs designed specifically for data centers. That’s where a utility makes an agreement with state regulators to treat data centers differently from other customers, ensuring they pay their fair share of costs. Davies described Wyoming regulators’ creation of such a special tariff to serve a Microsoft data center. Davies was Microsoft’s director of renewable-energy strategy and research at the time.
In another example, Citizens Action Coalition reached an agreement last year with utility Indiana Michigan Power and three new data centers, requiring long contracts, exit fees, and other protections to ensure the centers pay the full costs of infrastructure built to serve them, even if they don’t use as much power or operate for as long as expected. The agreement also requires the data centers to pay millions of dollars to support low-income electricity customers with benefits like weatherization.
Advocates point out that Indiana already has a law on the books meant to help utilities more quickly get power online to supply data centers, without sacrificing transparency or relying on a new entity like GenCo. HB 1007, enacted in May, gives utilities an expedited approval process for new generation if they provide information about the impacts on customers, predicted load growth for the next five years, and the potential of grid-enhancing tech to avoid investments in new power plants, among other things.
“NIPSCO decided to ignore 1007 and create what we think is a shell game, a scam, with this unregulated affiliate doing Lord knows what,” said Olson.
The creation of GenCo will likely undermine the clean-energy transition in northern Indiana, advocates say. NIPSCO has already made clear its plans to build lots of natural-gas-fired generation to power data centers, and if this is carried out through GenCo, stakeholders will have little opportunity to weigh in on the implications.
This is a disappointing shift for environmental groups that had praised NIPSCO for plans it announced in 2018 to retire all coal plants within a decade and build out renewables, reducing carbon emissions by 90%.
By contrast, NIPSCO’s 2024 Integrated Resource Plan says that if contracts with data centers are in place, the utility will build over 1,700 megawatts of gas generation by 2030 and another over 2,000 MW by 2035. Already, NIPSCO is seeking an air permit to build 2,300 MW of gas-fired generation at the site of a retiring coal plant, in order to serve data centers.
“GenCo is certainly a concern for the climate, demonstrating that NIPSCO has done a complete strategy reversal on sustainability,” said Ben Inskeep, program director at Citizens Action Coalition. He said the utility’s 2018 resource plan “was groundbreaking for leading the way on a clean-energy transition. Now, they are pursuing a strategy that appears to be 100% natural gas for new data centers, with no additional clean energy to serve the additional load.”
If NIPSCO had to turn to the open market to procure the power that data centers need, Piontek noted, more renewables would likely get built along with the gas-fired generation.
“Clean-energy resources like wind, solar, and energy storage outcompete other resources in speed-to-market and remain the most cost-effective resources available, making them an attractive option for bringing data centers online in Indiana,” Piontek said.
Batteries have quickly become a crucial part of the U.S. electricity grid — and a whole lot more are about to come online.
Over the next five years, the country will build nearly 67 gigawatts’ worth of new utility-scale batteries, per data from research firm BloombergNEF, enough to send almost 284 gigawatt-hours of stored-up electricity back to the grid.
Those are massive figures. Should the forecast bear out, the U.S. will have roughly three times more battery capacity in 2030 than it does now. Such rapid growth is familiar territory for the sector, which jumped from just 1.5 GW of total capacity in 2020 to a whopping 27.3 GW by the end of last year.
The transition to renewable energy — particularly solar — relies on batteries. That’s because communities with lots of solar arrays often generate more power than the grid needs at a particular moment in time. Batteries let these solar-saturated states save that extra energy for later use.
California and Texas, the U.S.’s two leaders on solar, have built the vast majority of the country’s utility-scale storage. Already, the states are reaping the benefits. By spring of 2024, California’s battery fleet had grown large enough to begin displacing some natural-gas use in the evening. Meanwhile, batteries have helped Texas stave off summertime grid emergencies for two years running.
As battery developers propose more, bigger projects, the sector has started to run into some opposition. Just last week, news broke that plans to build New York’s biggest battery on Staten Island fell through following fervent protest from the local community. Fears of battery fires have spread around the country following the massive blaze at California’s Moss Landing facility in January, even though that disaster stemmed from the project’s outdated design.
Still, several broader trends suggest the sector’s growth will continue.
For one, President Donald Trump’s One Big Beautiful Bill Act left incentives for battery storage relatively untouched, even as it yanked away tax credits for solar and wind projects. Then there’s the fact that solar is growing steadily around the country, which will eventually create a need for storage in other states just as it has in California and Texas. Most important of all, demand for electricity is surging nationwide — and batteries are among the cheapest and quickest ways to get more capacity onto the grid.
Illinois legislators passed a major energy bill that creates grid-battery and geothermal incentives and a virtual-power-plant program, during the final hours of a fall veto session Thursday.
Advocates and industry sources describe the legislation as the crucial next step in the state’s clean-energy transition, jump-started by 2017 and 2021 laws that created significant solar and wind incentives. The bill’s passage comes as the Trump administration eviscerates federal support for clean energy and as a debate plays out in state legislatures around the country over how best to rein in soaring electricity rates.
The legislation faced substantial pushback, largely because of concerns about the costs imposed on residential and industrial customers to fund the energy-storage incentives. It also faced stiff competition for legislators’ attention during the six-day veto session, as bills related to a transit-funding emergency, a new stadium, and insurance regulation were also on the table.
The state House passed the bill on the second-to-last day of the October veto session, and the state Senate passed it in the final hours on Oct. 30. Gov. JB Pritzker, a Democrat, has pledged to sign the bill.
The Clean and Reliable Grid Affordability Act, or CRGA, calls for the procurement of 3 gigawatts of energy storage by 2030.
The Illinois Power Agency, which procures electricity on behalf of the state’s two major utilities, ComEd and Ameren, estimates that developing and operating the storage will cost $9.7 billion over 20 years. That money will be collected from utility customers through a new charge on their electricity bills. But under the incentive structure, a portion of the revenue earned by the storage companies will go back to consumers. With this factored in, customers will end up paying an estimated $1 billion for the storage.
Meanwhile, energy storage connected to the grid will save those same customers an estimated $13.4 billion over 20 years, since the influx of electricity into “capacity markets” will suppress prices, the Illinois Power Agency predicted. Capacity markets are run by regional grid operators to make sure enough power is available to meet future demand.
Mark Pruitt, an energy consultant who previously led the Illinois Power Agency, said that getting more electricity into capacity markets is urgent because of the AI data centers springing up in the state.
“Is there a way of demonstrating that we’re going to be able to get a benefit for consumers in all of this?” asked Pruitt. “That was an honest concern by many of the policymakers. When do consumers start to see a benefit, and will they see lower costs? I don’t know that prices are coming down; it’s a question of can you slow their rate of increase.”
The credit structure meant to incentivize storage under the bill is already being used as part of the state’s subsidy program to keep existing nuclear plants online, which got started in 2021. At the time, watchdog groups worried the mechanism would cost households money, but the arrangement has actually benefited consumers.
Energy-storage deployment is central to the virtual-power-plant program created by the bill, wherein homes and businesses with batteries can earn revenue by supplying energy to the grid when needed. The bill also, for the first time, makes geothermal eligible for state renewable-energy incentives. And it lifts a decades-old moratorium on the construction of large nuclear plants. The legislature had revised the moratorium in 2023 to allow small modular nuclear reactors to be built, though this technology is still nascent.
Legislators’ approval of CRGA “is a major step toward strengthening Illinois’ power grid and keeping energy costs in check,” said Hannah Flath, climate communications manager of the Illinois Environmental Council, a group of over 100 environmental organizations working on policy and advocacy. “Battery storage represents the next phase of Illinois’ clean-energy buildout, ensuring that clean power is available around the clock.”
The bill was backed by the Illinois Clean Jobs Coalition, made up of clean energy, environmental, and community groups that were instrumental in crafting and passing the 2021 Climate and Equitable Jobs Act. That law built on 2017’s Future Energy Jobs Act, by increasing incentives for renewables and electric vehicles and creating an ambitious clean-energy workforce training program, among other measures.
In February, legislators introduced two separate storage-related bills, one backed by the Clean Jobs Coalition and the other by storage and solar industry groups. They eventually joined forces, pushing together for CRGA.
Opponents — namely, large energy users — argued that storage development should be left to the open market and that customers shouldn’t have to pay for incentives.
“We want an all-of-the-above energy strategy,” said Phillip Golden, chair of Illinois Industrial Energy Consumers, which represents companies that use lots of electricity. “We think battery storage has a role to play; we think renewables have a role to play. What we’re anti is making ratepayers pay for things they don’t need to. Look to Texas: We’ve seen battery-storage developers invest in projects without state procurements.”
Indeed, Texas has seen rapid growth of battery storage, thanks in part to a lack of regulation. But backers of CRGA said it’s too risky to count on companies to build storage if they don’t have certainty of earning revenue.
The debate played out as northern Illinois residents served by ComEd face a serious spike in electricity prices, driven by the high cost of capacity in the PJM Interconnection regional market. CRGA proponents have said that storage on the grid is crucial to mitigate escalating prices, in part because it facilitates more solar deployment; energy from solar can be held in batteries until it’s needed.
“The only way to protect ratepayers and address energy affordability is by investing in solar and storage, the fastest and cheapest energy sources to deploy,” said Andrew Linhares, a senior manager at the Solar Energy Industries Association who focuses on the Midwest. “Energy costs are already set to increase next summer, and they’ll continue to skyrocket every year until Illinois solves its energy supply-and-demand imbalances.”
CRGA backers sought to dispel the myths that they say swirled leading up to and during the veto session, including the fear that companies could get incentives before they even built storage.
“CRGA does not deliver any benefits to storage projects until those projects are online,” said Stephanie Burgos-Veras, senior manager of equity programs at the Coalition for Community Solar Access, made up of businesses and nonprofits nationwide. “This means ratepayers have no up-front cost for the storage program, and that all projects must actively contribute to the grid through stored power and price suppression before they are eligible for incentives. It is an incredibly safe funding model that ensures families and businesses receive risk-free savings.”
Ultimately, backers of CRGA said the bill’s passage shows that a state-level clean-energy transition can still move forward even without federal support.
“This bill isn’t just a rejection of Trump’s anti-climate policies — it’s proof that local and state action can offset those backward policies,” said Flath. “Illinois consumers, our power grid, and our climate will be better protected from price volatility and increasingly extreme weather events because we’re stepping up to fill the gap where the federal government is failing us.”
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