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A total of 112 gigawatts of batteries were deployed around the world in 2025 — 10 times the amount added just four years prior.
See more from Canary Media’s “Chart of the Week” column.
First came the solar. Now, the batteries have arrived.
Installations of grid batteries, which can store solar and other energy for later use, surged by 48% in 2025 from the year prior, per new data from BloombergNEF. A total of 112 gigawatts of battery storage capacity was installed worldwide in 2025 — a record high that represents a tenfold increase over the amount constructed in 2021.
So, where are all of these batteries sprouting up? The short answer: mostly in China and the United States.
China alone installed more than half of the world’s grid battery capacity last year. The U.S., meanwhile, accounted for 16%.
Other places are seeing rapid uptake, too. Sun-soaked Australia grew its battery installations by a factor of nearly six last year, albeit from a pretty small base of just 827 megawatts in 2024. The U.K., which shuttered its last coal plant in 2024, saw installations nearly double between 2024 and 2025, to 2.6 GW. Meanwhile, across the broader sub-Saharan Africa region, installations roughly quintupled to 4.3 GW.
Battery installations are now starting to catch up to solar installations, BNEF says. A decade ago, the world was installing 56 MW of solar for every 1 MW of storage. Last year, that ratio was 6-to-1. This year, BNEF expects it to drop to 4-to-1.
The key driver of this growth is the ever-decreasing cost of energy storage, with lithium-ion battery prices dropping by more than 90% over the last 15 years.
The case for batteries is also strengthening as the world builds an incredible amount of wind and solar, since the technology can stockpile wind and solar power when it’s abundant to dispatch later when the grid needs it.
BNEF expects the storage boom to continue as data centers surge onto the grid — especially in the U.S. — and as power demand rises because of the electrification of vehicles and buildings.
The firm forecasts that the world will install a total of 158 GW of batteries in 2026, resulting in 41% year-over-year growth. Although the pace tapers off a bit from there through 2030, BNEF projects that by the end of the decade, annual additions will top 200 GW — more than double the record-setting amount seen last year.
A bill advancing through California’s legislature would create pathways for virtual power plants to compete with fossil-fueled peaker plants — a move that could help the state curb its fast-rising utility rates.
Virtual power plants are aggregations of small-scale batteries, electric vehicles, smart thermostats, and other customer-owned devices that can be called upon to provide cheap capacity to the grid. VPP programs already exist in California, but the state’s utility and grid regulatory structures don’t offer a clear way for VPPs to replace peaker plants.
Senate Bill 913, introduced by state Sen. Josh Becker, a Democrat, would allow VPPs to “compete on a level playing field with traditional power sources to provide grid reliability at the lowest cost.” The bill, which lays out a slew of policy changes, passed out of the California Senate Energy, Utilities, and Communications Committee earlier this month, a first step on the way to a potential vote before the full state Senate and Assembly.
Gas-fired peaker plants are a major driver of California’s rising electricity bills. Most of the state’s aging peaker plants are used only during a handful of hours each year when electricity demand is particularly high, but utility customers are required to pay for them to be available year-round in case of emergency.
VPPs can accomplish this job at a much lower cost, their advocates say, because customers have already paid to install these devices in their homes and businesses. The potential is vast: Millions of homes across California have devices that can turn down power use, and hundreds of thousands have batteries that can inject power onto the grid — all of which can be used to reduce the need for those “peaker” power plants.
Still, SB 913 may face an uphill climb, even in California’s Democratic-controlled government.
Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, the state’s major utilities, haven’t openly opposed the legislation. But VPP advocates say the utilities have quietly pushed back against programs that might undermine their ability to invest in — and earn guaranteed profits on — grid infrastructure to serve peak electricity demand.
The California Public Utilities Commission, whose five members have all been appointed by Democratic Gov. Gavin Newsom, has taken a number of actions in recent years that have reduced the ability of customer-owned resources to serve grid needs. Newsom also vetoed a slate of pro-VPP legislation last year.
But Becker and SB 913’s supporters are hopeful that mounting concerns about energy affordability could push the VPP legislation over the finish line this year. The bill is backed by clean energy companies, environmental groups, and consumer advocates.
“This is part of a nationwide effort that you’re starting to see, which is all about making better use of the clean energy resources that people already have in their homes to both lower cost and to improve reliability and to reduce pollution,” Becker, who’s authored several utility cost-containment and VPP bills in the past few years, told Canary Media. “I’m hopeful that now that more and more folks are focused on these things, we can move the ball forward.”
At its core, SB 913 is aimed at answering a fundamental question: How can VPPs reduce our reliance on gas-fired power plants that rarely ever run?
In California, the state’s aging peaker plants are paid to be available through a program called resource adequacy. In recent years, resource adequacy has become an increasingly larger part of customers’ bills, according to the community energy providers that are having to pay higher and higher prices to secure it.
The state’s growing fleet of utility-scale batteries is starting to become available for resource adequacy, but storage can’t meet these requirements on its own. For now, aging gas power plants remain the primary last resort for this critical service, which is meant to prevent blackouts.
Becker estimated that Californians are spending about $1 billion per year to “keep expensive peaker plants available for short-term demand,” both through resource adequacy payments and via state emergency funding to extend the lifespan of three coastal power plants, which were slated to close years ago to reduce their harmful impact on marine life.
“At the same time, we have underutilized assets like home batteries and EVs and smart thermostats,” he said.
SB 913 would order the California Public Utilities Commission to design clearer pathways for those assets to count toward resource adequacy.
That could allow VPPs to help displace gas peaker plants. Overall, VPPs could provide more than 15% of the state’s peak grid demand by 2035 and deliver $550 million in annual utility customer savings, according to a 2024 analysis conducted by the energy consultancy The Brattle Group for GridLab. About $417 million of those savings would come from deferring the need for generation capacity, the report found — a category of costs that includes resource adequacy.
Home batteries have already proved that they’re ready and able to meet these peak grid needs, Becker said. In particular, the Demand Side Grid Support program, one of California’s most successful VPP programs to date, has grown to more than a gigawatt of capacity as of last year.
DSGS has shown that its fleet of home batteries can be relied on much like a traditional power plant. In a test of the program over two consecutive hours during a late afternoon in July 2025, roughly 100,000 home batteries delivered about 476 megawatts of energy — enough power to match the output of a typical gas peaker plant.
Despite this performance, the DSGS program has been severely underfunded over the past two years and is now facing the threat of being disbanded entirely. VPP proponents are pushing legislators and the Newsom administration to keep it alive.
SB 913 largely uses the DSGS program as a model for how the California Public Utilities Commission should order the state’s three major utilities to design broader VPP programs.
“DSGS has been a very successful program, and it’s the thoughtful design elements that have made it that way,” said Erik Lyon, an energy regulatory manager at Renew Home. “That’s the key thing to understand about SB 913. The latest version of the bill actually names DSGS as a model.”
Renew Home manages millions of Google Nest thermostats that control air conditioners and home heating systems to reduce energy use and relieve grid peaks across the country, including in California. But to date, California’s demand-response programs have severely limited the role of such assets in addressing resource adequacy.
There are a lot of reasons for these limitations. Most of the demand-response programs in California require customers and the VPP companies that are enlisting them to undergo complicated and time-consuming enrollment processes, Lyon said. They also impose problematic compensation structures that can penalize participants on the basis of what VPP companies say are inaccurate measurements of how much relief they’ve actually provided to the grid.
The design elements that SB 913 adopts from DSGS, by contrast, offer a lot more flexibility for participants, according to Lyon. The bill instructs the CPUC to “streamline the enrollment process to eliminate these common and well-documented problems” that have been cumbersome for customers participating in traditional demand response programs, he said. And it calls for pathways to allow customers to enroll individual batteries, EV chargers, smart thermostats, or other devices that are actively reducing energy use, he said.
SB 913 also instructs the CPUC to use “weather normalized” approaches to measuring customers’ contributions to grid relief, Lyon said. That could help solve a measurement problem often associated with weather-sensitive devices like thermostats, ensuring that household contributions are emphasized during peak days when they are using more air conditioning or heat but not penalized for low load reductions on mild days, he said.
The California Public Utilities Commission has been leery of relying on demand- response programs in the past. But VPP backers say that perspective is based on its analysis of traditional programs, with all their flaws and gaps in accurate measurement.
Renew Home has been working with other utilities in other states and the companies that manage their home thermostat programs to test and verify more modern approaches to measuring the impact of lots of home thermostats turning down their air-conditioning use in response to utility signals, Lyon pointed out.
This should give the CPUC more confidence that it’s getting the grid relief promised, he said. “You can have statisticians dig around in that data and show how it works in ways that are really hard to fake.”
SB 913 also takes on a key problem for households that are increasingly installing batteries alongside rooftop solar: getting compensation for the power they can feed back to the grid.
Today, almost none of the state’s VPP programs allow that, said Jonathan Hart, policy director at the trade group California Solar and Storage Association.
Instead, those programs only allow homes to reduce their grid consumption to zero, he said — which means “utilities are not really accounting for what could be tapped into.”
State regulators have created some rare exceptions to this “no export” rule — including for the DSGS program. Under those exceptions, companies are allowed to measure the power flowing from batteries to the grid using the battery inverters themselves, rather than the utility-owned smart meters.
What’s missing right now is a way to account for that flow of electrons to the grid for resource adequacy, he said.
SB 913 would explicitly order the CPUC to develop a methodology that will give credit for energy exported to the grid in consultation with the California Energy Commission, which currently manages the DSGS program, and the California Independent System Operator, which manages the state’s transmission grid and energy markets.
That won’t be a simple task. CAISO has traditionally required that any power exported from home batteries must be measured via special stand-alone meters, as is required for utility-scale energy resources.
But these rules designed for utility infrastructure don’t work for programs that need to be cost-effective for homes and businesses, said Kurt Johnson, community energy resilience director at The Climate Center, a nonprofit group that supports SB 913.
The “revenue-grade meters” that CAISO requires battery-equipped homes to install would add an extra $800 to $1,000 per home, Johnson said. “If you require that, you’re going to crush the economics” of VPPs. Modern home-battery inverters and smart thermostats can meter themselves at a fraction of that cost, he said.
Hart noted that CAISO is working on rule changes that could allow distributed energy resources like home batteries to be integrated into its markets.
The grid operator hasn’t yet accepted the idea that VPPs should be able to earn resource adequacy value for battery power that’s exported to the grid, Hart said. But recent proposals that might allow individual batteries to be credited for their exported power indicate that there’s room for compromise on that front, he noted.
Sunrun and Tesla Energy, which collectively manage by far the largest share of rooftop solar–charged home batteries enrolled in DSGS, agree that California is missing out under its current regulatory regime.
“Building on this success means creating long-term pathways for DERs to enter the resource adequacy and CAISO wholesale energy markets,” said Lauren Nevitt, Sunrun’s senior director of policy. “SB 913 endeavors to do just that.”
Colby Hastings, senior director of residential energy at Tesla, said that the company has roughly 3 gigawatts of distributed battery capacity deployed in the state. “Enabling these resources to provide grid value will put downward pressure on rates, but we are not seeing urgency on using them,” she said. “We need faster action.”
Could California’s major utilities control their rapidly rising electricity rates by using their power grids more efficiently? State lawmakers want to find out.
A set of bills introduced this year would order Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric to measure and improve how they’re utilizing the hundreds of thousands of miles of power lines that carry electricity to customers.
At issue is how those utilities handle peaks in electricity demand that happen only a handful of hours per year — typically by upgrading and expanding expensive grid infrastructure. Identifying exactly where on the grid that utilities have taken, or plan to take, this approach and where extra capacity could be freed up is key.
Armed with that knowledge, regulators could set metrics and create incentives for utilities to use technologies like advanced grid controls and distributed solar with batteries to smooth out those peaks — and thus, reduce one of the biggest drivers of soaring electricity costs.
Assembly Bill 1975, introduced by Assembly Member Nick Schultz, a Democrat, would require utilities to measure grid utilization and find ways to improve it over time.
Senate Bill 905, a wide-ranging utility cost-containment package, includes a provision that would mandate “additional reporting on how effectively utilities are using existing distribution grid capacity, particularly during off-peak periods,” when grids have more headroom to deliver power.
“At a time when cost is an issue, making better use of the grid we already have — and have already paid for — is paramount,” state Senator Josh Becker, the Democrat who introduced SB 905, told Canary Media. “That doesn’t mean we won’t keep building new transmission for clean energy. But let’s make sure we’re using our existing grid well.”
One way to do that would be through load flexibility programs, which help relieve temporary grid constraints by paying customers to reduce the amount of power they use via smart thermostats and other devices, or to share the electricity they’ve stored in plugged-in electric vehicles and home batteries charged with rooftop solar.
Making better use of the existing grid could save a lot of money over the long run, Becker said. California’s three big utilities are spending more than other utilities around the country on their distribution grids, according to data from the Department of Energy’s Lawrence Berkeley National Laboratory and The Brattle Group. The costs of those grid investments must be recovered through the rates they charge their customers — who are now paying roughly twice the national average for electricity.
Much of that grid spending is meant to reduce the risk of sparking deadly wildfires. But a sizable chunk goes toward expanding substations, transformers, and power lines to serve EVs, heat pumps, data centers, and broader economic growth.
As the state pushes to meet targets to electrify vehicles and buildings, those costs could grow even further. A 2023 study commissioned by the California Public Utilities Commission found the state’s three major utilities could need to invest up to $50 billion by 2035 to meet growing power demand.
But if utilities can successfully get EV chargers, heat pumps, and other devices to use electricity when the existing grid has more capacity, it would minimize the need for expensive upgrades while also increasing sales of electricity to cover new and existing grid costs.
And such devices are eminently capable of orchestrating their load-shifting capacity as “virtual power plants,” which could flip them from driving up grid costs to lowering expenses for utility customers at large. This “load shift” approach could cut costs passed on to California customers by up to $13.7 billion through 2030, according to a 2025 analysis prepared for think tank GridLab by grid analytics startup Kevala.
Utilities don’t have a clear incentive to constrain excess grid spending, however. In fact, under traditional cost-of-service regulation, they earn guaranteed profits based on how much money they invest in infrastructure. That’s why elected officials who are facing voter anger over high utility bills in states across the country are looking to measures like those that have been proposed in California.
Deploy Action, a nonprofit formed to promote distributed energy as a solution to rising electricity costs, is pushing these kinds of grid utilization bills in California and several other states.
“We all know what’s driving up utility rates and bills,” said Phil Ting, the organization’s co-founder and a former California Assembly member from 2012 to 2024. “Every time PG&E is building something, they’re getting their rate of return. That adds to our rate base — the rates go up — and that’s what they’re financially motivated to do.”
Last month, Deploy Action won its first victory on this front in Virginia, with the passage of a law that would set grid utilization requirements for Appalachian Power and Dominion Energy, the state’s two major investor-owned utilities. The law was supported by Gov. Abigail Spanberger, who campaigned on containing rising electricity costs.
Virginia’s law requires utilities to gather and report detailed data on their grid utilization, and orders regulators to use that data to establish targets and timelines for utilities to optimize grid usage, with special consideration to “non-wires alternatives” like batteries and advanced grid controls.
“A goal would be for California to follow in Virginia’s footsteps,” said Arnab Pal, Deploy Action’s executive director and a former adviser in the Biden-era Department of Energy. “Then, we can do some procurement reforms around the technologies that increase utilization.”
This work wouldn’t happen overnight. Under AB 1975 and SB 905, the California Public Utilities Commission would order utilities to collect and share core grid-utilization data. Though the bills differ slightly in their approach, both stipulate that the CPUC set rules for the utilities to improve their grid utilization starting in 2028.
Simply getting the data is the first step, Becker said. Today, regulators lack insight into “how well we’re using the existing infrastructure,” he said. “There’s data we just don’t have.”
Grid utilization can be measured in lots of ways. Some are holistic in nature, such as determining “load factor,” which is a ratio of average load compared with peak load over a year. While this data isn’t disclosed in a consistent way, Becker and Pal both noted that comments in regulatory proceedings indicate that California’s utilities are experiencing load factors of about 45% to 50% in recent years, meaning that roughly half their grid capacity is underutilized much of the year.
That’s down from roughly 60% to 65% in previous decades, when the state had more steady electricity demand from factories and other big customers and fewer “peaky” loads like air conditioners and EV chargers. Similar dynamics have been reducing load factors for utilities in other states, Pal said.
Knowing your average load factor only gets you so far, though. Finding out which parts of the grid that utilities should target for peak demand reduction, or where excess grid capacity can better serve new loads, takes more fine-tuned data, Ting said.
Luckily, California has had mandates in place for more than a decade that have ordered utilities to collect data on grid hosting capacity — a measure of how much room is available on grid circuits and substations to add new generation sources like solar panels — and publish that data on maps, which have gotten incrementally more accurate and useful over time.
A bill authored by Becker and passed in 2023 instructed California utilities to find ways to overcome grid bottlenecks preventing new customers from getting connected. Since then, California utilities have made progress on using locational grid data to support flexible interconnection of solar and battery projects, as well as flexible energization of big electricity users like EV charging hubs — and could potentially do the same with new data centers.
Utilities have also launched pilot projects to figure out how to use distributed energy resources — like rooftop solar–charged batteries, grid-responsive smart thermostats, and EV chargers — to relieve grid pressures. Other pilots are asking customers who want to add EV chargers, heat pumps, and other new loads on stressed circuits to promise to limit their draw on the grid during times of peak demand.
What’s missing from all these efforts so far is a regulatory structure that rewards utilities for planning their grid investments around these new ways to smooth out peak demand, Pal said. To address this, AB 1975 and SB 905 include provisions that would require the CPUC to design and implement penalties for utilities that fail to improve grid utilization, as well as incentives for achieving better performance over time.
“The way to do this is, give them the ability to use more of their grid, give them a set of metrics, give them the tools to actually plan for that — that is, require it of them,” Pal said.
That may involve incentives for utilities that expand options for customers to enlist their batteries, EV chargers, and remote-controllable appliances in virtual power plant programs, he said. But it could also mean giving utilities the opportunity to earn a regulated profit on technologies they deploy.
For example, utility-controlled batteries could be used to relieve peak loads on substations, a scenario that Minnesota regulators recently approved for utility Xcel Energy. Other options include so-called grid-enhancing technologies, which help utilities identify and optimize underused portions of their grid; and advanced conductors, which carry more power than traditional power lines do.
Deploy Action is supporting another bill in the California legislature, SB 1295, that would create a pathway for utilities to identify and propose projects that could meet those needs. “When it comes to distributed batteries and advanced conductors and other things that help with efficiency, we want to make sure there’s a procurement function available,” Pal said.
One way to achieve that would be for utilities “not necessarily to own the technology behind it, but perhaps rate-base some of it, so they’re able to make some of the right decisions,” he said. “We’re comfortable with that.”
These kinds of concessions to utilities raise red flags for Matthew Freedman, staff attorney for The Utility Reform Network. The consumer advocacy group supports legislative directives to the CPUC to set metrics and establish targets for improving utilities’ grid utilization, he said.
But TURN is leery of moving too quickly to create financial incentives that would reward utilities for doing things that might not directly reduce rates for customers, Freedman said. “If we say to the utility, ‘We’ll reward you based on the utilization of the system,’ but we don’t have another metric to track total spending, utilities could maximize that incentive by spending through the roof, or diverting money from other programs,” he said.
That’s why TURN has asked California lawmakers to amend AB 1975 to avoid giving the CPUC authority to set utility incentives right away, he said. “Let’s give it a number of years to play out. And at that point, we’ll have more confidence on which targets and metrics are worth putting our money on.”
Pal said that Deploy Action understands such concerns. “We’re going to want to see an incentive structure for utilization,” he said. “But we want to make sure … the ultimate goal is cost reduction.”
The Middle East crisis is straining global supplies of aluminum — a metal that’s key to making everything from fighter jets and soda cans to clean-energy technologies like solar panels and electric vehicles. Iran’s strikes on two Gulf aluminum smelters and the monthslong blockade of the Strait of Hormuz have disrupted production and pushed up prices, fueling fears of a coming aluminum crisis.
(Emirates Global Aluminium)
The United States has plans for a massive new smelter that would help to somewhat insulate the country from future global disruptions. But how quickly the $4 billion facility moves ahead depends largely on when it secures a long-term power contract — something its developers have been trying to do for almost a year.
In May 2025, Emirates Global Aluminium announced that it was building a new smelter in Oklahoma, a state with abundant natural gas and wind and solar energy resources. Earlier this year, Chicago-based Century Aluminum said it was partnering with EGA to build the plant, slated to produce up to 750,000 metric tons annually, through a joint venture named Oklahoma Primary Aluminum.
The energy-hungry facility will be America’s first new smelter since 1980, and it will more than double the nation’s capacity for making primary aluminum. The companies say they expect to start construction in late 2026 and begin producing metal by the end of the decade.
“Finalizing the power agreement is the next critical step,” Ryan Plotkin, an Oklahoma-based manufacturing executive who helped lure the smelter to the state, wrote in a Tulsa World opinion piece this week. “Oklahoma was chosen because of our resources and reliability. Now we must follow through.”
The smelter could require over 11 terawatt-hours of power to convert raw materials into shiny aluminum — enough electricity to power the city of Boston or Nashville annually, according to an Aluminum Association report.
To secure its electricity supply, Oklahoma Primary Aluminum has been pushing for a competitive deal with Public Service Company of Oklahoma, which is a subsidiary of utility giant AEP. The aluminum company is slated to receive hundreds of millions of dollars in incentives from the state of Oklahoma, including power discounts, along with a $500 million grant from the U.S. Department of Energy.
“Negotiations are ongoing and remain aligned with our original timeline,” Ziad Fares, project director for Oklahoma Primary Aluminum, told Canary Media.
“The project will source power from the grid, and its energy mix will evolve based on decarbonization goals, market conditions, and demand for low-carbon aluminum,” he said, adding that decisions about expanding electricity capacity to meet the smelter’s demand — whether through gas, wind, or solar — will be made by the utility.
A spokesperson for Public Service Company of Oklahoma didn’t directly address the contract talks but said that the utility “works closely with large prospective customers early in the planning process to ensure safe, reliable, and cost-effective electric service.”
Aluminum production has always been closely yoked to electricity prices.
America’s fleet of smelters has shrunk in recent decades as industrial electricity rates steadily climbed, from 33 facilities in 1980 to just four operating plants. Today’s producers still face the same challenge of securing affordable, yearslong contracts. Only now, smelters are increasingly competing with data centers and electrified cars and buildings for a slice of the nation’s limited power supply.
“There’s a future in which American manufacturing in general will have more competition from other sectors for the energy that we need to be successful,” Charles Johnson, president and CEO of the Aluminum Association, said on an April 23 press call. The industry group represents companies that make about 70% of all aluminum and aluminum products shipped in North America.
As it happens, Century Aluminum recently sold an idled Kentucky smelter to a data center company, which will use the site’s existing grid capacity. The manufacturer Alcoa is in talks to sell a shuttered smelter in New York to a bitcoin mining firm as part of its larger plan to offload 10 closed or curtailed sites to the tech industry.
In the last year, the Trump administration has attempted to reverse America’s aluminum decline by slapping steep tariffs on imported metals. But while tariffs can boost the bottom line for some domestic primary producers, Johnson said the measures don’t contend with the underlying energy issues that smelters must first overcome. (In fact, Trump administration policies have made it harder to deploy the fastest and most cost-effective resources for expanding grid capacity: utility-scale wind and solar projects.)
For now, the Aluminum Association’s members have been able to adapt to the rising commodity prices and supply chain disruptions since the U.S. and Israel waged war on Iran in late February. Iran subsequently bombed the two biggest smelters in the Middle East: EGA’s Al Taweelah site in Abu Dhabi and Aluminium Bahrain’s smelter. The Gulf region accounts for about a fifth of primary and alloyed aluminum imports to the U.S.
Still, Johnson said, “We do think that as the conflict drags on and the strait stays closed, that the impacts on our supply chains could be more profound.”
The Oklahoma smelter, despite its massive size, will cover only a fraction of America’s demand for primary aluminum, which totals around 5 million metric tons a year — or nearly four times the combined capacity of the new and existing smelters. To reduce its reliance on imported aluminum, the U.S. will need to build multiple new smelters. That likely won’t happen without federal policies that usher more affordable, reliable electricity onto the grid, said Joe Quinn of SAFE, which advocates for policies to enhance U.S. energy security.
“The aluminum problem will be solved with an energy solution,” he said.
In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.
Lightshift Energy is constructing a second battery project for the city of Danville, Virginia. (Sanjay Suchak)
In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.
Virginia — the world’s data center capital — is starting to catch on to the big-battery trend. But a new project by local electric providers in the state underscores that much smaller storage projects have value, too: They’re designed to fill specific community needs and — due to their size — relatively quick and low-cost to build.
The Blue Ridge Power Agency, which serves a string of nonprofit utilities in central and western Virginia, is set to go live this summer with a collection of five batteries of about 5 megawatts each. The systems will help two rural electric co-ops and the city of Salem’s utility save money by storing power when it is cheap and abundant. They can then rely on that saved-up power when high demand on the grid spikes prices.
All in all, the projects are predicted to save the member utilities $100 million over the batteries’ 20-year lifespan, addressing long-held local concerns over rising costs.
Lightshift Energy, the storage developer building the five batteries, has formed a bit of a niche working with small, member-owned utilities, said Rob Greskowiak, the company’s chief commercial officer.
These nonprofit utilities are rooted in their communities and intimately familiar with their customers and grids, Greskowiak explained. “These municipalities are like, ‘Listen, I know the 50,000 people that live here, and I know that this distribution circuit is not reliable and that our energy costs are going up,’” he said. At Lightshift, “we can find a very acute problem and solve it with 5- to 30-megawatt-sized batteries.”
Small cooperatives’ investment in storage extends well beyond Virginia. As of the first quarter of 2025, 136 battery storage projects sponsored by co-ops were underway or operational in 27 states, according to an analysis by the National Rural Electric Cooperative Association. It predicts that storage deployed by co-ops will more than triple, from 439 megawatts of capacity to 1.5 gigawatts, in the next three years.
The smaller batteries these co-ops tend to favor are cost-competitive because they avoid the need for expensive network upgrades, don’t require expensive long-lead equipment, and are sited on very small footprints, Greskowiak said.
Their minimal impact means they’re often quicker to permit and gain community acceptance than larger versions, he added. “If you’re putting in a battery that isn’t that big in a spot that already has that infrastructure, people aren’t really batting an eye on that.” The company can typically go from initial discussions with a utility to operations in 18 to 24 months, he said, significantly faster than transmission-scale assets.
The rapid setup is particularly meaningful in Virginia as data center plans flood the state and send power-demand forecasts ballooning, said Nikhil Kumar, program director at GridLab, a nonprofit that provides technical support on the clean energy transition in a range of settings. “Speed to power,” he said, “it’s in the zeitgeist right now.”
While reining in power prices is the main motivation behind the Blue Ridge Power Agency’s midsize-battery buildout, Greskowiak emphasized other advantages as well. “Battery storage is best when it acts like the Swiss army knife that everybody talks about,” he said.
A key benefit includes storing electrons from solar and wind and dispatching them when the sun fades or the breeze dies down, enabling even more renewable energy deployment. “Local homeowners, local businesses, local community solar gardens can add to that grid more sustainable energy,” he said, “because we’ve released and unlocked more capability at those substations to host more solar.”
Batteries are also getting cheaper and cheaper, with the average price of a lithium-ion battery pack dropping by nearly 80% over the last decade. And even though President Donald Trump and congressional Republicans slashed incentives for wind and solar last year, they retained the 30% credit for storage well into the next decade. “That’s another big advantage,” Kumar said.
Lightshift Energy’s Danville II project (Sanjay Suchak)
The Blue Ridge Power Agency project is just the latest example of a small Virginia utility quickly deploying batteries. Lightshift has partnered with the city of Danville on two systems that total over 20 megawatts and are expected to save customers $70 million; the first went online in 2022, and the second is under construction. Last year, developers announced two similar-sized projects for a co-op on the state’s Eastern Shore.
Co-ops’ increased interest in storage comes as the state directs its two investor-owned utilities to ramp up investments, too: A law recently enacted by Gov. Abigail Spanberger, a Democrat, requires Dominion Energy and Appalachian Power to build nearly 17 gigawatts of battery storage by 2045; their former target was 3 gigawatts by 2035.
All these planned storage investments will be necessary to ease grid strain and bring down costs, Kumar said. “Especially in Virginia, with the large loads and the data center growth, we’ll need a lot of these projects to help the grid.”
A narrow complaint to a federal energy commission could have wide implications for the solar industry and the electric grid — both in North Carolina, where it originated, as well as nationwide.
At issue is a unique planning scheme that’s been years in the making. Duke Energy, the state’s predominant utility, is moving to proactively upgrade poles and wires to create room for prospective solar farms. Rather than making improvements pegged to specific projects and then charging solar developers for the full cost, as it did in the past, the company is now building in anticipation of future grid needs and spreading the costs among all customers.
In recent years, state regulators have pushed Duke to take this approach to alleviate grid congestion. The company is thought to be the first utility in the country to address local transmission needs in this way, even though it is far from the only one with a long backlog of projects waiting to plug into the grid.
But one set of Duke customers isn’t happy. North Carolina’s electric member cooperatives, which buy most of their power wholesale from the utility, filed a complaint with the Federal Energy Regulatory Commission in February over four grid projects. They argue that the cost of the upgrades — $57 million, in this case — should not be distributed evenly among all customers. Instead, they want solar developers to pay half the total cost.
Many observers believe the protest is on shaky legal ground. Yet FERC is chaired by an appointee of President Donald Trump, who is known to attack renewable energy regardless of the law. The commission is expected to make a decision by the fall, and if it rules in the co-ops’ favor, experts say the ripple effects could be dire.
For one, the solar projects banking on the four grid upgrades could falter if they are forced to bear millions of dollars in new expenses. A ruling for the plaintiffs could also send Duke back to its old transmission planning method — a strategy criticized as costly, ineffective, and hostile to new solar.
“It would be hugely disruptive to the solar industry, but also to the development of the transmission system in the Carolinas more generally,” said Ben Snowden of Fox Rothschild LLP, an attorney for solar developers who isn’t directly involved in the case. “It would be a huge mess.”
What’s more, a decision for the co-ops could set the stage for federal meddling in local grid planning.
“Better-planned transmission will save ratepayers money while providing a more reliable grid,” said Chris Carmody, executive director of the Carolinas Clean Energy Business Association. “This complaint could establish precedent for expensive slowdowns and federal interference in state decision-making.”
Duke’s current approach to network upgrades arose because the old one was failing.
As North Carolina policymakers passed laws to speed the clean energy transition in the 2000s and 2010s, Duke was flooded with requests from developers looking to bring large-scale solar arrays online.
To accommodate these projects, the utility sometimes had to replace lines, poles, and other infrastructure. Whenever that was the case, Duke sought to charge 100% of those costs directly to solar developers. Some paid up and connected to the grid, but others balked and withdrew or were delayed indefinitely.
“Every project was studied, one after the other, and the first project to trigger an upgrade was assigned the entire cost of that upgrade,” Snowden said, even if the improvement made way for lots of other projects to interconnect, too.
“The part of Duke’s system that was most conducive to solar got to the point where it was — in Duke’s view — pretty much at capacity,” he said. Any new generator — solar or otherwise — that sought to interconnect in that area would be tagged with tens or hundreds of millions of dollars of upgrades. “The queue got clogged, and it was stuck for a couple of years.”
Over time, the logjam contributed to a slowdown in renewables. New large-scale solar installations plummeted in 2022, according to data from the Solar Energy Industries Association, falling to about 200 megawatts from a peak in 2017 of nearly 1.2 gigawatts.
The most congested areas on the grid became known collectively as the “Red Zone.” Duke, developers, and other parties deemed over a dozen projects — to upgrade lines, replace poles, and make other improvements — necessary. But the disrepair endured because no one could pay for them.
Then, in 2022, the North Carolina Utilities Commission began to turn the ship. The commission ruled that Red Zone upgrades were “appropriate” and “reasonable.” The projects would enable over 3.7 gigawatts of solar to connect to the grid, commissioners said, while providing “operation and resiliency benefits.”
Crucially, regulators also laid the groundwork for upgrade costs to be shared by all customers, instead of paid for by developers alone. Finally, the commission noted flaws in Duke’s transmission planning strategy and urged the company to “engage with stakeholders” to improve its process.
The company did just that, workshopping the Red Zone projects with interested parties and setting up a scheme to identify future grid needs that would provide multiple benefits.
“Duke — pulled kicking and screaming — has made pretty big strides on modernizing its transmission planning,” said Nick Guidi, senior attorney at the Southern Environmental Law Center. “Kudos to Duke for adopting that process.”
Duke didn’t respond to a request for comment for this story. But the company told FERC that the four contested upgrades were on the original Red Zone list and had been extensively vetted by a range of parties — including the state’s member cooperatives.
The Red Zone projects, Duke wrote, “were identified through years of collaborative local transmission planning … and selected because they provide broad, system‑wide reliability, resiliency, and economic benefits that far exceed their costs.”
The company also noted the projects will “help reduce overall power costs for all users” and even facilitate new gas generation in which the co-ops have partial ownership.
A spokesperson for the North Carolina Electric Membership Corporation, the association of 25 rural co-ops bringing the challenge against Duke, declined to speak to Canary Media for this story.
The co-ops’ complaint doesn’t make clear why they chose to object to the four improvement projects in question — two in Erwin, halfway between Raleigh and Fayetteville; one in Sanford, in the state’s dead center; and one in Camden, just west of the Outer Banks.
But their protest repeatedly states that the improvements are “proactive solar upgrades” that primarily help solar companies. A follow-up filing dismisses systemwide reliability and other benefits asserted by Duke as a “barrel of red herrings.”
The $57 million that Duke has assigned to customers for the four upgrades is a “simple unfairness,” the complaint says. Customers should bear only half those costs, and the co-ops’ share should be reduced from $802,000 per year to $401,000. The rest, they argue, should be borne by solar developers, the projects’ “primary beneficiaries.”
“That’s a really faulty premise,” Snowden said. “That’s like saying that the water pipes that run down my street are for the benefit of the people who sell me water.”
What’s more, clean energy and consumer advocates say, the proactive nature of the Red Zone projects is a good thing — unlike Duke’s old “Whac-A-Mole” approach — and their price tag is appropriately rolled into the transmission fees the utility charges its customers.
“You have to spread the costs out across the broader grid,” said Guidi of the Southern Environmental Law Center, “because they provide benefits to the broader grid.”
Perhaps the $401,000 in savings would trickle down to the co-ops’ 1 million metered customers, representing 2.8 million North Carolinians. But, Guidi said, “It would be a drop in the bucket.”
The impact could be more acute for solar companies, which tend to operate on thin margins. The extra costs could conceivably cause developers relying on the four upgrades to withdraw, Snowden said. However, he added, “I think the bigger danger is: Do you undermine Duke’s willingness to continue with proactive transmission planning?”
The complaint is the first of its kind, making its outlook murky.
“It’s a very big swing from a legal standpoint,” Snowden said. “There are some very serious questions about the relief that they’re seeking, including whether FERC has the jurisdiction to provide this relief at all.”
The five-member commission still contains three appointees from former President Joe Biden, and Trump’s choice for chair is generally considered qualified and conventional.
But when disputes over renewable energy reach a body even remotely touched by the president, all bets are off.
“They’re trying to identify these four lines as solar lines,” Guidi said. “Whether that’s their belief, or whether they are trying to play to a federal administration generally not friendly to solar, that is seen throughout their complaint.”
Furthermore, the petition clearly signals that more challenges could be on the way to Red Zone improvements, as it calls the four upgrade projects “the tip of an iceberg.”
“This is just the start,” Guidi said. “I don’t think they expect it to end here.”
For decades, utilities have used smart thermostats to reduce strain on the grid when electricity consumption is super-high. Paying customers to let utilities turn down air conditioning on hot summer afternoons or electric heating on cold winter mornings is called demand response, and it’s delivering gigawatts of valuable grid relief today.
Phoenix’s Ahwatukee Foothills neighborhood is served by the utility Salt River Project, an early mover in tapping smart thermostats to reduce pressure on the grid. (Hunter Trick [Trick Hunter], CC BY-SA 4.0 via Wikimedia Commons)
But millions more of these smart thermostats are shifting households’ temperatures on a daily basis — and not on behalf of utilities. Instead, the owners of these devices have agreed to let smart thermostat companies modify their temperature settings to avoid costly peak power rates, or to use more clean energy and less dirty energy.
While this energy shifting has largely been invisible to them, some utilities are now gathering data on how these under-the-radar systems could be leveraged to avoid costly infrastructure upgrades or to burn less fossil fuels. Put simply, the more smart thermostats that utilities can recruit to lower peak demand, the less they have to run dirty power plants and the fewer wires and poles they need to transport electrons.
Big Arizona utility Salt River Project is one early mover on this front. Last year, it worked with smart thermostat firm Renew Home to see how thousands of the company’s thermostat-equipped customers in and around the Phoenix area could reduce strain on the grid. Those thermostats belonged to households that opted into Renew Home’s Energy Shift program, which lets the company automatically adjust their temperature settings throughout the day. Nationwide, about 5 million customers representing 4 gigawatts of capacity have signed on to that initiative.
The tracking effort revealed that customers enrolled in Energy Shift are easing peak grid pressures nearly as effectively as those enrolled in the utility’s smart thermostat demand-response program.
Over the course of six test events last August and September, about 28,500 Energy Shift–enabled homes each delivered about 1.1 kilowatts of peak load reduction on average, for a total of about 27 megawatts, Josh Logan, Salt River Project’s senior product manager, said during a March webinar.
That’s not quite as much energy reduction as the average 1.3 kilowatts per thermostat that Salt River Project gets from the roughly 75,000 customers enrolled in its standard demand-response program, he said. But an additional 27 megawatts of peak relief happening more or less automatically is nothing to sneeze at, he added.
It’s worth pausing to note the trickiness of comparing customer load-reduction programs like Energy Shift to typical utility demand-response initiatives. Utilities and regulators have always thought of demand response as something that happens during emergencies to directly alter how customers would have otherwise used energy. Utilities want to see a direct reduction in energy demand from some typical baseline.
Energy Shift’s frequent tweaks to millions of household thermostats upend those benchmark expectations, said Will Baker, Renew Home’s senior director of market integration. To measure the impact of its test events in Arizona and elsewhere, the company uses randomized control trials that pull data from a broad range of customers to determine a baseline, he said.
The company’s results are prompting Salt River Project to examine the idea of offering Energy Shift customers incentives for expanding how often or deeply they’re willing to shift their energy use. While the utility isn’t disclosing what financial arrangements it might be working out to more reliably tap into those smart thermostats in the future, Logan expected the results would be “extremely cost-effective” for the utility.
Renew Home worked with the company EnergyHub to reveal this particular data to Salt River Project, free of charge. The utility already uses EnergyHub’s online platform to manage its existing demand-response programs, and the smart thermostat data from Renew Home was rolled into the tool to allow an easy viewing experience.
Arizona isn’t the only place where EnergyHub and Renew Home are collaborating to surface the value of what they call “background virtual power plants” — networks of distributed energy resources that operate with no utility management.
During Winter Storm Fern in January, for example, the two companies found that Energy Shift customers reduced load for an unnamed Southeast U.S. utility by 50 megawatts, said Megan Nyquist, EnergyHub’s senior product market manager. That’s about twice as much winter peak reduction as that utility has enrolled in its official smart thermostat demand-response program, she said.
“Utility programs will continue to be a huge part of how [virtual power plants] grow and scale. But they’re not the only source of flexible capacity out there,” Nyquist added.
Last summer, Renew Home reported that it was able to provide 380 megawatts of load reduction over two hours on a hot July afternoon in the territory of PJM Interconnection. PJM faces a cost crisis in meeting its peak demands for the grid it manages for more than 67 million people in 13 states and Washington, D.C.
Tyson Brown, Renew Home’s head of utility partnerships, noted during the March webinar that this achievement came from “only a fraction of the available fleet. If we actually dispatched the entire Energy Shift–enabled fleet in PJM, the impact would have been closer to 800 megawatts.”
One important advantage of Energy Shift’s day-to-day adjustments is that they are generally less disruptive to household comfort than traditional demand-response programs, Brown said. Utilities that ask customers to shiver through the coldest mornings or swelter through the hottest afternoons struggle to keep households enrolled.
“The goal here is for it to really be imperceptible, such that the end user feels as if the thermostat is doing the things that it’s already been doing for them,” he said, noting that customers are always free to cancel their participation if they want to.
Paying consumers to use less energy during times of peak demand can help save all utility customers money in the long run, Baker noted. That’s because utilities pass on the costs of building and operating power plants and grid infrastructure to meet peak loads on to all customers as a portion of their utility rates. Anything that utilities can do to reduce those costs can eventually lead to lower rates across the board.
Renew Home is a member of the Utilize Coalition, a group of companies promoting virtual power plants as a means of reducing rising utility bills. Baker declined to name other utilities that might be considering methods to pay Energy Shift customers for committing to reduce peak energy use. But he did say, “We’re going into our preseason planning with our utilities — and there’s not a single utility we’re not talking with about this.”
Enormous new batteries keep appearing on the grid, making it devilishly tricky to keep track of which is the biggest in a given region. That’s certainly the case in New England, where acute power needs and robust state climate goals are fueling a buildout of big batteries that keep breaking capacity records.
Canary Media recently covered the inauguration of the 175-megawatt Cross Town battery in Gorham, Maine, which was the largest in New England when it began operating in late November. But that trophy has already passed to a 250-megawatt facility in Medway, Massachusetts, southwest of Boston and about 10 miles from the Patriots’ Gillette Stadium.
The Medway battery came online fully Feb. 25, according to developer VC Renewables, a subsidiary of global energy trader Vitol.
“To be fair, I don’t expect Medway to hold that title for very long, either,” said Tom Bitting, managing director at Advantage Capital, which supported the project with a $158 million tax equity deal. “There are other batteries being developed in New England that are bigger, but I think it is all just a sign that we need all of it, and there’s huge demand for it.”
For instance, Jupiter Power, a heavyweight in Texas’ booming grid storage market, is developing the 700-megawatt/2.8-gigawatt-hour Trimount battery plant at a former oil-storage site in Everett, Massachusetts, just north of Boston. Jupiter aims to finish the project in 2028 or 2029. Trimount is slated to be among the largest stand-alone batteries in the whole country — Vistra’s battery in Moss Landing, California, set that record with 750 megawatts/3 gigawatt-hours, before much of that capacity burned up in a disastrous fire.
The wave of battery megaprojects marks a new chapter for the region, which until recently was focused on building small-scale batteries. Massachusetts encouraged this by requiring energy storage alongside many distributed solar projects that received payments through the state’s main solar incentive; this rule led to a buildout of systems in the range of 1 to 5 megawatts.
Bigger batteries started taking off in the late 2010s out West: in California, Arizona, and Nevada, where developers can sign long-term contracts to deliver grid capacity; and in Texas, where they can bid into a uniquely competitive market.
The first three big batteries in New England — Plus Power’s Cranberry Point and Cross Town, as well as Medway, which was previously developed by Eolian — won seven-year contracts in 2021 to provide capacity for the New England grid, but the grid operator subsequently shortened that kind of contract to one year. After that change, developers have struggled with the lack of long-term capacity revenue; they can still charge up when prices are low and sell when they’re high, but that’s an unpredictable revenue stream that financiers might not want to underwrite.
Massachusetts has succeeded in building a robust fleet of small-scale solar — on recent sunny spring days, it has generated close to 50% of the region’s demand. But leaders knew they needed batteries to keep cleaning up the grid in the hours when solar doesn’t produce. So they created a new policy driver for storage investment called the Clean Peak Standard, which officially took effect in 2020.
The rule orders utilities to serve a percentage of their peak-demand hours with clean electricity, and the target grows with each passing year. Companies that use batteries to save solar energy for the evening — when electricity consumption rises as people get home from work and school — earn credits that they can sell to utilities, providing some revenue certainty outside the wholesale market.
The administration of Gov. Maura Healey, a Democrat, views storage as a key lever to improve energy affordability, Undersecretary of Energy Michael Judge said, because it makes better use of existing grid infrastructure to meet peak demand.
“Store all that solar energy that we’re producing in the middle of the day and bring down the cost of operating the system for everyone,” he said. “You don’t have to run these peakers, and you get all the emissions benefits and integration of clean energy benefits, too.”
It took several years for the rule to actually spur batteries in the multihundred-megawatt range, but now that era has begun. Advantage Capital, for example, factored in revenues from the Clean Peak Standard when it analyzed and underwrote the investment in the Medway project, Bitting noted. A total of 725 megawatts of battery storage had qualified for the Clean Peak Standard as of early March, according to state data.
Stand-alone grid battery projects are also bolstered by a federal tax credit that can cut investment costs by 30%, an incentive that the Trump administration preserved in last summer’s budget law even as it slashed support for wind, solar, and electric vehicles.
Clean Peak cash alone doesn’t pay the bills; battery developers still need to make money in the marketplace. Though New England lacks long-term capacity contracts, storage companies in the region have at least two factors working in their favor: some of the nation’s highest electricity prices and growing demand for power.
“It’s very difficult to get additional generation online in an area with high population density, because regardless of what type of power generation you’re building, it requires a lot of space,” Bitting said. Batteries, though, can fit a lot of power into a relatively small footprint, without the smokestacks or pollution that make it hard to build new fossil-fueled plants in populous areas.
Batteries compete directly with gas power plants to serve the peak hours of demand, when prices are highest. That’s especially valuable in New England, where gas supplies are stretched thin between power generation and home heating on the coldest days of the year.
“When it’s cold, the households are going to continue to demand it,” Bitting said. “But if we can ease some of the peak on the utility side, that will provide a relief valve to supply.”
Jupiter Power’s colossal Trimount project will continue New England’s foray into large batteries, with the ability to discharge enough power for roughly 500,000 homes, per the developer. Trimount was the largest of four battery projects selected in December from Massachusetts’ statewide solicitation to bring on more Clean Peak power. Previously, battery owners could sell off their Clean Peak credits on a quarterly or annual basis. The new solicitation was designed to produce “cost-effective” long-term contracts for storage, giving developers more stable revenue to plan around. Furthermore, Healey doubled down on grid storage in a March 16 executive order that calls for another 5 gigawatts installed by 2035.
“That kind of policy signal, combined with the state’s grid reliability challenges and its decarbonization commitments, creates the conditions for investment at scale,” Hans Detweiler, senior director for development at Jupiter, said in an email.
Massachusetts officials also hope to speed development with new permitting rules, which run large battery applications through a state-level body instead of piecemeal local processes. Community members still get to weigh in, but the program has a clear 15-month timeline and allows just a single appeal to the state Supreme Court, to ensure a more timely resolution of conflicts in the permitting process.
The true test of all these policies will be whether the recent megabatteries kick off a trend, or remain bold outliers in the region’s energy system.
After years of negotiations, data centers and other large customers of Georgia Power have finally won a pathway to pay for their own new clean energy projects to be built and connected to the utility’s grid.
The Georgia Public Service Commission approved the utility’s program last week, allowing these companies to identify and commit to paying for solar, battery, and other renewable-energy projects to supply their own power needs.
If it works as planned, the new customer-identified resource, or CIR, program could help prevent data center growth from raising power bills for Georgia Power’s customers at large — and offer a template for other utilities and regulators wrestling with similar issues nationwide.
Georgia Power is planning one of the largest new fossil-fuel buildouts in the country. Over the next five years, the utility wants to build nearly 10 gigawatts of new capacity resources, roughly 60% of which would come from natural gas power plants. The utility says it needs this new capacity to keep the grid running as power-hungry data centers flood into the state.
Those new power plants may be justifiable if the proposed data centers get constructed and keep operating long enough for the utility to recoup the costs through electricity sales. But if the AI bubble deflates, as more and more industry observers fear will happen, then the cost of paying off those utility investments could fall on everyday customers.
Programs like CIR are meant to protect customers at large from that worst-case scenario as well as from upward pressure on utility rates linked to data centers.
Its effectiveness on that front will depend on whether it results in Georgia Power building a smaller amount of electricity infrastructure than it’s currently planning on through its normal processes, thus reducing cost burdens on customers.
But that effectiveness will be hard to measure, given how the program is designed. Under the program, Georgia Power does not have to include any CIR projects in its long-term grid planning. If regulators don’t rectify that and force the utility to incorporate those projects into its plans, it may wind up adding gigawatts of unnecessary power plants in addition to whatever clean energy moves through the new program. Customers at large would foot part of the bill.
This issue will likely come to a head in Georgia Power’s next integrated resource planning process — the sprawling regulatory proceedings aimed at determining how much power, and what mix of resources, a utility needs to develop or maintain to meet its future needs.
Still, the unanimous vote approving CIR indicates that state regulators want Georgia Power to “work with large loads on the system in a way that manages cost shifts and concerns related to affordability,” said Nidhi Thakar, senior vice president for policy at the Corporate Energy Buyers Association (CEBA), the trade group that negotiated with the utility to create the CIR program.
CEBA includes major hyperscalers — like Amazon, Google, Meta, Microsoft, and Oracle — that signed a “ratepayer protection pledge” at the White House last month, promising to limit the risk that their data center expansion plans will increase everyday utility customers’ electricity rates. But most of the actions that could actually fulfill that pledge will rely on efforts from individual states and utilities, energy experts say — such as the CIR program from Georgia and Georgia Power.
“These large customers are willing to put down capital on the front end and take on the risk” to build the clean energy to supply significant portions of their demand, said Katie Southworth, CEBA’s deputy director for market and policy innovation in the South and Southeast. “This program opens up the procurement pathways.”
Starting this summer, large commercial and industrial customers in Georgia Power’s territory can use CIR to seek out and work directly with independent developers of solar, wind, battery, geothermal, and other carbon-free energy projects, Southworth said.
That’s a first for Georgia Power. As with many utilities in the Southeast and Midwest, it is vertically integrated, meaning it has exclusive rights to contract for power plants. The utility already lets big customers subscribe to clean energy projects that Georgia Power selects and contracts with, but it hasn’t previously allowed customers to bring their own specific clean energy projects to the table.
States without vertically integrated utilities let independent power producers contract directly with big customers. Big power users, and tech giants in particular, have taken advantage of this arrangement where available. U.S. corporate clean-energy procurement surpassed 130 gigawatts of new generation capacity between 2014 and 2025, according to the latest CEBA data. That’s roughly 44% of all new generation capacity built in that time, CEBA told Canary Media.
Under the CIR option, these large customers still won’t directly purchase energy from the projects that they have identified. Instead, they will pay Georgia Power a monthly tariff designed to cover the projects’ construction and operating costs, plus a reasonable rate of profit for the projects’ owners, in an arrangement CEBA likens to a “sleeved power purchase agreement.”
Solar and batteries will probably make up the lion’s share of that new CIR capacity, given that more than 20 gigawatts of those resources are being developed and seeking interconnection in Georgia, according to data from the Southern Renewable Energy Association trade group.
Solar and batteries are also the cheapest source of new generation capacity available nationwide, which could drive lower energy costs for the big customers contracting for it and for Georgia Power customers at large. Together, solar and batteries are expected to account for nearly 90% of new energy capacity built nationwide this year.
Under the CIR structure, if the power from these projects is cheaper than the equivalent cost of power generated and delivered by the utility, 75% of the resulting savings will go to participating customers, while 25% will be shared with other Georgia Power customers, Southworth said.
That could help get large-load customers — namely AI data centers — the massive amounts of energy they need without increasing utility rates for customers at large.
Georgia Power’s previous renewable-procurement structures have helped “diversify our generation mix and increase reliability,” Wilson Mallard, the utility’s director of renewable development, told Canary Media in an email. Adding CIR to those existing structures “offers the opportunity for the procurement of additional renewable resources at competitive prices to meet customer needs,” he said. “We expect these projects will provide energy and capacity benefits to the system value for all Georgia Power customers.”
CEBA fought for some key features that made it into the final CIR program approved by Georgia regulators last week.
For one, Georgia Power removed a contentious provision that would have allowed the utility to terminate CIR contracts at any time and without penalty, Southworth said.
Additionally, small commercial and industrial users of power can now band together to collectively achieve the 3-megawatt minimum required to participate, Southworth noted. That could expand options for retail chains, hotels, local businesses, or local governments to secure their own clean energy resources. And customers will be allowed to transfer in and out of those arrangements, which allows for more flexible participation.
But CEBA wasn’t able to secure one feature it had wanted — a way for CIR customers to earn credits for the capacity value of the projects they bring online. Capacity is how utilities measure the impact that power plants, solar and wind farms, batteries, and other resources have on meeting the peak demands on their grid.
Those peak demands are important because they determine how much generation and grid infrastructure that utilities ultimately build. What’s more, large utility customers typically have to pay demand charges, which are based on how much power they use during those handful of hours when electricity use hits its upper limit.
The CIR program’s monthly tariff is an energy-only tariff. That means participating customers won’t be able to reduce their demand charges on the basis of the projects they’ve enabled to be built under CIR — even if that infrastructure helps Georgia Power reduce its peak demand.
But sooner or later, Georgia Power and its regulators will need to consider how to capture the grid value these CIR projects provide.
That’s likely to play out in the utility’s future integrated resource planning, Southworth said. “When we get to the next IRP, I’m confident there will be some resources — solar and storage — that will be brought on” under CIR, Southworth said. “Those will be resources on the Georgia Power system, and through that modeling, they will absolutely show up” as part of the capacity calculations.
The question then will be whether that newly unveiled CIR capacity will alter Georgia Power’s current power plant expansion plans, which were approved in December through a regulatory process that has unfolded largely outside the utility’s standard IRP proceedings. Georgia Power and regulators justified this approach to deal with a massive increase in the utility’s forecasts of how much power and capacity it will need to supply in future years, which have surged from 400 megawatts in 2022 to 6.6 gigawatts in 2023 to 8.5 gigawatts in 2025.
But environmental groups, consumer advocates, and others say Georgia Power’s latest expansion plan for gas power plants and batteries allows the utility to overbuild for a data center boom that may fail to emerge. Georgia Power will be able to earn guaranteed levels of profit on the $16.3 billion in “company-owned projects” in that plan, giving it an incentive to overestimate its power needs.
Last month, a group of environmental and faith groups brought a legal challenge against the decision. “The commission still has to apply its rules to protect its ratepayers from overbuilding,” said Isabella Ariza, a staff attorney with the Sierra Club, one of the groups filing the legal challenge. “And we think those rules are the only protection that ratepayers have at this point.”
Ariza noted that the final version of the CIR program wasn’t yet posted by the Public Service Commission, which limited her ability to discuss how the resources brought online under the program might impact future capacity planning.
Even so, “in future IRPs, Georgia Power would have a hard time theoretically explaining to the commission why the clean resources shouldn’t offset some of the peak demand,” she said. “But we’ll see.”
A correction was made on April 15, 2026: This story originally misstated that Georgia Power has exclusive rights to build and operate generation in its service territory. In fact, the utility also contracts with third-party solar and battery projects under its CARES program.
In western Illinois, ComEd is tapping a rarely used technique to fast-track community solar installations — working with, not against, environmental groups and solar project developers.
For years, utilities have explored the concept of flexible interconnection, in which solar projects are allowed to come online even when, by the books, there’s not enough space on the grid for these arrays. In return, these solar farms must promise to curtail output during the handful of hours each year when their production would overwhelm power lines and substations.
Flexible interconnection is a speedy way to get cheap new solar online without requiring utilities to spend even more on costly grid upgrades, which are a key driver of the nation’s fast-rising utility bills.
But U.S. utilities haven’t made use of the technique at any significant scale — until ComEd got its program off the ground late last year.
Since then, the utility has fast-tracked more than 50 megawatts of community solar projects using flexible interconnection, and more are likely to be approved before federal tax credits sunset in July.
That’s much faster than utilities in other states have been able to move on flexible interconnection, said Samantha Weaver, senior director of interconnection and grid integration policy at the Coalition for Community Solar Access, a trade group representing community solar developers. In fact, ComEd is “leading the country right now,” she said.
ComEd plans to accelerate that work, said Jessie Bauer, the utility’s senior manager of smart grid and innovation. “Our plan was to do 50 megawatts a year, and we’re hitting that cadence,” he said. “We’re proposing in our grid plan to go even faster, and do 100 megawatts a year, and get to 650 megawatts by 2031.”
The utility has previously committed to deploying 240 megawatts of distributed energy capacity by 2030 to meet its requirements under Illinois’ landmark 2021 climate law.
ComEd was able to succeed where other utilities haven’t thanks to a nudge from regulators that spurred it to collaborate with solar developers and environmental groups.
Historically, utilities and solar developers have struggled to establish the basic mutual trust required to move a flexible interconnection program forward, Weaver said. Utilities are often skeptical that solar farms will reliably cut back as promised during those key hours of potential grid overload. Meanwhile, solar developers suspect utilities will force them offline more than is absolutely necessary.
Illinois’ flexible interconnection process didn’t go that way.
Instead, in 2024 ComEd collaborated with environmental groups represented by the consultancy Eclipse on a flexible interconnection plan. Then, the utility worked out mutually agreeable solutions with those groups, solar developers, and the nonprofit collaborative the Charged Initiative, in a series of workshops that resulted in a program design that gave each side enough of what they needed to move ahead.
Both the utility and solar developers had to make some compromises, Weaver said. But that effort bore its first fruit last November, when 27 megawatts of community solar was green-lit in a region where it would have been excluded by traditional processes. Another 25 megawatts of projects were approved in February.
This coordinated approach is now gaining some momentum in Maryland, Massachusetts, New York, and other states where community solar is struggling, said Nikhil Balakumar, Eclipse’s CEO and founder.
“Now, more than ever, especially in this climate, we need unprecedented collaboration,” Balakumar said. We can’t just slog it out and fight and litigate every little thing till the end of time. There has to be a new way forward.”
ComEd’s push into flexible interconnection was less a choice than a necessity.
Since 2016, Illinois has created and expanded programs that offer lucrative incentives to build community solar projects, which are generally limited to no larger than 5 megawatts. Households can subscribe directly to these projects, which often allow them to lock in cheaper, cleaner energy. The state’s programs are explicitly meant to reduce utility rates for low-income customers.
In Illinois, developers have flooded into the programs over the years, snapping up the most suitable land for community solar arrays.
This posed a problem for ComEd: Everyone wanted to build their solar arrays in the same relatively concentrated geographic area — the rural western reaches of its territory — where there simply wasn’t enough space on the grid.
“We quickly saw all that grid capacity evaporate with the community solar being connected,” Bauer said.
In a situation like this, the standard utility playbook is to require community solar developers to shell out for grid improvements. In western Illinois, that would mean multimillion-dollar system upgrades, he said — a cost that few solar developers can afford.
However, the grid actually does have the space to accommodate those solar farms — at least, most of the time.
Distribution grids are built to serve the times when electricity demand is at its highest. These peaks in demand are relatively rare, happening only during a handful of hours per day, or days per year. That means for the vast majority of the year, there’s unused capacity sitting there.
Flexible interconnection takes advantage of this fact — and helps developers and consumers avoid exorbitant grid upgrade costs as a result.
“If you can give up some of your energy during times of system constraints, you can interconnect much more affordably,” Bauer said.
But this is easier said than done. Utilities can’t perfectly predict how often demand will peak. They need flexibility to handle unexpected changes and respond to emergencies. A major storm or flood could knock out an entire substation for months, leaving other parts of the grid straining to supply power until it’s repaired.
That uncertainty constrains utilities from setting guaranteed limits on how often they’ll ask solar projects to curtail their generation. But for solar developers, “projects aren’t financeable if curtailment is unpredictable,” Weaver said. “We need certain details to be able to literally take to the bank.”
To resolve this conundrum, ComEd and solar developers collaborated on a compromise.
Solar developers calculated that they — and their investors — could bear having about 5% of their annual solar production curtailed. They conceded that ComEd couldn’t guarantee it would stick to that curtailment limit. But if the utility was willing to share historical data on how often its grid was likely to face overloads, developers could use that to convince those investors that the risk was worth taking.
That wasn’t the solar industry’s initial ask, Balakumar noted. Solar developers started out asking for “some sort of fund that compensates us if you do go over 5%,’” he said. But ComEd pays for the power it purchases by passing those costs on to its customers — and the prospect of charging customers for power that didn’t actually get onto the grid was a nonstarter for consumer advocates and regulators.
“We went in wanting a guarantee,” Weaver said. “But we came to the understanding that that wasn’t realistic and that we needed to give up a degree of certainty.”
Nor was it easy for ComEd to agree to sharing confidential data on its substations. Bauer said that process was helped along by community solar developers limiting what data they needed and how they would use it.
Already, the real-world data coming in from ComEd’s flexible interconnection projects could allow it to tighten curtailment expectations for future rounds of development, Bauer said. That could make community solar projects more lucrative to financial backers — and given that the alternative was to not be able to build them at all, or to wait for years for utility grid upgrades to plug them in, that’s better than nothing.
Regulated utilities like ComEd earn profits from the investments they make to expand or upgrade their power grids, not from connecting third-party solar projects. If anything, flexible interconnection exposes them to grid instability risks. Meanwhile, sharing data on how efficiently they utilize their grids can weaken the case for investing in moneymaking upgrades.
But in Illinois, policymakers and regulators forced ComEd’s hand.
Under the 2021 Clean Energy Jobs Act, ComEd and fellow utility Ameren Illinois must invest in their grids to improve customer affordability and meet state climate and clean energy goals. In 2023, the Illinois Commerce Commission rejected the initial grid modernization plans filed by ComEd and Ameren Illinois, because of critiques including an absence of commitments to streamline interconnection of distributed energy resources like community solar systems.
That’s when Eclipse started working with the Environmental Law and Policy Center, the Environmental Defense Fund, the Natural Resources Defense Council, the Union of Concerned Scientists, Vote Solar, and other groups to get ComEd to the planning table, Balakumar said. The following year, these groups agreed to a memorandum of understanding with ComEd, which led to the joint plan submitted to regulators in late 2024.
ComEd then set up that workshop series with solar developers and environmental advocates over the course of 2025. That’s where parties hashed out their positions and came up with compromises that they could live with, Weaver said.
“To give credit where credit is due, the utility came with a lot of information and proposals they’d developed in advance for developers,” she said.
That included detailed information on the capabilities — and limits — of the utility’s technologies to make flexible interconnection possible, Bauer said. For example, one solar developer asked for hour-ahead forecasts of when the utility would curtail projects, he said. “We can do that in the future — in fact we plan to,” he said. But if ComEd had been forced to wait until it could warn solar projects that they would be curtailed an hour in advance, “we wouldn’t have launched this year — we would have launched in a year or two.”
ComEd also chose not to immediately incorporate all the different distributed energy resources that state law requires it to eventually handle, he said. “We were deliberate and focused on community solar, because we recognized that those were not only where the need was, but because those are the most technically sophisticated customers.”
The flexible and collaborative approach that ComEd and solar developers have undertaken stands in contrast to some much slower processes in other states. In California, for example, it took nearly four years between regulators ordering utilities to make flexible interconnection possible and finalizing the rules that allow it to happen — and California still hasn’t created a workable community solar program to make use of those rules.
But speed is of the essence as community solar developers rush to start their projects before July. That’s the deadline for achieving “safe harbor” status for earning tax credits set by the massive tax and spending package passed by Republicans in Congress last year. “Because of these changes happening in the tax credits, we realized we needed to move faster,” Bauer said.
Balakumar agreed that “to go from March workshops to a full-blown program in November for a utility is lightning speed.” But regulators and utilities in states with clean-energy and climate goals that haven’t moved as quickly are setting themselves up for even greater costs — and arguments over who’s going to pay for them — once the window for securing federal tax credits has closed, he said.
That’s not to say that other states can’t still learn from Illinois, he said. Take New York and Massachusetts, two states where Eclipse is closely involved in flexible interconnection work.
“We were in workshops in New York with Avangrid and National Grid,” two utilities serving upstate regions with a lot of community solar and grid constraints, Balakumar said. There, solar developers are “talking to banks and thinking about how they can get much more creative.” In January, National Grid filed a proposal to enable flexible interconnection at seven substations, each potentially hosting 30 to 60 megawatts of new projects.
And in Massachusetts, where utilities have struggled for years to connect more community solar projects, Eclipse has been involved in a workshop jointly hosted with a state regulator–created interconnection working group, with the goal of jointly filing flexible interconnection proposals with National Grid and Eversource “as soon as possible this year,” he said.
Those utilities are actively expanding their grids to accommodate more community solar. But flexible interconnection could allow many projects to connect while deferring $239 million in proposed upgrades, Balakumar said in November 2025 testimony in a proceeding reviewing new grid investment proposals.
In March, ComEd engineers came to a Massachusetts flexible interconnection workshop to share their experience, according to Nick Burica, senior director of grid planning and interconnection engineering at community solar developer Nexamp.
Utilities have plenty of reasons to be leery of requests to operate their grids in this new and unfamiliar way, noted Burica, who previously led development of distributed energy engineering for ComEd. But when those kinds of objections arose, ComEd was “in the room,” able to say that “it will provide energy affordability, and you’ll be able to operate your system better,” Burica noted.
“I was so happy to see ComEd come out and champion what can be done with flexible interconnection,” he said. “Getting people together — industry, utilities, and outside consultants — we’re starting to see the fruits of this labor.”
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