Battery storage is being deployed at record levels in the U.S., but the growth is concentrated in just three states: Texas, California, and Arizona. Those states combined accounted for 74% of all the 16 gigawatts of utility-scale capacity installed in 2025, according to the Solar Energy Industries Association’s first storage market report.
That means Eastern and Midwestern states are lagging behind, and aren’t enjoying the range of benefits that battery storage provides the grid, including absorbing the often cheap, excess power available during midday slumps; being on standby to turn on quickly during an emergency; and curbing wild price swings during peak demand.
A major problem is that market rules in several regions don’t value all those ways battery storage can serve the grid, according to research by GridLab and interviews with industry experts. If battery operators can’t get paid for a range of services — also known as revenue stacking — then expensive new projects won’t necessarily pencil out for investors. That, combined with the backlog in interconnection queues, is constraining growth.
“In several RTOS that are lagging behind their peers, storage can’t fully stack its operational capabilities and services,” Noah Roberts, executive director of the Energy Storage Coalition, a trade group that represents battery manufacturers, developers, and operators, told Latitude Media. “That’s like saying, ‘We’ll let you connect your resource, but we’re only going to value 25% of what it can do.’ That’s a significant barrier to deploying storage.”
The slow pace of building battery storage in markets like PJM, MISO, and SPP means higher costs for ratepayers and a less reliable grid, according to industry research. That contributes to political risk for everyone from the White House and Congress to state and local governments, especially at a time when energy affordability is a major concern of voters.
President Donald Trump has taken several steps to try and spur new generation and curb costs, including by encouraging tech companies like Amazon, Anthropic, and Microsoft to pay for powering their new data centers. The White House is expected to hold a meeting on Wednesday with the companies to sign a pledge saying as much. Trump in January also directed PJM to hold a capacity auction just for data center developers to sign 15-year contracts for new generation — as opposed to the typical one-year capacity contracts.
That intervention in PJM by the White House and several governors across the region has created even more uncertainty in a market that is already struggling to attract investment in storage. (It’s unclear whether that auction would include battery storage.)
Proponents of battery storage argue that if grid operators are going to solve a power crunch and alleviate some of this uncertainty, storage is the quickest path. Some systems can be permitted and brought online within six to 12 months, according to the GridLab report.
“I think that it is very obvious to anyone who is running an ISO right now that the only way that they’re going to get out of their predicament over the next three years is batteries,” Jigar Shah, co-host of the Open Circuit podcast, said on the latest episode. He added that if PJM, MISO, and SPP are looking for speed to power, batteries are one of the cheapest ways.
Some projects are getting built in those regions, of course. But developers are taking on a lot of risk to do so, said Aaron Zubaty, CEO of Eolian Energy, whose primary investor is a fund by BlackRock Global Infrastructure Partners.
Developers don’t have clarity on forward revenue curves for battery storage over the long-term, in part because there’s ongoing debate over how to construct capacity market revenue and how to serve large data center customers, Zubaty said. Grid operators are also undervaluing storage services, which makes them a tough sell for bankers who are looking for stable revenue.
For now, Eolian is building battery storage in PJM and MISO on its own balance sheet and then securing individual revenue agreements with offtakers like data centers. This includes a 200 MW project outside of Columbus, Ohio that Eolian said will be the largest in PJM when fully operational in the spring of 2027.
“Not many people can do that,” Zubaty said. “You have to have the risk appetite, but you also have to have the equity that you can invest to build a new battery storage facility based on the premise that growing demand for solutions to enable new large loads will dwarf available supply for the foreseeable future.”
The storage gap
Nationwide, industry analysts said the pace of battery storage deployment is too slow given the face of rising U.S. energy demand and prices for consumers.
PJM needs to build at least 16 GW of storage by 2032 to meet demand in the region, primarily from data centers for artificial intelligence, according to an analysis by the Brattle Group and commissioned by the Energy Storage Coalition last year. Falling short of that target could lead to 34% higher electricity costs and increase the risk of rolling blackouts. PJM had about 40 megawatts of storage capacity installed in 2025, orders of magnitude less than what’s needed.
Meanwhile in MISO, deploying more than 10 GW of storage between 2025 and 2035 could help the region save more than $4.5 billion, an analysis by Aurora Research and commissioned by the American Clean Power Association found. And in SPP, a “modest” deployment of 5 GW of energy storage during that same time period could save the region more than $2 billion, the research showed.
MISO and SPP had deployed only 62 MW and 13 MW of storage capacity, respectively, in 2025.
By contrast, Texas has rapidly scaled to more than 14 GW of capacity — which proved to be critical during Winter Storm Fern in January.
Market reforms
ERCOT runs a deregulated energy market, where prices reflect more real-time supply, demand, and transmission conditions. That means battery storage can respond within seconds to economic signals and get paid for the services provided. Meanwhile CAISO, a regulated market, values a wide array of batteries’ grid services, GridLab researchers found.
In other words, battery operators are able to earn via multiple revenue streams, including from energy arbitrage, capacity value and resource adequacy, and ancillary services. That isn’t the case in PJM, where battery operators can be penalized for responding in real-time to critical events if they were already scheduled to be delivered in a different window, Roberts said.
“Battery storage has flexibility that no other resource is really capable of providing, so it’s just a matter of PJM rewriting some of their rules to accommodate this new technology,” he added.
Both PJM and MISO are working on changing market rules for storage. PJM in a January notice said it was reviewing how it manages and compensates batteries, although that effort doesn’t cover resource adequacy. Market changes could be drafted within a little as nine months — a tight timeline as PJM works on a slew of other reforms, including to its interconnection queue.
MISO, for its part, has also started a review of how it values battery storage, acknowledging that batteries can absorb excess power that otherwise would be wasted and respond to peak demand. It is also one of the few regions implementing a model where a battery can be built instead of a power line to help ease congestion on local distribution grids.
Roberts sees signs of progress in MISO, and pointed to a project in Michigan that he thinks foreshadows what’s to come. The utility DTE Energy is undertaking an aggressive coal-to-storage transition in order to serve a rising number of data centers, with a 220 MW project expected to come online this year.
“I think we’re going to see utilities in the Midwest turn to energy storage to better optimize their resource portfolio,” Roberts said. “We are seeing that in Wisconsin and Minnesota, Illinois and other states.”
