Three States, Three Quarters of the Batteries
The United States installed 58 GWh of new energy storage in 2025. Texas, California, and Arizona accounted for 74 percent of all utility-scale deployments.
The remaining 26 percent was spread across 47 states, many of which have higher electricity prices, worse grid congestion, and stronger economic cases for storage than the three leaders. The concentration is not a function of need. It is a function of market design.
The revenue problem. Battery storage earns money in layers: energy arbitrage, capacity payments, ancillary services, demand response. In ERCOT and CAISO, operators can stack these revenue streams with relative freedom, building financial models that attract capital. In PJM, the largest wholesale electricity market in North America, battery operators face structural penalties for doing exactly that. Latitude Media reported this week that PJM’s market rules actively penalize storage assets that respond to real-time grid signals if they are already scheduled in a different market window. The result is that a battery in PJM cannot simultaneously optimize across arbitrage, capacity, and ancillary services the way it can in Texas or California.
This is not a minor technical complaint. It is the primary reason the Eastern Seaboard and Midwest, home to the nation’s most congested grids and highest commercial electricity rates, have a fraction of the storage capacity that less populated states enjoy.
The Massachusetts test case. On February 27, the Massachusetts Energy Facilities Siting Board approved Jupiter Power’s Trimount project in Everett: 700 MW and 2.8 GWh of battery storage using Hithium’s 5 MWh BESS units. When operational, it will be one of the largest standalone battery installations in the country. The project will connect through Eversource Energy’s Mystic Substation, and groundbreaking is expected in 2027 with commercial operation by late 2028.
The project’s economics tell their own story. ISO New England estimated that Trimount could defer up to $2.27 billion in transmission upgrades, a figure that illustrates the scale of infrastructure spending that strategically sited storage can displace. The demand exists. Developers are lining up. The constraint on Eastern storage deployment is not land, interconnection access, or developer interest. It is whether the asset can earn enough once connected.
The monopoly play. While PJM’s market design suppresses competitive storage investment, incumbent utilities in the Midwest are asking regulators to make the problem worse. Xcel Energy and other Midwest utilities are pressing FERC to suspend electricity competition rules. Their argument: surging AI-driven electricity demand requires utilities to build infrastructure faster, and competitive procurement slows things down.
The utilities have taken their case beyond FERC to the White House’s National Energy Dominance Council, framing monopoly expansion as aligned with the administration’s energy priorities. If FERC grants the request, utilities in MISO territory would gain expanded rights to build infrastructure in their service areas without competitive bids. Independent developers, including storage providers who compete to defer transmission upgrades, would lose their seat at the table.
In the same week that data quantified the Eastern storage gap, the incumbents who benefit from that gap asked Washington to widen it.
What market design costs. The Benchmark/SEIA Q1 2026 market outlook puts the national installed base at 165 GWh cumulative: 137 GWh utility-scale, 19 GWh commercial and industrial, 9 GWh residential. The report forecasts 35 GW of new installations in 2026. But those national numbers obscure a distorted geography. States with the highest commercial demand charges, the worst grid congestion, and the most acute need for non-wires alternatives are systematically underbuilt.
The financial logic is circular. Developers cannot build in PJM because the revenue model does not support investment. Utilities point to the lack of storage as evidence that they need to build more utility-owned generation and transmission. Regulators approve utility rate base expansion. Ratepayers fund infrastructure that competitive storage could have deferred at lower cost. The cycle continues.
The FERC fork. Two regulatory proceedings will determine whether this geography shifts. The first is PJM’s ongoing capacity market reform, which could restructure how storage participates in forward capacity auctions and whether revenue stacking restrictions loosen. The second is the Xcel-led petition to suspend competitive bidding rules, which would set precedent for whether independent energy infrastructure can compete with utility-owned assets in the fastest-growing electricity markets.
These are not abstract policy debates. Jupiter Power’s Trimount project demonstrates that capital is available, sites exist, and the technology works at scale. The question is whether the market rules will let it earn its keep. A 2.8 GWh battery at the Mystic Substation can absorb solar, shave peaks, and defer billions in transmission spending. But only if ISO New England’s market design lets it capture the value it creates.
The United States added 58 GWh of storage in 2025. Three quarters of it went where the rules allowed operators to get paid, not where the grid needed it most.
Sources
Why is battery storage lagging across the East Coast and Midwest? (Latitude Media)
Jupiter Power receives approval for 2.8GWh Massachusetts BESS (Energy Storage News)
Midwest utilities are looking to FERC for monopoly expansion (E&E News)
600 GWh of US energy storage expected by 2030 (Utility Dive)
United States installs 58 GWh of new energy storage in 2025 (SEIA)