The lack of battery storage in the Eastern U.S. is jarring. According to a recent report from GridLab, Electric Reliability Council of Texas (ERCOT) alone has installed almost 10 times more storage than the Pennsylvania-New Jersey-Maryland (PJM) Interconnection, Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), and the Southeastern U.S. combined.
PJM, MISO, and SPP account for more than 15 states—both ERCOT and California Independent System Operator (CAISO) only account for one.
What do Texas and California know that the Eastern U.S. doesn’t?
The answer lies in each state’s market design, procurement rules, and planning assumptions.
California prioritized procurement in its approach, making energy storage a priority starting as early as 2010. That year, the state legislation required utilities to account for 1.325 gigawatts (GW) of storage capacity by 2020. Since then, state regulators have required utilities to prove they could meet demand at every hour throughout the day. Over the last eight years, the state went from 0.5 GW of installed battery storage to more than 15.7 GW in early 2025. California found a purpose for its surplus of solar energy by bridging the gap between daytime production and evening demand.
In Texas, price volatility is the business model. ERCOT operates on an energy-only market, meaning generators are only paid for the electricity they produce and deliver. This gives battery operators the chance to buy power at a low price during low-demand periods and sell it back into the grid when it’s needed the most. For instance, an operator will charge their batteries at night and sell the electricity back into the grid the following afternoon when the energy is more valuable.
This model makes policy mandates unnecessary in Texas, and allows developers to connect quickly while managing grid congestion in real time.
While their approaches differ, both states have achieved what the Eastern states have failed to reach: conditions where energy storage makes sense.
The Eastern approach
Since Eastern energy grids encompass multiple states, their approach to storage is more complex. If a decision is made in one state, other states must agree with it before any changes are made to the storage process. This creates friction at every level, as state utilities, regulators, and grid operators have different incentives.
“Eastern states should have more discretion on the types of resources they can deploy within the parameters PJM is suggesting,” says Nikhil Kumar, program director for GridLab. “A lot of other states have been able to do that, and it’s been successful for them.”
But those other states don’t have the same market entanglements that the East does.
During peak demand periods, Eastern grids rely heavily on gas peaker plants. These plants typically power on during temperature extremes, when demand spikes. Since gas peaker plants don’t run very often, operators can’t rely on selling electricity alone. They also rely on capacity payments, which require utilities and grids to pay generators for the electricity they produce and for being available to produce it.
Since the Eastern grid operates in a capacity market, the owners of gas peaker plants don’t want that to change. That resistance has created the market rules storage developers are fighting to change today.
Data centers and AI add pressure
In addition to how it’s managed, the Eastern grid is outdated. Most of the infrastructure was built in the 1950s, making power failures and outages more frequent. The problem is especially urgent today, as electricity consumption increased by 2% in 2024—that number is expected to jump drastically as data centers and AI become a top priority in the next few years.
“Data center load growth or electrification is making energy demands higher,” says Kumar. “Historically, it was a capacity question: How much energy do I need for the peak summer and winter days? Now, it’s more about the need to serve data center loads.”
According to a report from ICF International, the demand for electricity will grow 25% by 2030 and 78% by 2050 from 2023 due to the growing number of data centers appearing throughout the U.S.
The U.S. Department of Energy (DOE) supports these predictions, as it foresees energy loads reaching between 325 to 580 terawatt-hours (TWh) within the next two years due to AI workloads. And with major companies like Amazon and Meta investing $320 billion in data centers just last year, those projections don’t sound too far off.
So, what does this mean for the East?
What the East can do now
First, energy regulation must be updated on the Eastern grid. In April 2025, the American Clean Power Association encouraged PJM to update its outdated rules to make batteries a stronger player in the energy market.
“The East needs to look at a diversified energy portfolio,” Kumar says. “It is currently dependent on gas as a resource, which is highly volatile. Implementing nuclear and solar energy will minimize risk and help with battery deployment.”
To accomplish this, the East must go a step beyond passing energy mandates—they must implement them.
Illinois recently followed through by passing the Clean and Reliable Grid Affordability Act, a law that aims to pump three gigawatts (GW) of storage into the grid by 2030. The state is also making sure small wind turbines, solar panels, and combined heat and power (CHP) systems can send power into the grid when it’s most in demand.
Eastern states should also prioritize long-duration battery storage. Most batteries installed in the East have short-term storage, only lasting for about four to six hours. California, on the other hand, is making the push for long-term storage by having generators prove they can meet energy demand at every hour of the day. Eastern states would benefit from proving the same hour-by-hour reliability.
In Texas and California, storage has become part of the infrastructure plan. In much of the East, it remains an add-on, something that competes, rather than integrates.
As demand accelerates, that distinction will show up in real ways: in capital costs, in reliability margins, and in how quickly new load can be served. Without changes to how storage is valued and procured, Eastern utilities may find themselves building a grid that works, but at a higher cost and with fewer options.
