Battery Storage Hit $78/MWh in 2025. Gas Peakers Cost $110. The Lines Just Crossed.

Seventy-eight dollars.

That is the global benchmark levelized cost of energy for a four-hour battery storage system in 2025, according to BloombergNEF's LCOE 2026 report. Down 27% from the prior year. A record low for grid-scale battery storage.

A more important number sits on the other side of the ledger. Combined-cycle gas turbines, the workhorses of American dispatchable power, hit a benchmark LCOE of $102/MWh in the same year. Up 16%. An all-time high. Gas turbine capital expenditure has doubled in two years, driven by data center demand and supply chain constraints.

For simple-cycle gas turbines, the peaker plants that fire up during afternoon demand spikes, the economics are worse. Lazard's LCOE+ 2024 report pegged peaker LCOE at $110 to $228 per MWh. Even the floor of that range now sits above a four-hour battery.

This is the crossover. Not projected. Not modeled for 2030. It happened in 2025.

57.6 GWh in a Single Year

The deployment numbers match the cost trajectory. The US Energy Storage Market Outlook Q1 2026, published by SEIA and Benchmark Mineral Intelligence, reports that the United States installed 57.6 GWh of new battery storage capacity in 2025. That figure represents a 30% increase over 2024's record, itself four times the level installed just three years earlier.

Utility-scale systems accounted for nearly 50 GWh of the total. Residential storage added 3.1 GWh, a 51% year-over-year surge driven in part by homeowners racing to claim the Section 25D Investment Tax Credit before year-end policy shifts. Commercial and industrial storage grew 16% but remains small at 95.6 MW.

A separate accounting from Wood Mackenzie's Energy Storage Monitor counts 18.9 GW and 51 GWh installed using a slightly different methodology. Both sources agree on the trajectory: the US grid added more battery capacity in 2025 than in any prior year, and the rate is accelerating.

Since 2019, cumulative installed capacity has reached 137 GWh for utility-scale storage alone. But the pipeline dwarfs installed capacity. Wood Mackenzie identifies 152 GW of projects in active databases and 530 GW sitting in interconnection queues as of Q4 2025.

The Peaker Displacement Calculation

Here is a number nobody seems to be running. The United States operates approximately 132 GW of simple-cycle gas turbines, according to EIA data. These are the peaker plants: low-capacity-factor machines that average 10% to 17% utilization annually but earn outsized revenue during hot afternoons and cold snaps.

In 2025, the US installed 57.6 GWh of battery storage. Assuming a four-hour duration (the most common configuration for utility-scale systems), that translates to 14.4 GW of peaking-equivalent capacity added in a single year.

At 14.4 GW per year, the math says the entire 132 GW peaker fleet could be functionally replaced in about nine years.

In practice, the real timeline will be longer. Four-hour batteries cannot substitute for every peaker use case. Some peakers serve as reliability backstops during multi-day heat events. Others provide ancillary services like frequency response and voltage regulation that batteries handle differently. And much of the battery capacity being installed is not aimed at displacing peakers at all; it is paired with solar farms or co-located with data centers.

But the ratio is still significant. Battery deployment already equals 11% of the US peaker fleet, measured by nameplate capacity, in a single year of installations. Even if only half the deployed storage functionally displaces peaking gas, that is 7.2 GW of gas capacity made economically redundant annually. The EIA reports that only 4.6 GW of gas capacity is scheduled for retirement in 2026. Deployment is outrunning retirement schedules.

Where the Batteries Are Going

Two-thirds of all utility-scale battery storage installed in 2025 went into states won by President Trump in the 2024 election, including nine of the top 15 states for new installations. Texas is projected to overtake California in 2026 as the largest battery storage market in the country.

This is not an environmental choice. It is an economic one. Texas operates a deregulated energy market (ERCOT) where price spikes during peak demand can reach thousands of dollars per MWh. Battery owners who charge at $20/MWh overnight and discharge at $200/MWh during a summer afternoon earn returns that make the IRA tax credit a nice bonus rather than a deciding factor.

Grid reliability drives the geographic spread too. Texas suffered the catastrophic failure of Winter Storm Uri in 2021. The state's grid operator has since approved interconnection for more battery storage than any other generation type. The demand signal is clear: dispatchable capacity that does not freeze when gas pipelines do.

Beyond Texas, the growth is spreading. Storage installations occurred in 22 states during 2025. California remains the largest single market by cumulative capacity, but the gap is closing fast.

The Speed Gap

Cost is one advantage. Speed is another.

Gas turbines now take two to three years from order to commercial operation, according to analysis from the Kleinman Center for Energy Policy at the University of Pennsylvania. Material shortages and manufacturing backlogs at Mitsubishi, GE Vernova, and Siemens Energy have pushed delivery timelines to levels not seen in decades. Battery storage systems can be delivered and installed in months.

This matters enormously for data centers. Generative AI infrastructure requires enormous power, and it requires it fast. A hyperscaler that breaks ground on a 100 MW data center cannot wait three years for a gas turbine. According to Wood Mackenzie's 2026 analysis, battery storage is now the second most common onsite power source in the US data center pipeline, trailing only gas turbines. Some developers are co-locating storage specifically to bypass utility interconnection bottlenecks, using batteries to manage the millisecond-scale training loads that crash grid equipment.

The Supply Chain Is Pivoting

One of the less visible shifts in 2025 was the reorientation of battery cell manufacturing. As electric vehicle sales growth slowed in several markets, battery cell manufacturers pivoted production lines from EV cells to stationary storage cells. SEIA reports that US-based lithium-ion cell manufacturing for stationary storage applications has risen to over 21 GWh of annual capacity. US facilities now have the capacity to manufacture 69.4 GWh of battery energy storage systems per year, more than the entire 2025 installation volume.

Battery manufacturers are also diversifying away from lithium. Peak Energy signed a 4.75 GWh sodium-ion supply agreement with Jupiter Power, one of the largest non-lithium storage deals on record. Flow batteries, iron-air systems, and zinc-based chemistries are reaching what Wood Mackenzie calls the "bankable" stage, meaning that project financiers accept them for utility-scale deployments without requiring technology risk premiums. This chemistry diversification reduces the grid storage sector's exposure to lithium supply constraints and Chinese processing dominance.

Strongest Counterargument: The Duration Wall

The most serious challenge to the "batteries replace peakers" thesis is duration.

Four-hour batteries handle daily peaks well. They charge from midday solar, discharge during the evening ramp, and reset overnight. For the typical summer afternoon spike that lasts two to four hours, batteries are a direct substitute for a gas peaker.

But the grid does not always cooperate with four-hour windows. Winter Storm Uri lasted five days. The Pacific Northwest heat dome of 2021 created sustained demand for 72 hours. California's September 2022 heat event pushed the grid for more than a week. During these multi-day events, four-hour batteries empty and cannot recharge if solar generation is also suppressed (by clouds during storms or by high air conditioning demand extending past solar hours).

This is the honest limitation. A grid that retires all its gas peakers and relies solely on four-hour lithium-ion batteries will fail during the events that matter most. Peaker plants, for all their expense and carbon intensity, provide something batteries currently do not: the ability to generate power continuously for days by burning fuel.

Long-duration storage technologies (iron-air, flow batteries, compressed air, gravity systems) are designed to fill this gap. Form Energy's iron-air battery targets 100-hour duration at roughly $20/kWh of capacity. But these technologies are still in early deployment. Until they scale, some portion of the gas peaker fleet serves as an insurance policy against multi-day extreme weather.

What This Analysis Cannot Show

Several limitations bound the calculations above.

First, LCOE is a useful but imperfect comparison. Gas peakers earn revenue from capacity markets (being available) in addition to energy markets (actually generating). Batteries can participate in capacity markets too, but their capacity value depends on duration. A four-hour battery in PJM receives a derated capacity credit that reflects its inability to discharge for 10+ hours during a winter reliability event. LCOE alone does not capture this dynamic.

Second, the 132 GW peaker fleet number dates from EIA's December 2022 inventory. Some capacity has been added and some retired since then. The exact current fleet size may differ by several GW in either direction. That 11% displacement ratio should be read as an approximation, not a precise figure.

Third, battery storage degradation is real. Lithium-ion cells lose capacity over their 15- to 20-year lifetimes. A system rated at 100 MWh on day one may deliver 80 MWh by year 10. LCOE calculations from BNEF account for this degradation, but real-world performance varies by cell chemistry, cycling patterns, and thermal management.

Fourth, the IRA's standalone storage Investment Tax Credit (30% base, up to 50% with domestic content and energy community bonuses) significantly affects project economics. If future policy changes reduce or eliminate this credit, the LCOE for battery storage would rise. SEIA's low-deployment scenario shows 17% less capacity than the base case under stricter policy assumptions.

Fifth, BNEF's $78/MWh figure is a global benchmark. Costs vary significantly by market, interconnection charges, and local permitting. Some US projects are achieving LCOEs well below $78/MWh. Others, particularly in regions with complex permitting or high interconnection costs, are significantly above it.

The Bottom Line

Battery storage just crossed below gas on LCOE for the first time. Not in a model. Not in a projection. In 2025 actuals. Gas combined-cycle hit $102/MWh while battery storage dropped to $78/MWh. Gas peakers, the specific plants that batteries are best positioned to replace, range from $110 to $228/MWh. At current deployment rates, the US is installing enough battery capacity each year to functionally displace 11% of its gas peaker fleet.

If you run a utility: the economics now favor storage over new gas peakers in most markets, and the IRA tax credit makes the gap wider. If you are evaluating data center power: battery co-location is faster to deploy and increasingly cheaper than waiting for a gas turbine. If you invest in energy infrastructure: watch Texas. The state's deregulated market, extreme weather, and booming demand make it the proving ground for whether batteries can replace gas at scale. And if you track energy policy: note that two-thirds of this growth is happening in red states. Grid storage politics are not what the debate in Washington suggests.

The peaker fleet will not disappear in nine years. Multi-day events will keep some gas plants running as insurance. But the direction is no longer ambiguous. The cost curves crossed, and they are not crossing back.