Four to One

The U.S. Energy Information Administration projects 86 gigawatts of new generating capacity in 2026, a record. Battery storage accounts for 24 gigawatts. Natural gas accounts for 6.3. That is a ratio of nearly four to one, and it has never happened before in American electricity.

Add solar (43.4 gigawatts) and wind (11.8 gigawatts), and renewables plus storage comprise 93 percent of all planned capacity additions this year. Nuclear contributes zero. Gas sits at 7 percent.

The 2025 baseline. SEIA confirmed this week that the United States installed 57.6 gigawatt-hours of new battery storage in 2025, a 30 percent increase over 2024 and roughly four times the volume deployed three years prior. The behind-the-meter segment accounted for approximately 13 percent of total demand, with the residential segment surging 51 percent as homeowners locked in tax credits before year-end changes. Cumulative commercial and industrial storage reached 19 GWh. SEIA projects over 600 GWh of cumulative storage by 2030.

The geography. Two-thirds of utility-scale battery installations in 2025 were in states that voted for President Trump in 2024. Texas is on pace to overtake California as the nation’s largest storage market this year. The drivers are grid economics and data center demand, not emissions mandates. ERCOT’s scarcity pricing design rewards batteries that can discharge into price spikes during summer peaks. The policy tailwinds are secondary to the revenue case.

The cap. In the aftermath of the Western energy crisis of 2000 and 2001, when wholesale electricity prices in California spiked to levels that bankrupted Pacific Gas & Electric, triggered rolling blackouts, and eventually exposed Enron’s systematic manipulation of Western energy markets, FERC imposed a soft price cap of $1,000 per megawatt-hour across WECC territory. Any seller exceeding the threshold had to cost-justify the sale and faced potential refunds.

It was a revenue ceiling designed for a grid where a small number of gas-fired generators could withhold supply and extract monopoly pricing during scarcity. On February 19, 2026, FERC voted to eliminate it.

The D.C. Circuit forced the issue. In Shell Energy North America v. FERC, the court ruled that FERC had to conduct a formal public-interest analysis before ordering refunds under the cap framework. FERC opened a show-cause proceeding. Multiple market participants filed comments supporting elimination. The commission concluded the cap was “no longer just and reasonable.” Macquarie Energy, which had already paid refunds under the old framework, won the right to recoupment.

The battery math. When the cap was imposed, utility-scale battery storage did not exist. The market power problem was straightforward: generators with fuel costs could bid above marginal cost during heat waves because buyers had no alternative.

Batteries invert that dynamic. A storage operator’s marginal dispatch cost approaches zero. The real cost is opportunity cost, the foregone revenue from not discharging later. A battery bidding $800/MWh during an evening ramp is not withholding supply. It is providing a service that was unavailable at any price when the cap was written.

Removing the ceiling does not eliminate all safeguards. CAISO’s organized markets maintain their own bid caps and mitigation mechanisms. The broader wholesale transaction space across WECC’s 11-state footprint now allows storage operators to capture full scarcity pricing during extreme events. For a 200 MW four-hour system in California, even a handful of hours per year above the old $1,000 threshold materially shifts the 20-year revenue projection.

The convergence. FERC removed the price cap in the same week SEIA confirmed the largest annual battery buildout in American history, and in the same month EIA projected batteries would outbuild gas by a factor of four. The regulatory framework is being rewritten for a grid that has already changed underneath it.

Gas at 7 percent of new capacity is not a policy outcome. Federal clean energy mandates are weaker today than they were four years ago. The OBBBA legislation tightened tax credit requirements for solar and wind, but battery storage retained both safe-harbor pathways with no 2026 deadline, a strategic advantage VDE Americas confirmed in a technical memorandum published this week.

What is happening is simpler and harder to reverse than any policy agenda. Batteries are cheaper to build, faster to interconnect, and increasingly preferred by grid operators who need dispatchable capacity without the permitting timelines or fuel exposure of gas-fired generation. The EIA data does not describe a policy triumph. It describes a market verdict.

The grid rules designed for gas dominance will continue to fall. The WECC price cap will not be the last.

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