If Demand Grew Faster: EIA's Scenario for Gas, Coal and Wholesale Prices in Texas

Electricity use by data centers "is driving the electricity demand growth" in the United States, the U.S. Energy Information Administration, EIA, wrote in an analysis dated March 12, 2026. It then asked what would happen if that growth came faster than it expected, while the generating capacity stayed as its February forecast had it. In its scenario, more natural gas would be burned, coal generation would fall by less, and the effect on wholesale prices would be most pronounced in Texas.

A note under the title adds a limit. The analysis was done with the February Short-Term Energy Outlook, or STEO, and "The results may differ slightly from the most recent forecasts published in the March STEO."

A faster scenario, with the same power plants

The starting point is the February forecast, in which EIA expected electricity load in the United States to grow by 1.9% in 2026 and 2.5% in 2027. It expected the highest growth in the regions of the grid operators ERCOT and PJM, where annual load growth was forecast to average 10% and 3% respectively between 2025 and 2027.

For the scenario, EIA set the 2026 and 2027 growth rates 50% higher than that baseline forecast in the regions "with significant development of data centers," and "one percentage point higher" elsewhere. It added no power plants beyond those its base forecast already counts. EIA judged it "unlikely that more capacity will become operational by the end of the STEO forecast period," given "long lead times for planning, construction, and interconnections of new generating capacity."

In the scenario, natural gas is "the primary source of available power generation to meet incremental demand." The gas delivered to power plants is assumed to cost about $0.50 per million British thermal units more than in the February forecast.

EIA judges it unlikely that capacity beyond what it already counts comes online inside this window. A campus that needs power before the window closes draws, in this scenario, on plants already counted.

Primarily gas, in the scenario

More demand would need more generation, and the analysis says it would come "primarily" from greater use of natural gas-fired power plants. Natural gas was already the main source of electricity generation in the United States, with 40% of the total in 2025.

The numbers show how much more. In the February forecast, gas generation in the United States grows by 1.7% between 2025 and 2027, "or 29 billion kilowatthours (BkWh)." In the scenario, the two-year increase "would rise to 7.3% (123 BkWh)."

Coal would still fall in the scenario, but by less. The February forecast has coal generation in the United States falling 9.3% between 2025 and 2027, against a fall of 5.0% over the two years in the scenario. In the Mid-Atlantic (PJM), the Midwest (MISO) and the Southeast (SERC), coal would supply "more than half the additional increase in electricity generation" in the scenario, "because coal-fired plants have existing spare capacity."

What prices would do, and why Texas

Wholesale prices would rise with demand in the scenario, the analysis says, with a relatively minor effect in 2026 and a more evident one in 2027. Texas would see the most. There the 2027 wholesale price would be $37 per megawatthour higher than in the February forecast. Across the other major hubs the analysis covers, the 2027 price would average $2.10 per megawatthour more in the scenario than the February forecast's average of $48.

The analysis says why Texas stands out. Modeled hourly prices there were "particularly high during the late summer months when wind generation typically reaches a seasonal low," just when demand "tends to reach its seasonal peak." And ERCOT's grid "is isolated and has limited connections to the main Eastern and Western grids," which, the analysis says, "makes the price response to higher demand more acute."

In this scenario the isolated grid is where faster demand shows most in price. For a campus planned in Texas, the price of power in a late-summer hour is part of the risk, not only the price in a contract.