A faster data center buildout than forecasters currently expect would push U.S. power plants to burn more natural gas, slow the retirement of coal generation, and add $37 per megawatthour to Texas wholesale prices in 2027, on a scenario published by the U.S. Energy Information Administration. The agency held future generating capacity fixed and asked what happens when demand outruns it.
Start with what the scenario assumes, because the assumptions do most of the work. For regions with significant data center development, EIA raised the 2026 and 2027 load growth rates 50% above the baseline in its February Short-Term Energy Outlook, and added one percentage point everywhere else. Future generating capacity was left unchanged, on the reasoning that planning, construction and interconnection lead times make extra plants unlikely to arrive inside the forecast period. Delivered natural gas was assumed to cost about $0.50 per million British thermal units more than in the baseline.
The baseline itself has U.S. electricity load rising 1.9% in 2026 and 2.5% in 2027, with annual load growth averaging 10% in ERCOT and 3% in PJM between 2025 and 2027. Both regions are where the data center pipeline is heaviest.
Gas absorbs the extra load. February's forecast has U.S. natural gas generation rising 1.7% between 2025 and 2027, or 29 billion kilowatthours. Under the higher demand case the two-year increase reaches 7.3%, or 123 billion kilowatthours. In ERCOT alone, gas generation grows by 105 billion kilowatthours instead of 68.
Coal moves in the direction that matters to anyone tracking retirement schedules. The baseline has U.S. coal generation falling 9.3% across the two years; in the high demand case it falls 5.0%. Across PJM, MISO and the Southeast, coal supplies more than half the additional generation, because those plants have spare capacity already sitting idle.
Prices separate sharply by region. ERCOT's modeled 2027 wholesale price runs $37/MWh, or 79%, above the February forecast, with the widest gaps in late summer when wind output hits a seasonal low as demand peaks. PJM adds $2.60/MWh, or 4%, and New England and New York add $3.00/MWh, or 5%. California and the Southwest come in at $1.30/MWh, or 4%. Excluding ERCOT, the average across the other major hubs rises $2.10/MWh against a February forecast average of $48/MWh.
"The results indicate that most regions can accommodate higher-than-expected electricity demand growth, but the modeled price effects in ERCOT highlight some of the challenges grid operators have in managing large increases of load in the near term", EIA writes. Texas is the outlier for a structural reason the agency states plainly: "ERCOT’s grid is isolated and has limited connections to the main Eastern and Western grids." A region that cannot import cannot borrow its way out of a tight afternoon, so the price does the rationing instead.
One caveat travels with the numbers. The analysis was completed alongside the February outlook, and EIA says its results may differ slightly from the forecasts in the March edition, so the figures describe a scenario run against a baseline that has since been updated.
For buyers negotiating interconnection or power contracts, the modeled cost of a faster buildout is a rounding error in most of the country and a different order of magnitude in Texas. Everywhere outside ERCOT the added wholesale cost lands between $1.30 and $3.00 per megawatthour, against $37 inside it.
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