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LCG, March 18, 2026--The EIA released a new "In-depth Analysis" of the potential impact of faster-than-expected near-term growth in data center power demand on power generation and wholesale prices on March 12. The analysis models the lower 48 states through 2027 and compares results to its base case scenario. Key takeaway from this sensitivity analysis is the potential increase in fossil fuels in some regions and potentially a significant increase in wholesale prices in ERCOT.
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LCG, March 17, 2026--Oklo Inc. (Oklo) today announced that it has signed a U.S. Department of Energy (DOE) Other Transaction Agreement (OTA) to support the design, construction, and operation of Oklo’s first reactor, the Aurora powerhouse at Idaho National Laboratory (INL) under DOE’s Reactor Pilot Program (RPP). The DOE Idaho Operations Office subsequently approved the Nuclear Safety Design Agreement (NSDA) for the fast-fission power plant, and Oklo immediately requested DOE commence review of its Preliminary Documented Safety Analysis (PDSA).
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Industry News
Faster-than-Expected Data Center Load Growth May Cause Increased Regional Short-term Fossil Fuel Generation and Wholesale Electricity Prices
LCG, March 18, 2026--The EIA released a new "In-depth Analysis" of the potential impact of faster-than-expected near-term growth in data center power demand on power generation and wholesale prices on March 12. The analysis models the lower 48 states through 2027 and compares results to its base case scenario. Key takeaway from this sensitivity analysis is the potential increase in fossil fuels in some regions and potentially a significant increase in wholesale prices in ERCOT.
The EIA analysis was completed in conjunction with the February Short-Term Energy Outlook (STEO), and the data sources include the EIA's Short-Term Energy Outlook (STEO), February 2026; and LCG's UPLAN Network Power Model.
The EIA's analysis describes how electricity demand has been rising steadily since 2020 after more than a decade of little load growth. Between 2020 and 2025, U.S. electricity demand, as measured by net energy for load, grew about 1.7 percent annually compared with 0.1 percent annual growth between 2005 and 2019. A primary driver of electricity growth is data centers, and continued data center growth and expanded industrial growth is likely in the near term.
This new analysis investigates the potential impact of faster-than-expected electricity demand growth while assuming the same future generating capacity as the February Short-Term Energy Outlook (STEO), which incorporates the latest forecasts published by grid operators PJM and ERCOT and uses forecasts for economic activity and weather to project the baseline forecast for electricity load. ERCOT manages the grid covering most of Texas, and PJM manages the grid covering all or part of 13 states (Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia) and Washington, DC.
In the February STEO, the U.S. electricity load is forecast to increase by 1.9 percent in 2026 and 2.5 percent in 2027. The highest load growth (largely driven by data centers) between 2025 and 2027 is in the ERCOT (10 percent) and PJM (3 percent) regions.
For this new analysis, the EIA developed a high demand growth scenario in which the 2026 and 2027 growth rates were 50 percent higher than the baseline forecast in the February STEO for ERCOT, PJM, Southwest, Central (SPP ISO) and Midwest (MISO), i.e., where significant development of data centers are anticipated. For other regions, the assumed demand growth rates were one percentage point higher than the February STEO forecasts (e.g., CAISO increased from 1.5 to 2.5 percent) to account for potential increased development of data centers in those areas.
The STEO's electricity generation forecasts incorporate the generating capacity of existing power plants listed in EIA's Preliminary Monthly Electric Generator Inventory, future additions reported to the EIA by utilities and companies, and regional modeling using LCG's UPLAN.
Due to long lead times for developing and completing new generating capacity, EIA believes it is unlikely that more capacity will become operational beyond what is included in the base forecast. Natural gas-fired capacity is the primary source of available capacity to meet the assumed data center load growth. With additional demand for the fuel (natural gas) in the high demand scenario, the EIA assumes an increase of about $0.50 MMBtu in the cost of natural gas delivered to power generators in all regions relative to the baseline February STEO forecast.
The EIA analysis results through 2027 indicate that most regions can accommodate higher-than-expected electricity demand growth. Excluding ERCOT, the average 2027 wholesale price across the other major hubs would be $2.10/MWh higher in the high demand growth scenario compared with the February STEO forecast average of $48/MWh. However, in ERCOT the 2027 wholesale price averaged $37/MWh (79 percent) higher than the February STEO forecast price. Forecast ERCOT hourly prices in the high demand growth scenario were particularly high during the late summer months when wind generation typically reaches a seasonal low and electricity demand tends to reach its seasonal peak. When this occurs, ERCOT must rely on its most expensive generators to satisfy demand. Unlike other regions, ERCOT's grid is isolated and has limited connections to the Eastern and Western grids, causing ERCOT's price response to higher demand to be more acute.
PJM is the second-largest load growth region in the high electricity demand growth scenario. However, the annual average price increase in PJM is much more limited than in ERCOT because PJM is (i) interconnected with other regions in the eastern United States and (ii) has access to more coal and natural gas generating capacity to serve the additional load. EIA estimates that the modeled PJM wholesale price in 2027 in the high demand growth scenario would be $2.60/MWh (4 percent) higher than the forecast February STEO price.
In regions that historically have had higher electricity prices, like New England and New York ISO, the EIA expects an additional $3.00/MWh (5 percent) average wholesale electricity price increase in the high demand scenario compared to the February STEO.
The EIA's assumed higher electricity demand leads to greater overall power generation (supply), and the increase in generation would primarily come from natural gas-fired power plants. In 2025, natural gas accounted for 40 percent of total generation; coal accounted for 17 percent of total generation; and intermittent sources (wind and solar) accounted for 18 percent of total generation.
In the February STEO, the EIA forecast between 2025 and 2027 that U.S. natural gas generation will increase by 1.7 percent, or 29 BkWh. In the new analysis with the higher electricity demand scenario, the two-year increase would rise to 7.3 percent (123 BkWh), or an increase of more than four times the base case. Natural gas generation increases the most in ERCOT, rising by 105 BkWh in the high demand growth scenario compared with 68 BkWh in the February STEO.
Regarding coal generation, the February STEO forecast between 2025 and 2027 shows a nationwide decrease by 9.3 percent (68 BkWh). In the new high demand growth scenario, coal generation decreases by 5.0 percent (37 BkWh) over the two-year period. In the PJM, MISO, and SERC regions, coal accounts for more than half the additional increase in electricity generation in the high demand growth scenario because coal-fired plants have existing spare capacity.
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UPLAN-NPM
The Locational Marginal Price Model (LMP) Network Power Model
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UPLAN-ACE
Day Ahead and Real Time Market Simulation
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UPLAN-G
The Gas Procurement and Competitive Analysis System
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PLATO
Database of Plants, Loads, Assets, Transmission...
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