US Power Market Outlook 2025-2030: Inside the Scramble to Meet Surging Power Demand
After two decades of flat growth, U.S. electricity demand is rising sharply. By 2030, consumption could jump 20%, with system peak load climbing from 745 GW today to as much as 930 GW (see figure 1). The surge is driven by data centers, electrification, and industrial onshoring—three forces that are adding continuous, geographically concentrated load faster than the grid was designed to handle. Peak demand is rising faster than average consumption because much of the new electricity use runs around the clock with little flexibility, creating localized stress on substations and transmission corridors even when national averages look manageable.
The supply response is visible but uneven. Renewables dominate near-term additions, with solar expected to add approximately 60 GW in both 2026 and in 2027, before moderating to around 30 GW thereafter. Storage maintains a steady 15 GW per year through 2030. Natural gas plants arrive late in the cycle, ramping to 17 GW annually between 2028 and 2030 as turbine manufacturing backlogs clear. Two factors explain this sequencing: economics and speed. Solar costs $38-78/MWh and can be built in 12-36 months. New combined-cycle gas plants cost $48-107/MWh on a levelized basis, but capital expenditures have surged from $722 million for a 1 GW plant in 2022 to $2.4 billion today, with projections reaching $2.8 billion by 2028 due to rapid demand growth, supply chain backlogs, and tariffs. Nuclear remains the most expensive option at $141-220/MWh, with timelines that stretch well beyond this decade.
Policy is now the binding constraint. The One Big Beautiful Bill Act (OBBBA) compressed the tax credit qualification window. Projects that begin construction by July 4, 2026, are safe-harbored and eligible to receive full income tax credits (ITC) or production tax credit (PTC) credits under the four-year pathway. Those starting after must reach commercial operation by December 31, 2027 to qualify at all (see figure 3). Foreign Entity of Concern requirements add a decade of annual compliance reviews, with recapture provisions if supply chains fail to meet domestic content thresholds. Tariffs are compounding costs across all technologies, with storage hit hardest, up more than 60% on Chinese battery components. Pre-OBBBA projects that safe-harbored costs in 2023-2024 remain the most bankable, while post-OBBBA developers face tighter structuring and heightened diligence.
Source: Department of Commerce, Federal Register, US White House, RaboResearch 2025
The fuel dynamic is shifting as well. North American LNG export capacity is on track to more than double by 2028, from 11.4 bcf/d in 2023 to 24.4 bcf/d. US projects account for 9.7 bcf/d of that increase. As Gulf Coast liquefaction trains reach commercial operation, feed gas demand will climb, pulling supply from the same basins that serve power plants in gas-dependent markets. If scarcity develops, natural gas prices could rise. Combined with the elevated capital costs of new gas plants, this creates upward pressure on wholesale power prices and PPA rates. That raises a strategic question. If power prices drift higher due to LNG-linked gas costs and expensive dispatchable capacity, do renewables still need subsidies to compete? The answer will shape not just which projects get financed, but how much policy support is required to meet the demand growth now bearing down on the system.
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