U.S. Gas-for-Power Flat This Summer, Record Forecast for 2027 as Capacity Orders Surge
EIA forecasts flat gas-for-power this summer and a record in 2027, as $50 billion in U.S. generation spending and 20 GW of turbine orders reshape expectations.
NYMEX Henry Hub front-month settled at $2.87 per MMBtu at Friday's close (2026-07-24). The Energy Information Administration's July Short-Term Energy Outlook, released Thursday (2026-07-02), put U.S. wholesale electricity prices at $45 per megawatt-hour for this summer, down $4 per megawatt-hour from a year earlier, and offered the gas market little demand-side rationale for a rally.7
The EIA's near-term gas burn forecast is specific: despite a 2% increase in overall U.S. electricity demand this summer, natural gas-fired generation is expected to hold near recent highs rather than capture the incremental load. Renewables are absorbing that growth. But the agency is explicit that next summer looks different — it forecasts electric-sector gas consumption will set a record in 2027 as new gas capacity comes online.4
The capacity commitments behind that 2027 outlook are already visible in order books. U.S. companies are on track to spend approximately $50 billion on coal and natural gas power generation this year, the International Energy Agency estimated as reported by the Financial Times. That would be the first time in decades that U.S. outlays on those two fuels exceeded China's comparable investment, with the difference standing at $3 billion. More striking is the order concentration: IEA data show U.S. companies placed orders for roughly 20 gigawatts of gas turbine capacity in the first quarter of 2026 alone.6
The demand logic runs through data centers. The EIA's Annual Energy Outlook 2026 projects data center server electricity use already accounted for an estimated 7% of commercial sector consumption in 2025, with that share rising to between 22% and 33% of commercial building electricity by 2050 across the agency's scenarios. That trajectory is pulling turbine commitments forward at a pace manufacturers are struggling to match.2
Supply is expanding alongside that demand. U.S. marketed gas production averaged 120.2 billion cubic feet per day in the first quarter of 2026, up 4% from the same period in 2025, according to EIA data. Morgan Stanley expects Lower 48 output to grow by a further 3 billion cubic feet per day this year as spring maintenance disruptions clear.3,5
That supply trajectory is the core of the bear case for 2027. Analysts cited in Oil & Gas 360 put it plainly: bulls own 2026, bears own 2027. LNG export demand and AI-driven power consumption support near-term prices, but a simultaneous surge in production and newly dispatching generation capacity threatens to tip the market into surplus once the ordered turbines begin operating.5
Turbine manufacturers are already flagging capacity limits. One company's chief executive stated that a planned 30% increase in production capacity would not be sufficient to meet demand, according to oilprice.com. U.S. buyers account for roughly 40% of new global gas turbine orders, with European customers taking another 35%, a geographic split that underlines how much of the world's incremental generation investment is competing for the same equipment.6
China's thermal power data add a piece of context worth noting. The National Bureau of Statistics reported Friday (2026-05-15) that thermal generation — predominantly coal, with a small natural gas component — rose 1.5% in 2024 to 6.34 trillion kilowatt-hours, the slowest growth rate in nine years outside COVID-affected periods. Greenpeace analysts argued in May 2026 that renewables could absorb all of China's new power demand growth in 2025. If Chinese coal-fired output stagnates, LNG volumes previously absorbed in Asian markets could redirect toward the Atlantic Basin, adding supply pressure to a U.S. market that is already expanding its own production at pace.1
Traders on ERCOT and MISO are waiting on whether heat drives real-time power prices high enough to generate additional gas burn before summer ends. At a load-weighted average of $45 per megawatt-hour, wholesale power pricing is not incentivizing incremental draws, and NYMEX Henry Hub front-month at $2.87 per MMBtu at Friday's close (2026-07-24) sits well below levels typically associated with demand-side tightening. A sustained heat wave across Texas or the Midwest could shift that arithmetic. It has not materialized.7