Natural gas

Natural gas prices
We expect the Henry Hub spot price to increase from around $3.00 per million British thermal units (MMBtu) in September to $4.10/MMBtu by January 2026, almost 50 cents/MMBtu lower than we forecast last month. We expect the Henry Hub price to average about $3.90/MMBtu overall in 2026.

Our lower price expectation reflects our forecast that natural gas production will be higher than we forecast last month, leading to more natural gas in inventory through the winter than previously expected. In addition to higher natural gas production in the forecast, since late August, above-average natural gas injections have increased storage levels heading into this winter. We now expect inventories to reach almost 3,980 billion cubic feet (Bcf) at the end of injection season, or 5% more than the five-year average. This forecast is almost 70 Bcf more than we forecast last month. These higher-than-expected stocks at the start of winter support more natural gas in storage throughout winter 2025–26, assuming near-normal temperatures. Natural gas inventories in our forecast end the withdrawal season on March 31 at 1,990 Bcf, 8% above the five-year average.

Natural gas production
We expect marketed natural gas production in the U.S. Lower 48 (L48) states to increase slightly in 2026 to an average of more than 118 billion cubic feet per day (Bcf/d) as growth from the three most prolific natural gas producing regions—the Appalachia, Permian, and Haynesville—is partly offset by declines from producing regions in the rest of the L48 states. Our forecast for U.S. marketed natural gas production in 2026 is 1.3 Bcf/d higher this month compared with the September STEO. We raised our expectations for natural gas production over the forecast based on data from July that showed natural gas production above our expectations, which increased the starting point for our forecast.

In 2026, we expect the combined production from the Appalachia, Permian, and Haynesville regions to account for 69% of overall U.S. production. We expect production in the Haynesville region to grow by 2% in 2026 to average 15.6 Bcf/d as higher natural gas prices has led to an increase in drilling activity in the region. For 1H25, rig counts in the Haynesville region rose by 7 to 39 rigs. We expect this trend to continue with the relatively higher forecast Henry Hub prices in 2026.

In the past, production in the Appalachia region has been constrained by limited takeaway capacity. But recently with the addition of the Mountain Valley Pipeline and demand growth from additional data centers in the Northeast that are increasing regional demand for electricity—including natural-gas fired generation—we expect production in Appalachia to grow by 2% in 2026 and average 37.6 Bcf/d.

The Permian Basin has been the most prolific natural gas growth area in the past, and we expect the Permian region production to rise 9% (2.3 Bcf/d) this year. In the Permian region, growth in natural gas production is primarily the result of associated natural gas produced during oil production. As West Texas Intermediate (WTI) crude oil prices in our forecast fall in 2026, we expect Permian natural gas production growth to slow to 1% next year, reaching 28.0 Bcf/d.

The forecast decline in WTI prices also reduces associated natural gas production from other regions such as the Eagle Ford, Anadarko, and Niobrara regions.

LNG export capacity
The United States is scheduled to add more than 5 Bcf/d in liquefied natural gas (LNG) export capacity combined over 2025 and 2026. In 2025, we expect Plaquemines LNG Phases 1 and 2 and three trains of Corpus Christi LNG Stage 3 to enter into service. Plaquemines LNG Phase 1 sent out its first cargo in December 2024, and Phase 2 began production in July 2025, earlier than our previously expected start-up date of 2026. By the end of 2025, we forecast all blocks will begin exports, adding 2.6 Bcf/d of nominal LNG export capacity and 3.2 Bcf/d of peak export capacity, driving most of the increase in LNG exports compared with 2024. We forecast that Corpus Christi LNG Stage 3 will begin exports from three of seven trains in 2025, bringing an estimated 0.6 Bcf/d of nominal capacity (0.7 Bcf/d peak capacity) into service in 2025.

In 2026, we expect the remaining four trains in Corpus Christi LNG Stage 3 to enter service, as well as two of three trains from Golden Pass LNG. The four trains at Corpus Christi will boost nominal capacity by a total of 0.8 Bcf/d (0.9 Bcf/d peak capacity). We expect Golden Pass LNG, which is currently under construction, to ship its first cargo in 1H26, and for Train 2 to start up later in the year. These start-ups will add 1.4 Bcf/d of baseload export capacity (1.6 Bcf/d peak capacity) in 2026. We forecast these capacity increases will raise U.S. LNG exports to an annual average of more than 16 Bcf/d in 2026, compared with less than 12 Bcf/d in 2024.