Natural gas

Natural gas prices
We expect the Henry Hub spot price to average about $3.00 per million British thermal units (MMBtu) for the third quarter of 2025. Natural gas inventories remain relatively high, and August ended with 6% more natural gas in storage compared with the five-year average. The Henry Hub spot price averaged $2.91/MMBtu in August (10% below our August STEO estimate). Lower prices over this summer have been driven by robust production and reduced natural gas consumption in the electric power sector. However, we continue to expect prices will gradually rise through the upcoming winter because inventories in our forecast are withdrawn at faster-than-normal rate this winter. The relatively strong inventory draws in our forecast mostly reflect rising LNG exports amid flattening U.S natural gas production. We forecast U.S. natural gas inventories will end March at 1% above the five-year average. In the forecast, the Henry Hub price reaches its winter peak in January at $4.60/MMBtu.

Historically, average annual prices for gas and oil change in tandem. We expect this year will be the first time they move in the opposite direction since 2014. By 2026, we forecast natural gas prices will be nearly double compared with 2024, while the West Texas Intermediate (WTI) crude oil price in our outlook falls 38%, leading to the lowest crude oil-to-natural gas price premium since 2005 at just over $4.00/MMBtu. The U.S. benchmark Henry Hub natural gas price averaged $3.66/MMBtu in the first half of 2025 (1H25), 67% higher than the 2024 annual average of $2.19/MMBtu. In contrast, the U.S. benchmark WTI crude oil price has averaged about $12.00/MMBtu in 1H25, 11% lower than the 2024 annual average.

With these price movements, we expect decreases in natural gas produced as a byproduct of oil directed drilling will offset increases in that produced by natural gas-directed drilling. Overall, we expect U.S. marketed natural gas production will average 117.1 billion cubic feet per day (Bcf/d) in 2025 and 116.8 Bcf/d in 2026. We expect the Permian region, an oil-rich region that produces large amounts of associated natural gas, to slow production growth. Permian production in our forecast averages 27.6 Bcf/d in 2026, a 0.2 Bcf/d increase from 2025. We also expect natural gas production from the Bakken and Eagle Ford regions, as well as in the STEO region known as the rest of Lower 48 states, will decrease by 1.3 Bcf/d combined. However, we expect the natural gas-rich Appalachia and Haynesville regions will increase by a combined 0.8 Bcf/d in 2026.

Natural gas consumption
LNG exports continue to be the largest source of demand growth for domestically produced natural gas. We forecast U.S. LNG exports will increase by 36% (4.3 Bcf/d) from 2024 to 2026, far outpacing our expected 1.0 Bcf/d of domestic consumption growth over the same period. We forecast U.S. domestic consumption of natural gas will average 91.4 Bcf/d by 2026, a 1% increase relative to 2024. The largest user of natural gas in the United States is the electric power sector which accounted for around 40% of domestic natural gas consumption last year and is set to remain at that share into next year.

Two LNG export facilities—Plaquemines LNG Phase 1 and Corpus Christi Stage 3—shipped their first cargoes in 4Q24 and 1Q25, respectively. Plaquemines LNG Phase 2 is expected to come online by the end of 2025, which is faster than we anticipated earlier this year, highlighting the uncertainty that project timelines can have on our natural gas balances. Another LNG terminal—Golden Pass l—is expected to come online by the end of 2026. When fully online, these developments will increase baseload LNG export capacity by 53% (6.0 Bcf/d) compared with the end of 2024.