Natural gas prices have climbed sharply from the historic lows seen in 2024, driven by a combination of surging export demand, flat domestic production, and tighter-than-normal storage levels. The Henry Hub spot price, the main U.S. benchmark, reached $7.72 per million British thermal units (MMBtu) earlier in 2026 before pulling back to around $3.62. For context, that peak was roughly double the price the Energy Information Administration had forecast for the full year. The forces pushing prices up are structural, not temporary, and understanding them helps explain where things may be headed.
LNG Exports Are Pulling Gas Off the Domestic Market
The single biggest change in the U.S. natural gas market over the past several years is the explosive growth in liquefied natural gas (LNG) exports. In 2024, the U.S. shipped roughly 12 billion cubic feet per day (Bcf/d) overseas as LNG. That figure is expected to jump to 14 Bcf/d in 2025, and once all projects currently under construction come online by the end of the decade, export capacity will reach 26 Bcf/d. The U.S. government has authorized over 49 Bcf/d in total LNG export capacity.
To put those numbers in perspective, total U.S. natural gas production averaged about 113 Bcf/d in 2024. Sending 12 to 14 Bcf/d abroad means more than 10% of everything the country produces now leaves the domestic market entirely. That tightens supply at home, especially during periods of high heating or cooling demand. European and Asian buyers are willing to pay significantly more than U.S. consumers, which gives producers a financial incentive to direct gas toward export terminals rather than domestic pipelines.
Production Growth Has Stalled
While exports have been climbing, U.S. natural gas production barely grew in 2024. Total marketed production increased by less than 0.4 Bcf/d compared to 2023, essentially flat at 113 Bcf/d. That stagnation wasn’t uniform across the country. The Permian Basin in West Texas and New Mexico saw a 12% jump in output, adding 2.7 Bcf/d to reach 25.4 Bcf/d. But the Permian’s gas growth is largely a byproduct of oil drilling. Producers there are chasing crude oil, and the natural gas comes along for the ride.
In the Haynesville Shale, which spans Louisiana and East Texas and is one of the country’s most important gas-focused regions, the picture was the opposite. Production fell 11% in 2024. Drillers there cut back aggressively in response to the extremely low prices that had prevailed, dropping from an average of 57 active rigs per month in 2023 to just 37 in 2024. That kind of pullback takes time to reverse. You can’t flip a switch and restore lost production. New wells need to be permitted, drilled, and connected to pipelines, a process that can take months.
The Appalachia region, centered on the Marcellus Shale in Pennsylvania and West Virginia, remained the largest producing area at 35.6 Bcf/d, accounting for 31% of total U.S. output. But growth there has been slowing for years because there simply aren’t enough pipelines to carry the gas to the markets that need it. Until new pipeline capacity is built, Appalachian production is effectively capped.
Storage Levels Are Below Average
Underground natural gas storage acts as a buffer between supply and demand. When storage is full, prices tend to stay low because there’s plenty of cushion. When storage dips below normal, prices rise on concern that a cold snap or heat wave could create a shortage. As of late February 2026, working gas in storage stood at 1,886 billion cubic feet (Bcf). That’s 43 Bcf below the five-year average of 1,929 Bcf. While still within the historical range, a below-average position heading into spring means less margin for error. If the coming injection season (when gas is pumped into storage from April through October) falls short, prices could spike again heading into winter.
Power Plants Keep Burning More Gas
Natural gas generated 42% of all U.S. electricity in 2024, making it by far the largest single fuel source in the power grid. That share has grown steadily over the past decade as coal plants have retired and utilities have leaned on gas-fired generation to complement growing renewable capacity. The problem is that this makes electricity demand and natural gas demand increasingly intertwined. A hot summer that drives up air conditioning use also drives up natural gas consumption, tightening supplies and pushing prices higher. The power sector now competes with LNG exporters, industrial users, and residential heating for the same pool of gas, creating more upward pressure on prices than existed a decade ago.
Where Prices May Go From Here
The EIA’s most recent Short-Term Energy Outlook projects Henry Hub prices will average about $3.76 per MMBtu in 2026 and rise to roughly $3.90 in 2027. Those forecasts were actually revised down by about 12 to 13% from the prior month’s estimates, reflecting the pullback from the early-2026 spike. Still, even these lower projections represent prices well above the sub-$2 levels that were common in 2024.
The structural factors keeping prices elevated aren’t going away anytime soon. LNG export capacity will keep expanding through the rest of the decade. Production growth in the biggest gas-focused basins is constrained by pipeline bottlenecks and cautious drilling activity. And the power sector’s appetite for gas continues to grow. Prices will fluctuate with weather, storage levels, and global demand, but the era of extremely cheap natural gas that defined much of 2023 and 2024 appears to be over for now.