Natural gas prices have climbed sharply, with the Henry Hub spot price averaging $7.72 per million BTU in January 2026, roughly double what it was just a year or two prior. Several forces are pushing prices up at once: surging export demand, a cold winter drawing down storage, and the simple fact that the U.S. now supplies a huge share of the world’s gas while also burning more of it at home than ever before.
LNG Exports Are Pulling Gas Out of the Country
The single biggest structural change in the U.S. natural gas market over the past decade is liquefied natural gas exports. The U.S. went from exporting just 0.5 billion cubic feet per day in 2016 to 11.9 billion cubic feet per day in 2024, making it the world’s largest LNG exporter. That number is projected to jump another 19% to 14.2 billion cubic feet per day in 2025, then climb again to 16.4 billion cubic feet per day in 2026 as new export terminals come online along the Gulf Coast.
Every cubic foot shipped overseas is a cubic foot unavailable to American homes, power plants, and factories. The EIA has modeled this relationship directly: higher LNG exports pull gas out of underground storage, tightening domestic supply and pushing prices up. Lower exports do the reverse. This isn’t a temporary blip. New export facilities take years to build, and the ones ramping up now will keep pulling gas from the domestic market for decades.
The European Union’s decision to phase out Russian natural gas imports by November 2027 is a key driver of this demand. Europe needs replacement supply, and American LNG is filling the gap. Asian buyers are competing for the same cargoes. The growing share of flexible LNG contracts means these regional markets are more connected than ever, so a cold snap in Europe or a supply disruption in Asia can ripple back to U.S. prices almost immediately.
Storage Is Tight After a Cold Winter
As of late February 2026, U.S. working gas in underground storage sat at 2,018 billion cubic feet, just 7 billion cubic feet below the five-year average. That sounds close to normal, but the context matters. Severe winter weather in early 2026 drove heavy heating demand, and the EIA raised its natural gas price forecast specifically because of increased withdrawals during that cold stretch. Storage levels that look adequate on paper can still support high prices when the market expects continued draws or sees little cushion against another cold spell.
Power Plants Burn More Gas Than Ever
Natural gas generated 43.1% of all U.S. electricity in 2023, making it by far the dominant fuel for power generation. That share has grown steadily as coal plants have retired and new gas-fired plants have replaced them. This means electricity demand and gas demand are now tightly linked. Hot summers with heavy air conditioning loads and cold winters with electric heat both spike gas consumption.
The price impact falls hardest on the power sector. The EIA forecasts that prices paid by electric power plants will increase 37% in 2025 compared to 2024 averages. Industrial customers face a 21% increase. Residential and commercial customers are somewhat insulated because their rates are set through longer-term contracts and regulated utility pricing, but they’re still looking at roughly 4% increases on average.
Infrastructure Is Playing Catch-Up
The U.S. produces enormous volumes of natural gas, but getting it from wellheads to where it’s needed requires pipelines, and pipeline capacity hasn’t kept pace with demand in every region. About 85% of new pipeline capacity built in 2025 (roughly 5.3 billion cubic feet per day) was dedicated to the South Central region, particularly the Gulf Coast. Two major projects alone added 3.5 billion cubic feet per day of capacity connecting the Haynesville shale formation in Louisiana to processing hubs, while three other projects added 1.8 billion cubic feet per day for Gulf Coast delivery.
These projects are responding to the explosive growth in LNG export demand along the coast. But until new pipelines are fully operational, bottlenecks can trap gas in producing regions while consuming regions pay premium prices. The infrastructure buildout helps over time, but in the short term it reflects just how much new demand the system is trying to absorb.
Production Economics Have Shifted
For years after the shale revolution, natural gas was almost too cheap. Producers struggled to turn a profit. Research from Harvard Kennedy School estimated the breakeven price for profitable shale gas extraction at around $4.04 per million BTU without LNG exports. With prices now well above that threshold, producers are profitable, but there’s less incentive to flood the market with additional supply when discipline keeps prices (and margins) higher. The days of $2 gas that defined much of the late 2010s and early 2020s reflected an oversupplied market. Today’s market is closer to balanced, and balanced markets price higher.
What Prices Look Like Going Forward
The January 2026 spike to $7.72 per million BTU was partly seasonal, driven by winter heating demand and cold weather. The EIA’s official forecast expects prices to settle lower over the full year, averaging $4.31 per million BTU in 2026 and $4.38 in 2027. That’s a significant drop from the January peak but still meaningfully higher than the sub-$3 averages that were common just a few years ago.
The forces keeping prices elevated are mostly structural. LNG export capacity will keep growing. Power generation will keep leaning on gas. Global buyers will keep competing for American supply. Prices will fluctuate with the weather and with geopolitical developments, but the era of consistently cheap natural gas in the U.S. has likely passed. The market has fundamentally changed from one where nearly all production stayed domestic to one where American gas competes on a global stage, and domestic consumers now pay prices that reflect that global demand.