Production has been the story in 2026
US dry gas production averaged 104 Bcf/d in H1 2026, up 2% year-on-year and in line with the EIA's forecast. The Permian and Haynesville basins continue to deliver associated gas volumes despite moderating oil-directed rig activity. The result is a supply environment that is meeting expectations without surprising to the upside.
The production growth rate, however, is decelerating. The US gas-directed rig count has fallen from a peak of 112 in late 2025 to 98 currently. EIA's Drilling Productivity Report shows new-well gas production per rig declining 5% year-on-year in the Haynesville. The marginal cost of new supply is rising, which puts a natural floor under prices.
LNG is the demand story that matters
LNG feedgas demand reached 14 Bcf/d in Q2 2026, up from 12.5 Bcf/d in Q2 2025. The key development in H2 2026 is the startup of Plaquemines LNG (Phase 1) and the Corpus Christi Stage 3 expansion, which will add a combined 3 Bcf/d of liquefaction capacity by year-end. Once these facilities are operational, the feedgas demand floor rises to 16-17 Bcf/d regardless of seasonal weather patterns.
The LNG-driven structural floor is the most important development in the Henry Hub market. Before the LNG export era (pre-2016), Henry Hub was primarily a weather-driven market with inventory builds and draws tied to heating and cooling demand. The LNG link has added a permanent demand source that operates independent of weather. When Henry Hub spot prices fall below the marginal cost of LNG production (estimated at $2.50-3.00/MMBtu for Gulf Coast liquefaction plants), LNG buyers increase feedgas offtake.
Storage is adequate but the injection season is late
Working gas in storage stood at 3,100 Bcf as of early July 2026, roughly 10% above the five-year average. Injections have been running at 70-80 Bcf/week, in line with seasonal norms. The storage surplus provides a comfortable buffer heading into winter, but it also removes the price catalyst that comes from storage deficits.
The EIA's STEO projects Henry Hub averaging $3.00/MMBtu for 2026, with Q4 prices rising to $3.50 as winter heating demand combines with LNG feedgas growth. The range of outcomes is narrow by historical standards, reflecting the increased predictability of the LNG-supplemented market.
Bull, bear, and base cases
The bull case: a colder-than-normal winter combines with the Plaquemines startup to push Henry Hub to $4.50/MMBtu in Q4 2026. European TTF prices remain elevated above $15/MMBtu, keeping LNG cargoes flowing to Europe and limiting Asia pull.
The bear case: mild weather persists through fall, production surprises to the upside, and the LNG capacity additions are delayed. Henry Hub tests $2.50/MMBtu, the marginal cost of Haynesville production.
The base case: normal weather, on-time LNG capacity additions, and production at trend. Henry Hub trades $2.75-3.50/MMBtu for the rest of 2026, exiting the year at $3.25-3.50. The risk distribution is skewed to the upside because the LNG floor is hardening.
Natural gas procurement has changed. The LNG export link has transformed Henry Hub from a weather-driven market to a global gas market with a structural price floor. For industrial buyers: $2.91/MMBtu is close to the floor. Lock in 12-month fixed-price contracts at $3.00-3.10/MMBtu. The risk of a sustained break below $2.50 is low given the LNG export floor and production cost support. For power generators: the Henry Hub-TTF spread of $10-12/MMBtu means US gas is the cheapest energy source in the world. If you have fuel switching capability, gas is deeply undervalued relative to global alternatives — lock in term volumes through Q2 2027.