Natural gas prices have edged above $3/MMBtu as summer heat drives cooling demand. Cooling degree days surged to 66 last week, up from 36 the prior week and 34% above the 20-year mean. The NGSA projects a record summer power burn of 40.3 Bcf/d, driven by coal-to-gas switching and data center load growth.
But the market remains fundamentally comfortable. EIA data shows working gas in storage at 2,686 Bcf as of June 5, 151 Bcf above the five-year average. The 108 Bcf injection for that week was in line with seasonal norms. Inventories are expected to exceed the five-year maximum by end-October, per the EIA.
Production is the structural story. US dry gas output averaged ~109 Bcf/d in early June and the EIA projects 111.0 Bcf/d for full-year 2026, up from 107.7 Bcf/d in 2025. This growth is driven by associated gas from Permian oil production, which benefits from higher crude prices. LNG exports are at 17.6 Bcf/d and expected to reach 17.2 Bcf/d average for the year.
The EIA's June STEO projects Henry Hub averaging $3.34/MMBtu in H2 2026 and $3.46 in 2027. This was revised down from earlier forecasts as production growth outpaces demand. The agency noted that the price curve retains its shape but has been 'translated vertically downward.'
LNG feedgas has dipped from the March record of 19.7 Bcf/d due to maintenance at Golden Pass and Freeport LNG. Cheniere's Corpus Christi Stage 3 expansion is commissioning, which should add structural demand later in 2026. The US is on track to export 17.2 Bcf/d on average this year, up from 15.1 Bcf/d in 2025.
The $3 handle is the new normal — sub-$2 days are structurally gone with 17+ Bcf/d of LNG export capacity. But production growth is keeping a lid on prices. Buyers should lock summer baseload at current $3 levels rather than wait for a heat-driven spike. The real tightening comes in winter, when the December futures premium above $4 reflects genuine supply risk. For fixed-price procurement, hedging winter at $4+ is expensive but warranted given depleted storage flexibility.