Henry Hub brushes $3 as LNG exports hold firm, but EIA forecasts near-term retreat

Henry Hub brushes $3 as LNG exports hold firm, but EIA forecasts near-term retreat Front-month gas posted a 7.4% weekly gain on export resilience, even as the EIA projects a Q2 average well below current spot levels. Front-month Henry Hub futures settled at $2.96/MMBtu last Friday, gaining 2.3% on the day and 7.4% for the week as expectations of hotter weather, stronger power-sector demand, and resilient LNG exports drew buyers back to the market.¹ The week's gain sits in direct tension with the EIA's near-term view. The agency projects Henry Hub will average $2.83/MMBtu in the second quarter of 2026, 11% below the same period last year and below where the market already trades.² Adequate storage and rising production make the agency's caution hard to dismiss. Lower 48 marketed output averaged 117.2 Bcf/d in the first quarter of 2026, up 4% year on year. The EIA expects 3% production growth for the full year, driven mainly by the Permian basin at a projected 29.2 Bcf/d, 6% above 2025 levels, with Haynesville growing 6% this year and 8% in 2027.² Associated gas is climbing with crude, as higher oil prices incentivize drilling in liquids-rich plays that co-produce gas whether producers want it or not.⁸ Storage ended winter at 1,908 Bcf, 4% above the five-year average. The heating season drew more than 2,020 Bcf from underground storage, 4% more than the five-year norm, yet the market exited without a supply deficit.² For the bears, this is the summary: a cold winter, heavier-than-average withdrawals, and prices are still fighting to hold $3. Morgan Stanley's view diverges sharply. The bank sees Henry Hub reaching $5/MMBtu in 2026 as LNG demand rises and domestic supply growth fails to keep pace.⁵ Last week's export data offered supporting evidence. Weekly LNG vessel departures reached 141 Bcf, up 26 Bcf from the prior week, despite maintenance curtailing several export facilities.¹ Projects like Golden Pass and Plaquemines are expected to add significant capacity later this year; if they ramp ahead of production growth, the Morgan Stanley scenario gets traction. LNG demand is not something U.S. production can resolve in isolation. Entso-G, the European gas TSO group, said EU storage may reach only 76% of capacity by October if global LNG supplies remain tight through summer because of geopolitical risks in the Middle East.³ A storage fill that low would push European buyers into the Atlantic Basin market aggressively from autumn, competing against Asian demand for the same cargoes. The European premium is already signalling stress. Analysts told Montel that German Q2 spot gas prices could jump 40% year on year, with power prices rising 17% in the same period.⁴ At that differential, re-routing Atlantic cargoes to Europe is commercially rational for cargo operators, tightening the U.S. domestic balance in exactly the months when gas-to-power demand typically softens. Domestic demand is not steady either. Southeast U.S. gas consumption rose 26%, or 3.5 Bcf/d, this week, with residential and commercial use surging 54% and power sector demand up 17%, both driven by warmer weather arriving early.⁷ Single-week swings of this size shift the weekly storage report and can quickly alter the injection trajectory heading into summer. The EIA's full-year 2026 Henry Hub forecast sits around $3.80/MMBtu, implying a back-half recovery that requires LNG offtake to outpace production growth or a disappointment in gas-focused plays.⁶ Haynesville is projected to grow 6% this year. Whether that is enough depends entirely on how fast new export terminals absorb available volumes. For traders, the near-term read is bearish: storage is above average, production growth is intact, and Q2 seasonality is soft. The forward tension is in the LNG ramp. If Golden Pass and Plaquemines load at projected capacity while Haynesville growth stalls, Morgan Stanley's $5 call becomes the base case rather than the outlier. The next signal is whether weekly LNG departures sustain last week's elevated pace through June and whether storage injections track below seasonal norms into summer.^1,2,5