Henry Hub natural gas futures settled at $3.198/mmBtu, easing -1.08% on the session, as the market weighs slower-than-average storage injections against rising production and moderating weather-driven demand.
EIA weekly storage data showed an injection of 78 Bcf for the week ending June 12, below the five-year average of 85 Bcf and the analyst consensus of 82 Bcf. Total working gas in storage stands at 2,480 Bcf, approximately 85 Bcf below the five-year average.
The injection deficit to seasonal norms is driven by stronger-than-expected power burn for early-summer cooling demand and higher LNG feedgas volumes. Lower 48 state natural gas production averaged 104.8 Bcf/d in June, up 0.8 Bcf/d from May but still below the 2025 exit rate of 106.2 Bcf/d.
LNG feedgas demand averaged 14.2 Bcf/d in the first three weeks of June, up from 13.5 Bcf/d in May. Freeport LNG's Train 3 returned from a scheduled maintenance outage, adding 0.7 Bcf/d of feedgas demand. Plaquemines LNG (Phase 1) continued commissioning, drawing an average of 0.4 Bcf/d.
The storage trajectory is critical for the winter 2026-27 price outlook. At the current injection rate of 76 Bcf/week, total storage would reach approximately 3,550 Bcf by November 1 — below the 2025 injection season finish of 3,680 Bcf. A colder-than-normal winter would create price upside risk for Q1 2027 delivery.
The below-average injection pace warrants hedging for Q1 2027 exposure. If storage ends injection season below 3,550 Bcf, winter pricing will carry a premium. Buyers with winter gas exposure should layer in protection at current prompt prices of $3.20/mmBtu.