The US natural gas market is entering the summer cooling season with a clear set of fundamentals. Production at approximately 108 Bcf/d is roughly balanced with total demand when LNG exports and domestic consumption are combined, meaning storage injections will depend on the weather-driven variability of cooling demand.
Typical summer inject rates of 60-80 Bcf per week are expected through June and July. The current storage surplus of 200 Bcf above the five-year average provides a cushion, but if the surplus narrows faster than expected — due to higher LNG exports or hotter-than-normal temperatures — the market could tighten.
The forward curve currently prices Henry Hub at $3.00-3.50/mmBtu through the summer months, with winter strip at $4.00-4.50/mmBtu. This backwardated (actually contango) structure reflects the market's assessment that the current storage surplus will be worked off through the injection season.
A key risk factor is extreme summer heat. A hotter-than-normal summer across the US South and Midwest could drive cooling demand above 45 Bcf/d on peak days, accelerating storage draws and pushing prompt-month prices toward the $4.00/mmBtu level.
On the production side, associated gas from Permian Basin oil drilling continues to provide a steady base supply, but declining well productivity suggests production growth may moderate. The Haynesville Shale, which had been a growth engine for dry gas production, is now in a flat-to-decline phase as operators reduce activity.
Summer gas prices are well-supported by LNG demand. For end-users, the $3.00-3.50/mmBtu range offers a reasonable entry point for summer needs. For winter coverage, the $4.00-4.50/mmBtu strip provides a useful benchmark — locking in at current levels protects against H2 price upside.