US natural gas storage inventories are entering the injection season in a position that is neither tight nor ample — a "just right" trajectory that is supporting prices near the $3 level without prompting panic buying. The EIA's weekly storage report estimated a 92 Bcf injection for the week ended May 15, precisely matching the previous five-year average and maintaining the surplus to that marker at approximately 140 Bcf for a third consecutive week.
Surplus dynamics. While the five-year-average surplus has stabilised, the year-over-year surplus tells a more interesting story. A 92 Bcf injection pushed the year-over-year surplus down to 24 Bcf from 51 Bcf in the prior week — a rapid narrowing that reflects the structural tightening of the market as LNG export demand has grown. The year-over-year surplus has now contracted significantly from the peak earlier in the injection season, and if this trend continues, it could flip to a deficit by mid-summer.
FACT: The five-year average for US natural gas storage levels includes years (2021–2025) with much lower LNG export volumes. LNG feedgas averaged 18.1 Bcf/d in April 2026 versus 11.1 Bcf/d in April 2021. This means the five-year average is a progressively less relevant benchmark for assessing current market tightness, as it systematically understates structural demand. Market participants are increasingly focusing on year-over-year comparisons and absolute storage levels rather than the five-year-average surplus.
EIA end-of-season forecast. The EIA's May Short-Term Energy Outlook projects that US natural gas inventories will end the injection season on October 31 at 7% above the previous five-year average. "Higher storage levels help meet demand and reduce the risk of price volatility," the EIA said. This 7% surplus implies end-October storage in the range of 3,750–3,850 Bcf, depending on the exact five-year average baseline — a level that is comfortably above the five-year average but well below the surpluses seen in the 2019–2020 period, when storage approached 4,000 Bcf.
The EIA noted that the 2025–2026 winter heating and withdrawal season saw more than 2,020 Bcf of natural gas withdrawn from storage (November–March), or 4% more than the five-year (2021–2025) average. This relatively strong withdrawal, combined with the structural increase in LNG demand, has left inventories on a tighter trajectory entering the 2026 injection season than would have been the case in prior years.
Injection pace and summer outlook. The 92 Bcf injection is a solid shoulder-season number, reflecting mild weather and moderate power burn. As the summer cooling season begins, power generation demand for natural gas typically rises by 5–10 Bcf/d relative to shoulder-season levels. If summer temperatures are above normal — and the developing El Niño pattern suggests increased risk of heatwaves — power burn could rise further, compressing injection volumes and potentially drawing down the surplus to the five-year average.
The futures curve provides a window into market expectations. Henry Hub futures for the balance of summer (June–August) are pricing in the $3.00–$3.50 range, with winter contracts (December–February) above $4.00. This suggests that the market sees the current storage trajectory as supportive of prices but not tight enough to cause a supply crisis — what one analyst described as a "benign but watchful" equilibrium.
Regional variations. While the national storage picture is relatively balanced, regional dynamics vary significantly. Production-constrained regions like the Northeast may see faster inventory drawdowns if winter is severe, while the Gulf Coast benefits from proximity to both production and LNG demand. The Permian's negative Waha prices (see related article) highlight growing pipeline constraints in the producing region, which could limit the ability to move gas to storage or demand centres during periods of peak supply.
The current storage trajectory supports moderate upside for Henry Hub through the injection season but does not suggest an imminent supply crisis. For procurement planning, the key inflection point to watch is the year-over-year storage surplus as it approaches zero. If year-over-year storage flips to a deficit by July — which is possible given the LNG demand trajectory — the market could reprice summer contracts higher. Hedge summer gas exposure at current forward levels ($3.00–$3.50) as a base case, with contingent coverage for a scenario where year-over-year storage turns negative.