The Henry Hub natural gas benchmark is trading around $3.07/MMBtu as of mid-May 2026, down significantly from winter's storm-driven spikes above $7/MMBtu but well above the sub-$2 levels that defined much of 2024. The April monthly average settled at $2.77/MMBtu, and the EIA's May Short-Term Energy Outlook projects full-year 2026 prices averaging approximately $3.50/MMBtu before easing to $3.18/MMBtu in 2027.
The headline figure of $2.50 in the title captures a psychological threshold — the price level around which the economics of LNG exports versus domestic consumption reach an inflection point. At or below $2.50/MMBtu, US gas becomes extraordinarily competitive on global markets, incentivizing maximum LNG offtake. Above it, the domestic market begins to reassert pricing discipline. The market has been trading in a range straddling this level for much of the spring shoulder season, as injection-season dynamics and near-record production vie with relentless export demand.
The LNG revolution is here. The United States exported an estimated 17.9 Bcf/d of LNG in March 2026 — the second-highest monthly volume on record, trailing only December 2025's 18.4 Bcf/d. The EIA forecasts full-year 2026 LNG exports will average 17.0 Bcf/d, up from 15.1 Bcf/d in 2025, a 13% year-on-year increase. US liquefaction terminals are operating at approximately 94% of maximum DOE-approved capacity, with operators describing utilization rates as "near maximum." The Department of Energy reports operational export capacity now exceeds 19 Bcf/d, with an additional 36 Bcf/d of capacity in various stages of operation and construction.
What's driving this? Global disruptions — particularly the Strait of Hormuz closure and damage to Qatar's Ras Laffan facility in March 2026 — knocked out over 10 Bcf/d, or roughly 20% of global LNG supply. European benchmark TTF prices surged to $14.80/MMBtu. The resulting price spreads between US Henry Hub and international benchmarks have made US LNG cargoes extraordinarily profitable, widening margins for exporters and incentivizing every molecule of available liquefaction capacity.
New capacity is arriving just in time. Cheniere Energy began ramping up Train 5 at Corpus Christi Stage 3 in April 2026, adding 0.2 Bcf/d of nominal capacity, with Train 6 expected by summer. Golden Pass LNG (Trains 1–2, totaling 1.4 Bcf/d) and additional Corpus Christi trains (5–7, 0.6 Bcf/d combined) are scheduled to come online through the remainder of 2026, bringing approximately 2.4 Bcf/d of new DOE-authorized capacity online between April and December alone.
Production is responding, but can it keep pace? Lower 48 marketed natural gas production averaged 117.2 Bcf/d in the first quarter of 2026, a 4% increase year-on-year. The EIA forecasts full-year 2026 L48 marketed production averaging 118.9 Bcf/d, rising to 124.0 Bcf/d in 2027. Dry gas production is tracking around 110 Bcf/d, growing approximately 2% year-on-year. The Permian Basin leads this growth, contributing an estimated 1.4 Bcf/d of additional associated gas production in 2026 as oil-directed drilling continues to expand. Appalachia adds a more modest 0.3 Bcf/d, constrained by pipeline takeaway capacity even after the Mountain Valley Pipeline came online.
Yet production growth faces real headwinds. The Permian faces severe pipeline constraints, evidenced by persistently depressed Waha Hub prices. Winter freeze-offs disrupted output in early 2026, and the February STEO noted that weather-related disruptions and Permian pipeline limitations slowed first-half production growth. The EIA expects supply to grow by about 1.1 Bcf/d in 2026 while demand (including exports) rises by about 0.6 Bcf/d — a surplus that would normally push prices lower, except that the composition of demand is shifting decisively toward higher-value export markets.
Storage: a comfortable cushion for now Working gas in underground storage stood at 2,290 Bcf as of May 8, 2026, approximately 140 Bcf (+6.5%) above the five-year average. Inventories are within the historical five-year range, providing a meaningful buffer against early-season weather volatility. The EIA forecasts that storage will end the injection season on October 31 at approximately 7% above the five-year average. This cushion has helped suppress price volatility during the spring shoulder season, with June futures trading in a relatively tight $2.70–2.90/MMBtu range.
The 2025–2026 winter withdrawal season (November–March) saw more than 2,020 Bcf withdrawn — 4% above the five-year average — driven by Winter Storm Fern's record 360 Bcf single-week draw in late January. That storm temporarily pushed Henry Hub above $7/MMBtu and demonstrated just how quickly the US market can tighten when extreme weather and LNG demand coincide.
The winter demand outlook: tightening ahead Looking toward the 2026–2027 heating season, the outlook suggests a gradually tightening fundamental picture. Industrial natural gas consumption is projected to hit record highs, averaging 26.1 Bcf/d in January 2026 and rising to 26.7 Bcf/d in January 2027, driven by a growing natural gas-weighted manufacturing index. Power sector demand continues to expand as data center buildout accelerates electricity consumption growth. With LNG export capacity continuing to ramp through year-end, the competition for molecules between domestic heating and industrial users versus international export markets will only intensify.
The EIA's forward curve implies Henry Hub averaging $3.50/MMBtu in 2026, then declining to $3.18/MMBtu in 2027 as new production gradually overtakes export demand growth. But that forecast carries significant uncertainty. If the Strait of Hormuz disruption persists or if an unusually cold winter arrives, the storage surplus could evaporate quickly, exposing the market to the structural reality that LNG exports have permanently raised the floor under US natural gas prices.
The Henry Hub at $3.07 is increasingly a memory rather than a baseline. The US gas market is no longer a closed system — it is the swing supplier to global markets, and that changes everything about how buyers and sellers should think about price risk.
The structural transformation of US natural gas markets means that the days of sustained sub-$2 Henry Hub pricing are likely behind us. LNG exports are creating a permanent demand floor that will keep markets tighter through the injection and withdrawal seasons. Buyers should evaluate fixed-price forward hedges for winter 2026–2027 exposure given the asymmetric risk of a storage surplus being rapidly eroded by cold weather and sustained LNG offtake. Consider layering in collars or three-way structures to protect against upside while allowing participation in any storage-driven downside. With EIA projecting end-of-injection storage at only 7% above the five-year average, the market has less cushion than headline numbers suggest when measured against potential weather and export scenarios.