CME Group's Henry Hub Natural Gas Futures contract NGU26 was last priced at $2.771, down $0.010 (-0.36%), on volume of 1,420, with market data delayed by at least 10 minutes (CME Group). Over the past three months, front-month gas prices have swung between $2.52 and $2.89 per million British thermal units (MMBtu — a standard unit for measuring natural gas energy content). Two forces have driven that back-and-forth: shifting demand from LNG export plants and modest changes in domestic production.

The most recent meaningful drop came in a July 2026 session, when front-month natural gas futures for August delivery on the New York Mercantile Exchange (NYMEX) fell 6.6 cents, or 2.3%, to settle at $2.888/MMBtu (Reuters). That followed a June 2 decline tied to a four-month low in daily gas flows to U.S. LNG export plants (Reuters). LNG, or liquefied natural gas, is natural gas cooled to liquid form for shipping overseas; feedgas is the gas piped into those export plants to be chilled and loaded onto tankers. As of June 2026, maintenance at LNG export plants had reduced feedgas flows from 17.1 billion cubic feet per day (Bcf/d) in May to 16.5 Bcf/d (Reuters).

That pullback reversed a spring rally. On May 1, 2026, U.S. natural gas futures rose roughly 1% to a three-week high, driven by a production drop over the prior month and near-record LNG exports (Reuters). Before that, the May NYMEX contract had settled at $2.523/MMBtu on April 24, down 15.1 cents from the prior Friday (Natural Gas Intelligence). NYMEX traders use the Henry Hub benchmark — a pricing point in Louisiana tied to a physical pipeline interconnect — to arrive at monthly settlement prices for natural gas (Gas South).

On the supply side, preliminary U.S. dry natural gas production in May 2026 was 3,418 billion cubic feet (Bcf), or 110.3 Bcf/d, according to the EIA's monthly report published July 31 (EIA). Dry gas is gas that has been processed to remove impurities and natural gas liquids, leaving mostly methane ready for market. Production has been a contributing variable throughout the period; the May 1 rally was partly attributed to an output drop in the preceding month.

The EIA forecasts U.S. natural gas consumption in the electric power sector will increase in 2026 and 2027, reaching a record in 2027 (EIA). That demand outlook is structurally supported by the expansion of LNG export capacity. Golden Pass LNG was expected to ship its first cargo in early 2026 (EIA). Back in September 2024, feedgas volumes consumed by U.S. LNG exporters were expected to climb from around 13 Bcf/d to 17 Bcf/d (Reuters). The May 2026 figure of 17.1 Bcf/d confirmed that trajectory before maintenance curtailed flows.

The 12-month natural gas futures strip — a series of sequential monthly contracts that gives a view of average expected pricing over the coming year — averaged $3.970/MMBtu as of January 22, up 65 cents from the prior month (EIA). That strip level implied a much tighter forward curve than the spot prices in the $2.50–$2.90 range that prevailed through the spring and summer.

The gap between the front-month spot settle near $2.89 and the 12-month strip at $3.97 captures the core tension in this market. Near-term prices are being held down by maintenance-driven feedgas weakness and ample production at 110.3 Bcf/d. The forward curve, by contrast, prices in the expectation that LNG export capacity additions — led by Golden Pass — will absorb extra supply and tighten the balance into 2027. The EIA's forecast of record power-sector gas consumption in 2027 reinforces that structural demand story.

The broader context here is straightforward: the market is pricing two different realities at once. Today's gas is plentiful and cheap because export plants are offline for maintenance and production is running hot. Tomorrow's gas, according to the forward curve, should be scarcer and pricier as new LNG export capacity comes online and power-sector demand climbs. For traders and analysts, the key variable to watch is the pace at which LNG export maintenance concludes and feedgas flows recover toward the 17 Bcf/d level. A return to those rates would narrow the spread between spot and forward prices. Prolonged maintenance or any delay in the Golden Pass ramp-up, on the other hand, would keep downward pressure on near-term Henry Hub pricing even as the forward curve stays elevated.