Natural Gas (NYMEX)

This page tracks the NYMEX Henry Hub natural gas price — the US benchmark, set at the Henry Hub pipeline interchange in Erath, Louisiana, where more than a dozen interstate and intrastate pipelines meet. The NYMEX futures contract (ticker NG) settles against delivery at this hub in units of 10,000 MMBtu, quoted in dollars per million British thermal units. When headlines say "natural gas prices," this is the number they mean.

Henry Hub matters far beyond Louisiana. It is the pricing anchor for most US physical gas contracts, the settlement reference for the deepest energy derivatives market after crude oil, and — since the US became the world's largest LNG exporter — an increasingly global price. European TTF and Asian JKM gas prices now transmit into Henry Hub through the LNG arbitrage channel: when export terminals run at capacity, marginal US molecules price against world demand, not just domestic weather.

Henry Hub trades near $2.73/MMBtu in late July 2026, mid-summer cooling season, when air-conditioning power burn competes with the storage injections that build inventory for winter. Prices in the $2-3 band are the post-shale normal: high enough to keep dry-gas basins running, low enough to reflect a market that remains structurally oversupplied at the wellhead, with US production running near record levels above 105 Bcf/d.

The weekly rhythm is set by the EIA's Natural Gas Storage Report, released Thursdays at 10:30 AM ET. The print that matters is the injection (or withdrawal) versus the five-year average for that week: consistently smaller-than-average injections tighten the winter outlook and bid the forward strip; bigger-than-average builds do the opposite. Summer price action is therefore a running referendum on whether cooling demand plus LNG exports can absorb record supply before November.

Natural gas is the most volatile major commodity, and the history shows it. The COVID demand collapse took Henry Hub to roughly $1.48 in mid-2020. The post-Ukraine global scramble for LNG drove it to about $9.68 in August 2022, the highest since 2008. During Winter Storm Uri in February 2021, spot gas at hubs across Texas and the Midcontinent briefly cleared above $20 (with some regional prints far higher) while production froze offline. Between extremes, the shale era has anchored the range near $2-4.

Five drivers explain most moves: weather (heating and cooling degree days dominate demand on a weekly horizon), storage relative to the five-year average, dry-gas production run-rates, LNG export capacity and feedgas flows, and power-sector demand, which is now growing structurally as data-center buildouts add baseload draw. Traders also respect the seasonality embedded in the curve — the March/April spread, the classic "widow-maker," prices the risk that winter ends with storage either critically low or comfortably full.

First, the Thursday EIA storage print against the five-year average, and the running surplus or deficit it implies for end-of-October inventory — the single best summary statistic for winter risk.

Second, LNG feedgas flows. New liquefaction trains ramping on the Gulf Coast add structural demand of multiple Bcf/d; outages at major terminals do the reverse and can move the front month several percent in a session.

Third, power burn and the data-center demand trend. Electricity generation is the fastest-growing source of US gas demand, and hot-summer records now regularly push daily power burn above 55 Bcf/d. Fourth, the production run-rate: sustained declines in dry-gas output below roughly 104-105 Bcf/d would flip the balance tighter. For the term-structure view, compare the front month against the January contract — a widening winter premium is the market pricing supply anxiety it does not yet see in spot.