Front-month U.S. natural gas futures held near $2.84/MMBtu after another failed test of the $3 level, with the October NYMEX contract expiring Monday and forcing roll-driven positioning into November. Record Lower 48 output of 113.2 Bcf/d is capping rallies, while a storage surplus that narrowed to 118 Bcf and Cove Point's maintenance outage pull in opposite directions.
October Henry Hub natural gas futures traded at $2.84 per MMBtu on Wednesday, holding steady after a fourth failed run at the $3 level, with the contract's expiration on Monday forcing positions to roll into the November heating-season month.
"The market keeps testing $3 and keeps getting turned back because there is 113 Bcf/d of supply sitting on top of it," said Omar Tariq, commodities strategist covering North American gas markets. "Roll week amplifies that — nobody wants to carry October length into an expiry when the physical market is this loose."
The prompt month settled at $2.912 on Friday, September 18, up 1.1 cents or 0.4% and roughly 3% higher on the week. Monday erased that entire gain in a single session. Prices are up 0.30% over the past month and down 9.44% over 12 months. Daily indicator-based signals flipped to sell on Monday evening after sitting neutral earlier in the day.
The stakes sit in the calendar. October expires September 28, and the November contract that takes over carries winter risk premium. Henry Hub spot averaged $3.79 in November 2025, $4.26 in December 2025 and $7.72 in January 2026 before collapsing to $3.62 in February. From $2.84, a repeat of January would be a 172% move — the asymmetry that defines the trade.
Production at 113.2 Bcf/d caps every rally
Supply is the variable that decides this market, and it is running at records. Average Lower 48 output reached 113.2 Bcf/d so far in September, above August's record monthly average of 112.2 Bcf/d. Friday's dry gas production was 113.1 Bcf/d, up 4.4% year over year, while Lower 48 demand was 80.9 Bcf/d, up 2.7%. Supply is growing at nearly double the rate of demand.
The growth is concentrated in the Permian and Haynesville, according to the EIA's September Short-Term Energy Outlook. Permian gas is largely associated production, pulled from the ground alongside crude, which makes it insensitive to Henry Hub prices — with November WTI at $89.42, Permian drilling economics stay strong and the gas keeps flowing. Haynesville, a dry gas play in Louisiana close to Gulf Coast liquefaction terminals, rising at $2.84 means breakevens have fallen far enough for producers to expand at these levels.
That gap is why rallies keep failing near $2.90 and why the calendar 2027 strip has fallen to an average of $3.31 per MMBtu, its lowest since February 2022. A four-year low in the forward curve means the market does not believe rising LNG exports and data center power demand will tighten the balance enough to lift prices next year. The equity market is pricing the same pressure: Coterra Energy (CTRA) fell 8.62% to $32.56 on Tuesday, among the largest declines in the S&P 500, as energy was the weakest S&P sector, down 1.3%.
Storage tightens to 118 Bcf while Cove Point sits offline
The bullish half of the argument is storage, and it is the reason prices have not broken down. In the week ended September 11, energy firms injected 44 Bcf, well below the 87 Bcf added a year earlier and the five-year average of 74 Bcf. Inventories reached 3.298 trillion cubic feet, 3.6% below last year but 3.7% above the five-year average, narrowing the surplus to 118 Bcf from 148 Bcf a week earlier. The surplus peaked at 7.7% above normal in April.
The EIA projects inventories will reach 3,969 Bcf on October 31, the end of injection season, 5% above the five-year average. That forecast was completed September 3, before the recent run of light builds. Getting from 3,298 Bcf to 3,969 Bcf requires 671 Bcf of injections over seven weeks, an average of 96 Bcf per week against recent builds of 44 Bcf.
Thursday's report, covering the week ended September 18, is the next test. A build under 30 Bcf would support a push toward $2.912 and then $3.00. A build above 35 Bcf opens $2.75 and $2.70. A print between 30 and 35 Bcf leaves the contract range-bound between $2.80 and $2.912. The Cove Point outage began Saturday, September 19, so it lands in the following week's data, not this one.
LNG is the other swing factor and it is currently impaired. Feedgas was on track to rise to 18.2 Bcf/d on Friday from a three-week low of 17.1 Bcf/d as Sempra's 2.0 Bcf/d Cameron plant in Louisiana recovered from maintenance. Berkshire Hathaway Energy then took its 0.8 Bcf/d Cove Point facility in Maryland offline Saturday for a few weeks of annual work, pulling roughly 0.85 Bcf/d of feedgas demand out of Appalachia. Six regional hubs there traded at their lowest prices since November 2024. At 18.2 Bcf/d, LNG absorbs about 16% of Lower 48 production, so every 1 Bcf/d lost to maintenance is 1 Bcf/d of extra supply looking for a home.
The near-term map is tight. Support sits at $2.80, then $2.772 and $2.75, with $2.70 the level where Haynesville drilling economics come under pressure and dry gas producers begin curtailing completions. Resistance runs from $2.87–$2.90 to Friday's $2.912 settle, with $3.00 the line that flips the structure. A daily close above $3.00 would require a storage build under 30 Bcf, heat holding across the South and LNG feedgas above 19 Bcf/d — a combination not currently in forecasts, which call for benign weather through early October and above-average temperatures covering a shrinking area of the South and Southeast.
The risk-reward at $2.84 favors patience. Downside to $2.70 is $0.14; upside to $3.00 is $0.16. At $10,000 per point, that is $1,400 of risk against $1,600 of reward. For traders looking for winter exposure, the November contract and later is the cleaner expression than the October contract that expires Monday.
This article is for informational purposes only and does not constitute investment advice.
