Published on: 2026-09-01
Updated on: 2026-09-01
October U.S. natural-gas futures settled Monday at $2.935/MMBtu, up 1.6%, putting $3 back within reach even as U.S. production runs at record levels. Hot early-September weather and LNG feedgas near 19.4 Bcf/d are supporting demand after the latest storage build came in tighter than expected. EIA still expects inventories to reach 3,985 Bcf by the end of October, leaving the shift from summer heat to autumn demand as the harder test for prices.
October natural-gas futures settled at $2.935/MMBtu, up 1.6%, leaving $3 within reach despite record U.S. production.
LNG feedgas reached around 19.4 Bcf/d, while strong heat is expected to support cooling demand for roughly another week.
U.S. dry gas production reached a record 112.33 Bcf/d in June, leaving little room for power demand to weaken without loosening the balance.
The latest storage build was 15 Bcf, below both the 21 Bcf market consensus and the roughly 33 Bcf five-year average.
EIA still expects 3,985 Bcf in storage by end-October, so September must bridge a wide gap between current tight injections and faster shoulder-season builds.
Stronger demand is supporting the latest move. Market weather forecasts at the end of August called for another six to seven days of intense late-summer heat, extending air-conditioning demand into early September. Higher electricity consumption increases gas-fired power burn and leaves less gas available for storage.
LNG exports are adding another demand driver. Feedgas reached about 19.4 Bcf/d on August 31, a two-week high. EIA completed its August outlook on August 6, when maintenance at Freeport and other LNG facilities had reduced feedgas demand.
The weather support has a clear time limit. NOAA’s August 31 update favours above-normal September temperatures across parts of the central and southern United States, with the strongest early-month warmth centred on the central Great Plains. It also added cooler odds in parts of the West and equal chances elsewhere, so a hot first week does not imply an exceptionally hot entire month.
Demand explains the move toward $3. Record production explains why a decisive break above it remains harder.
U.S. dry natural-gas production reached 112.33 Bcf/d in June, up 4.5% from a year earlier and the highest monthly rate in EIA data going back to 1973. Lower 48 output was still estimated near 112.4 Bcf/d at the end of August.
Permian supply may respond slowly to weak gas prices because much of it is associated gas produced alongside crude oil. EIA expects Permian gas production to average about 29.2 Bcf/d in 2026, up 6% from 2025, while total U.S. dry production is forecast to average 111.19 Bcf/d this year.
With output near record levels, even a moderate decline in power burn can loosen the balance quickly once temperatures normalise.
Permian takeaway capacity is becoming less restrictive. Energy Transfer said its Hugh Brinson Pipeline was already in commercial service and expected to be able to flow its full Phase I capacity of about 1.5 Bcf/d by September 1, subject to commissioning progress.
That is transportation capacity, not 1.5 Bcf/d of new production. The added takeaway allows more Permian gas to reach major Texas trading hubs and connected markets as summer demand fades.
U.S. working gas in storage stood at 3,184 Bcf for the week ending August 21, or 167 Bcf above the five-year average. The stockpile remains comfortable, but the latest weekly change showed a tighter balance.
Only 15 Bcf entered storage, below the Wall Street Journal consensus near 21 Bcf and the five-year average build of roughly 33 Bcf. The surprise was bullish in two ways: injections were seasonally small and tighter than expected.
South Central inventories also fell 19 Bcf while total U.S. storage increased. Recent flows are reducing the national surplus even though the overall stock level remains high.
EIA expects inventories to reach 3,985 Bcf at the end of October, about 5% above the five-year average and the highest pre-winter level since 2016. From the latest 3,184 Bcf reading, that requires roughly 801 Bcf of additional storage.
There are about ten weekly injection periods between the August 21 reading and the end of October, implying an average increase of roughly 80 Bcf per week. The latest 15 Bcf build is nowhere near that pace, but it does not need to persist.
September and October are the shoulder season, when cooling demand normally falls before winter heating begins. The real question is how quickly injections move from August’s tight builds toward the much larger increases embedded in EIA’s forecast.
EIA expects the Henry Hub spot price to average $2.87/MMBtu in the third quarter and remain below $3 until November. Recent LNG recovery, heat and tight storage data are challenging that path in the near term without overturning it.
The bull case is temporal. The market may have another week or two of strong late-summer cooling support before the shoulder-season transition becomes increasingly important.
Heat does not need to last indefinitely. It only needs to keep storage injections below normal long enough to tighten the balance before cooling demand fades.
In short, heat has to outrun the calendar. EIA’s September 9 outlook will show whether the agency still expects inventories to approach 4 Tcf before winter.
EIA’s next Weekly Natural Gas Storage Report is scheduled for September 3 and covers the week ending August 28. The headline injection matters, but its comparison with market expectations and the seasonal average matters more.
Another below-consensus, below-normal build would show that power demand and LNG exports are still absorbing enough gas to counter record production. A larger build would strengthen the case for EIA’s high end-October inventory forecast.
So $3 needs confirmation from the physical balance, not weather forecasts alone.
Hot weather increases electricity consumption as air-conditioning use rises. Greater demand for gas-fired generation can reduce the amount of gas available for storage.
Natural gas enters a shoulder season as cooling demand falls before winter heating demand begins. If production stays high, larger volumes can move into storage and weigh on prices.
Yes. Strong cooling demand can be outweighed by record production, weaker LNG feedgas or faster storage injections.
Henry Hub spot prices reflect physical gas for near-term delivery at the Louisiana benchmark, while futures price gas for delivery in a specified future month. The $2.935 figure here is the October NYMEX futures contract, while EIA’s $2.87 forecast is the average Henry Hub spot price for the third quarter.
The next storage data will show whether September demand is still absorbing enough gas to counter record production. Another tight build would keep the recent tightening intact, while a larger injection would show the seasonal supply build is beginning to catch up.
For natural gas to hold above $3, September heat needs to do more than lift demand temporarily. It needs to keep the storage surplus shrinking before the calendar hands the advantage back to record supply.
