The Energy Information Administration's Natural Gas Monthly, last released on 30 September, now carries a complete supply and disposition balance for the United States through July 2026. It is the most detailed public account of where American gas went during a year in which new liquefaction capacity on the Gulf Coast pushed LNG exports to record levels. The weekly storage figures and the daily Henry Hub price describe the market as it moves. The monthly balance is slower, but it is the only source that adds up production, imports, storage, consumption by sector and exports in one set of numbers.
TEI converted each EIA monthly series from million cubic feet to billion cubic feet per day and compared the first seven months of 2026 with the same months of 2025. The calculation uses EIA's published series without adjustment. Because 2026 January–July has the same 212 days as 2025, the daily averages are directly comparable.
Production
US dry gas production averaged 111.10 Bcf/d from January to July 2026, against 106.49 Bcf/d a year earlier. That is an increase of 4.61 Bcf/d, or 4.3%. Output rose in every month on a year-on-year basis, from 4.48 Bcf/d higher in January to 5.71 Bcf/d higher in July, when it reached 113.71 Bcf/d.
The growth came from a small number of states. On EIA's marketed production series, which is measured before processing and so runs higher than dry gas, the national total rose 5.30 Bcf/d. Texas added 1.87 Bcf/d, New Mexico 1.20 Bcf/d and Louisiana 1.17 Bcf/d. Between them those three states supplied 80% of the national increase. Texas and New Mexico share the Permian Basin, where gas is produced alongside oil, and Louisiana's growth comes from the Haynesville shale, which sits a short pipeline haul from the Gulf Coast export terminals.
Pennsylvania, the largest producing state in Appalachia, averaged 21.17 Bcf/d against 21.19 Bcf/d in 2025. West Virginia and Ohio together added 0.54 Bcf/d, so the region contributed about a tenth of the national increase.
Where it went
The table below is TEI's year-on-year comparison of the main lines of the EIA balance, January to July, in Bcf/d.
- Dry production: 106.49 in 2025, 111.10 in 2026, change +4.61
- LNG exports: 14.19, 17.39, +3.20
- Pipeline exports to Mexico: 6.66, 6.77, +0.12
- Pipeline exports to Canada: 2.76, 3.11, +0.35
- Total imports (almost all pipeline gas from Canada): 8.85, 8.34, −0.51
- Electric power consumption: 34.88, 35.80, +0.92
- Industrial consumption: 23.72, 23.72, no change
- Residential consumption: 14.69, 13.62, −1.08
- Commercial consumption: 10.51, 10.00, −0.50
- Lease and plant fuel: 5.52, 5.77, +0.25
- Net withdrawals from storage: 1.36, 0.76, −0.60
LNG exports took 3.20 Bcf/d of the 4.61 Bcf/d production increase, or 69%. Counting all exports and the fall in imports from Canada, the net export position of the United States grew by 4.18 Bcf/d, equal to 91% of the rise in production.
Total US consumption fell slightly, by 0.43 Bcf/d. A drop of 1.58 Bcf/d in residential and commercial use more than offset the 0.92 Bcf/d increase in gas burned for power. Industrial use was unchanged to two decimal places. Less gas was taken out of storage over the seven months than in 2025, which also counts as a use on the disposition side of the balance. EIA's balancing item, the gap between measured supply and measured disposition, was 0.29 Bcf/d in 2026 against 0.02 Bcf/d in 2025. That is small relative to the changes discussed here, though it is not zero.
The shares are an accounting result. A molecule produced in New Mexico is not tagged for a particular terminal. What the balance does show is that in 2026 the domestic market as a whole used slightly less gas than in 2025, and almost all of the additional supply left the country.
January is the outlier
The seven-month comparison includes January 2026, when winter storm Fern drove Henry Hub to a monthly average of $7.72 per MMBtu, the highest since 2022. In that month LNG exports were 4.01 Bcf/d above January 2025 while gas burned for power was 1.03 Bcf/d lower. FERC staff's review of the storm, which TEI [covered in September](/articles/2026-09-14-ferc-review-winter-storm-fern.html), describes the demand and outage conditions during the event.
Excluding January changes the picture somewhat. From February to July, production rose 4.63 Bcf/d and LNG exports 3.06 Bcf/d, so LNG took 66% of the increase and net exports 89%. Power-sector burn rose 1.25 Bcf/d over the same six months, equal to 27% of the production gain. Henry Hub averaged $3.07 per MMBtu from February to July 2026, against $3.51 in the same months of 2025, a difference of 44 cents.
The monthly pattern of power burn lines up with that price gap more closely than it does with the export ramp. The largest year-on-year increases in gas burned for power came in March (2.82 Bcf/d) and April (2.25 Bcf/d), when Henry Hub was $1.08 and $0.65 below its 2025 level. June was the only month after January in which the 2026 price was higher than the year before, by 13 cents, and it was also the only month after January in which power burn was lower, by 0.42 Bcf/d. Weather, coal plant availability and solar additions also move power-sector gas use, and the monthly balance does not separate those effects.
Capacity behind the exports
EIA attributed the 23% rise in first-half LNG exports to new liquefaction capacity. In its 1 September note the agency said Plaquemines LNG was exporting at full capacity and that Corpus Christi Stage 3 was running six of seven trains, with the two projects together adding 4.0 Bcf/d of nominal capacity once complete. Cheniere took control of the seventh Stage 3 train on 28 August, which EIA said raised the Corpus Christi terminal's nominal capacity to 3.1 Bcf/d.
Golden Pass, on the Texas side of Sabine Lake, shipped its first cargo in April. FERC's Office of Energy Projects allowed hazardous fluids into the warm end of Train 1 on 29 January and authorized commissioning of the Train 2 systems on 24 June, both under Docket CP14-517. EIA expects Train 1 to add 0.7 Bcf/d of nominal capacity as it ramps through the end of the year and Train 2 to be completed in late 2026.
Monthly LNG exports peaked at 18.49 Bcf/d in March, the month QatarEnergy declared force majeure, and averaged 16.73 Bcf/d in July. Destination data for those cargoes, which TEI analyzed [on 27 October](/articles/2026-10-27-us-lng-asia-swing-eu-refill.html), show the share bound for Asia rising from 7% in January to 41% in May.
Pipelines from the Permian
The production side depends on pipeline additions that are scheduled to arrive during the coming winter. EIA's pipeline tracker, summarized in May, counted 44.9 Bcf/d of capacity planned for 2026 and 2027, of which 29.7 Bcf/d originates in Texas. The Blackcomb pipeline, 2.5 Bcf/d from the Waha hub to Agua Dulce, was due in service in the third quarter of 2026. Phase 1 of the 2.2 Bcf/d Hugh Brinson pipeline was due to start flowing in the fourth quarter, with phase 2 in the first quarter of 2027. The 4.5 Bcf/d Rio Bravo line will carry feed gas to the Rio Grande LNG terminal in Brownsville, and the 2.0 Bcf/d Port Arthur Pipeline Louisiana Connector was expected in the second half of 2026.
Each of those pipelines serves both export terminals and domestic buyers on the Gulf Coast. Their timing matters for how much additional Permian gas reaches the coast this winter, and it is one of the reasons EIA's forecast assumes production keeps rising.
Storage and prices going into November
EIA's Weekly Natural Gas Storage Report released on 29 October put Lower 48 working gas at 3,724 Bcf on 23 October, after an 80 Bcf injection. That is 147 Bcf, or 3.8%, below the same week of 2025 and 38 Bcf, or 1.0%, above the 2021–2025 average. The deficit to last year is concentrated in the South Central region, which holds 1,168 Bcf, 8.6% less than a year ago. Salt cavern storage in that region, the fastest-cycling part of the system, holds 274 Bcf, 18.0% below last year and 11.6% below its five-year average. Stocks in the East and Midwest are slightly above both comparisons.
The October Short-Term Energy Outlook expects inventories of 3,850 Bcf at the end of October, 2% above the five-year average, under a winter forecast with heating degree days nearly unchanged from last winter. It projects Henry Hub at $3.48 per MMBtu for 2026 and $3.16 for 2027, and $3.09 for February through December 2027, the same as the corresponding months of 2026. Its forecasts for 2027 have dry production rising 3.93 Bcf/d to 116.13 Bcf/d, LNG exports rising 1.0 Bcf/d to 18.6 Bcf/d and total consumption rising 1.46 Bcf/d.
Henry Hub spot prices averaged $3.04 per MMBtu over the 19 trading days from 1 to 27 October, by TEI's calculation from EIA's daily series, compared with $3.19 for October 2025. The price fell to $2.52 on 26 October. The daily series had not been that low since 22 November 2024, when it closed at $2.41.
The Natural Gas Monthly with August data is due at the end of October. The weekly storage report for the week ending 30 October is due on 5 November, and the next Short-Term Energy Outlook on 10 November.