Why are natural gas prices staying so low?
EIA: U.S. Natural Gas Production On Track for a New Record (Again) in 2026
By Joel Acosta Aug. 20, 2026
The U.S. Energy Information Administration expects U.S. natural gas production to average a record 122.5 billion cubic feet per day (Bcf/d) in 2026, according to the their August Short-Term Energy Outlook. That would top the previous record of 118.5 Bcf/d, set just last year, and continue America’s run as the world’s largest natural gas producer – a title the United States has held every year since 2009.
Two Basins Power the Boom
Through the first half of 2026, U.S. production averaged 121.3 Bcf/d, up 4 percent from the same period in 2025. EIA attributes most of that growth to two regions: the Permian Basin in Texas and New Mexico, and the Haynesville Shale in Louisiana and East Texas.
In the Permian, EIA expects natural gas production to average 29.2 Bcf/d in 2026, 6 percent more than in 2025. Notably, as the basin’s reservoirs mature, the gas-to-oil ratio rises and each barrel of oil comes with more natural gas.
The Haynesville is growing even faster in percentage terms. Production there rose 7 percent (1.1 Bcf/d) in the first half of the year, and EIA forecasts 9 percent growth for full-year 2026. The geology makes that growth notable: at 10,500 to 13,500 feet, the Haynesville ranks among the deepest shale plays in the Lower 48. The basin plays a crucial role for America’s energy dominance given that Haynesville gas sits next door to the Gulf Coast’s liquefied natural gas (LNG) export terminals and one of the world’s largest industrial and petrochemical corridors.
The Buildout Behind the Record
While more pipeline capacity is certainly needed through permitting reform, midstream developers are attempting to match that production growth with new takeaway capacity. EIA reports that Texas originates two-thirds of the 44.9 Bcf/d of new U.S. pipeline capacity planned for 2026 and 2027, and nearly 70 percent of that capacity is already under construction. For example:
- The WhiteWater-led Blackcomb Pipeline is slated to enter service in the third quarter of this year, moving 2.5 Bcf/d of Permian gas from the Waha hub to Agua Dulce in South Texas.
- Energy Transfer’s Hugh Brinson Pipeline follows in the fourth quarter, ramping to 2.2 Bcf/d by early 2027.
- Targa’s 2.0 Bcf/d Apex Pipeline will carry Permian gas all the way to Port Arthur.
The LNG buildout is on a similar timeline. Golden Pass LNG, the QatarEnergy and ExxonMobil joint venture near Port Arthur, began producing LNG this spring and shipped its first cargo to become America’s ninth LNG export terminal, with two more trains to follow into early 2027. Industry analysts expect U.S. LNG export capacity to climb from about 17 Bcf/d at the end of 2025 to more than 19 Bcf/d this year, on a path to exceed 30 Bcf/d by early next decade after developers sanctioned six additional projects in 2025 alone.
The bottom line: EIA’s forecast confirms what the buildout across Texas, New Mexico, and Louisiana already shows: American producers and midstream developers are investing to meet growing demand from LNG exports, industry, and data centers. The United States is an energy powerhouse – and consumers and allies alike are better off because of it.
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Replies to This Discussion
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landownerPermalink Reply by Dale Walton on -
Could be because companies like Apex are running 14 rigs.
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Oil & Gas ProPermalink Reply by Skip Peel - Mineral Consultant on -
Apex entering the Haynesville this year has certainly goosed the rig count. Over Louisiana HA well permits, Apex was responsible for 44 out of 92 or 48% April through June. Apex only had two in July and none so far in August. Apex's rig count has dropped to 4 in E TX, down significantly since the last time I looked. Today, Apex's rig count is 4 in E TX and 7 in LA. The Apex bump has dropped off recently.
The volume of associated gas coming out of Texas and New Mexico is the larger reason for low prices on the Gulf Coast and it will only continue to rise. We can hope for a Fall/Winter bump but in the past it has been marginal. The last winter period HH prices were $2.84 in Oct., $3.38 Nov., $4.42 Dec., $4.69 Jan., $7.46 Feb. and $2.97 Mar. A somewhat improvement from the 2024/2025 winter period.
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Oil & Gas ProPermalink Reply by Skip Peel - Mineral Consultant on -
The average monthly settlement price over the last three years are 2023: $2.74, 2024: $2.27 and 2025: $3.43. Those are Henry Hub prices that no not appear as the gross price on royalty statements. Those gross prices are some variable discount to HH. I think if we apply a discount of ~12% that might get us in the ballpark of what royalty recipients see as their gross price before significant post production deductions. The true net revenue would be considerably less and still require most of us to pay some federal and/or state income taxes on that net income. It will be sometime, maybe mid 2027 before we see how supply and demand balance out. I think that there is currently much more enthusiasm for future demand than there is recognition that a surging supply could keep HH prices in the same general range at the last three years.
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landownerPermalink Reply by Dale Walton on -
Apex and the “war” that boosted oil prices by $20 plus dollars per barrel. Word is Apex is looking to exit later this year for Citadel so that should help. The insanity needs to stop.
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Oil & Gas ProPermalink Reply by Skip Peel - Mineral Consultant on -
I think Apex has already shifted gears. Much of the company's permits and rig count were the result of forming new Haynesville units that had to be HBPed and the acquisition of existing units from other HA operators that had low unit production and needed a new well to safely maintain the underlying leases. As those goals are accomplished Citadel can sit back and wait for the stars to align for a profitable exit if that is their long term strategy.
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