Fueling the Planet

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Since 2023 the United States has been the world’s top exporter of liquefied natural gas (LNG), ahead of Australia and Qatar. In fact, a recent report by the U.S. Energy Information Administration (EIA) showed that the top U.S. gas basins—the Permian is second only to Appalachia—produce more than most entire countries.

In 2022, the EIA showed Texas (24 percent of the U.S. total) producing more natural gas than any state (Pennsylvania was second at 21 percent). That’s because the Appalachian Basin stretches across several states, while the Permian is primarily in Texas, although the two New Mexico counties are among its top producers.

And the Permian is getting gassier as extended production, especially in long laterals, reduces formation pressure and releases more natural gas. With that, and with its proximity to LNG ports along the Texas and Louisiana gulf coast, is it poised to be a world leader in LNG supply?

To explore that topic, we talked in three separate interviews with three experts: East Daley’s Natural Gas Team Lead Oren Pilant; Josephine Mills, analyst for Enverus Intelligence Research (EIR); and Midland-based natural gas marketing consultant Mike Banschbach.

The top three issues for this topic involve whether ongoing production amounts will rise or fall and whether there will be enough pipeline capacity to deliver the gas, as well as expectations for LNG facility capacity/world demand.

Growth is seen both in Permian production and in LNG demand, so midstream growth is essential, everyone agreed.

Permian Basin Production on the Rise

In November 2025 EIR released a report titled “Permian and coastal gas pipeline buildout key to meeting surging U.S. LNG export demand.” That report said, “The Permian Basin’s dry gas output is forecast to increase to approximately 40 Bcf/d by 2050, but further infrastructure and resource development will be necessary to close a projected 2–8 Bcf/d supply gap by 2035.”

Pilant’s figures focused on the near term. “Through 2030 we expect to see on the order of five to six BCF a day of incremental gas growth. That’s residue gas, after NGL [natural gas liquids] processing.”

But there’s a question: The EIA and others are predicting Permian oil production to drop slightly in 2026 because the current low oil prices (at this writing, in January) are at or below the breakeven point for new production in most shale basins. That means drilling may slow to the point that there aren’t enough new wells to overcome the decline curve in existing wells. In light of that, why is natural gas supply expected to grow? It’s because Permian wells are getting gassier, Banschbach explained.

“As horizontal wells decline in oil production, the gas-oil ratio (GOR) increases so that gas will not decline as fast as oil, and in some cases, not decline at all,” he said. Permian drilling is most definitely driven by oil price, so if the oil price declines one would expect oil production to decline, and gas production would decline but at a much slower rate.

“But, returning shut-in gas to production and completing DUCs [drilled, uncompleted] wells, where a large portion of capital has already been spent, could easily offset that decline.”

No one is drilling specifically gas wells around here. The only area where that’s even likely is in the Alpine High near Pecos. Apache (now APA) did some drilling there in 2018, said Pilant, but moved on after that.

Getting It There is Half the Fun

Balancing new pipeline capacity with the rise in production is always tricky. Too much capacity and midstreamers lose money. Too little capacity, and producers lose money due to lower gas prices at the critical Waha hub.

How will that play out? Here’s where the expert opinions diverge.

New capacity will help, said the Enverus report, noting that by 2030 9.0 Bcf/d of new Gulf-Coast-aimed pipeline capacity is expected to be online.Added Mills in a follow up email interview, “The gas infrastructure under construction will enable operators to drill in gassier intervals—not to target gas but to continue to focus on oil recovery.”

East Daley’s Pilant gave a similar answer and listed why he agrees. He noted that Energy Transfer has upsized both their Desert Southwest project (upsizing announced December 18) and its Hugh Brinson line. Desert Southwest will help with takeaway but is aimed west instead of toward the coast. Eiger Express was also upsized recently.

Those additions should be enough that “Generally, we think there’s going to be a hard time filling all of that egress capacity [because] the Permian isn’t really a gas-driven basin. And I think you would need a very significant shift in economics to flow an additional 10 BCF a day of gas out of the Permian, which is what it would take to really fill up those pipelines,” Pilant said.

Banschbach is more skeptical about any oversupply in takeaway capacity. He said, “The producing community has seen flowrates on new pipelines [GCX, PHP, Whistler and Matterhorn] increase to capacity shortly after being put in service, and the Waha basis widens.”

Some gas production is shut in now, he noted. Also, any DUC completions, encouraged by temporarily stronger Waha prices due to the new pipelines, could, ironically, add enough supply to flood the capacity and drop prices again.

He does see space available in three underutilized pipelines that funnel gas to Mexico. Should demand from that nation rise, it could siphon off some extra gas production to stabilize prices, although that supply would not then be available to U.S. LNG plants.

Coasting into the LNG Plants

With all this, there’s still one more step. Once the gas arrives at the coast, it still must get to LNG plants. To that end Enverus expects “more than 12 Bcf/d of additional pipeline capacity along the coast dedicated to supplying LNG facilities.”

Getting supply to the Gulf Coast in general still misses the “last mile,” Banschbach pointed out. Many LNG terminals are close to the Houston Ship Channel, the destination of many current pipelines. But new terminals east of there have yet to find ample supply, as noted by price differences.

“Houston Ship Channel gas seeking the higher prices further east is constrained due to lack of pipeline space,” he said. “When we see a large basis between two geographic areas, many times that is due to lack of pipeline space, because if there was sufficient space to transport, that gas would find its way there. Like water flowing to the lowest point, gas flows to the highest pricing point.”

Challenges—Other Feedstock, Permian’s Nitrogen

As stated above, Appalachia produces more natural gas than the Permian, but its geography puts it much further from the concentration of LNG facilities on the Gulf coast. Plus, Appalachian pipelines would have to cross many state lines, creating regulatory nightmares that are already keeping it from going even to nearby states like New York—while Permian natural gas generally crosses no state lines, except for some going next door to Louisiana.

Permian natural gas could be hindered by one quality—its relatively high nitrogen content. Mills and Pilant pointed out that it has a higher nitrogen content than that of the Eagle Ford or Haynesville (the other basins within range of LNG terminals). That creates challenges for LNG plants in the chilling process because nitrogen liquefies much sooner than natural gas. That could cause issues with LNG trains.

Opinions on how to handle that issue were varied.

Mills sees an option of removing the nitrogen in the field. This extra expense works because “the economics are driven by oil, [so] we see the additional cost of processing the gas as nominal.”

Pilant is not convinced of the economics of processing. “You need specific nitrogen removal units, which are very expensive,” to do the job.

His better, but admittedly still not perfect, option is to mix Permian natural gas with less nitrogen-rich supplies from the Eagle Ford, to reduce nitrogen’s percentage. “But,” he cautions, “I think you could still see problems, particularly on the Texas Gulf Coast.”

For him it would be still better to direct more Permian supply to gas-fired generation for data centers, because there the nitrogen content “doesn’t matter.”

Increasingly, companies are indeed avoiding the takeaway capacity blues by co-locating power generation on the well site. And while that does help Waha prices and makes economic use of otherwise trapped natural gas, it doesn’t feed the increasingly hungry LNG system.

LNG Demand and Processing Capacity

The third link in the chain is on the Gulf Coast and the international markets beyond.

Enverus’s study expects LNG feedgas demand to reach 33 Bcf/d by 2030, possibly rising to 50 Bcf/d by 2035, “outpacing current domestic supply growth.” It points out that, in addition to the Permian, another LNG supplier is the Haynesville, a primarily gas formation in East Texas and Northwest Louisiana. But the latter is expected to peak at 19 Bcf/d in 2033, then begin a slow decline, “limiting its ability to support future LNG expansions.”

Further Permian growth could fill the gap, said Enverus’s Mills. “Permian natural gas output will continue to grow through to 2050. Haynesville is the marginal molecule. If the Permian grows more than we’ve forecast, it will offset growth needed from the Haynesville.”

Here’s how she sees that growth happening. “The gas infrastructure under construction will enable operators to drill in gassier intervals [not to target gas but to continue to focus on oil recovery], which will provide much of the required feedgas to the Gulf Coast.”

What about the LNG trains themselves? East Daley’s Pilant sees new builds slowing down for the near future, after several trains reached FID (final investment decision) in 2025.

He said, “One indicator of that is that, increasingly, we’re seeing FIDs made on one train at a time. In Rio Grande LNG, NextDecade’s project in Brownsville, Texas, they first FID’d trains one through three. Then in the latter half of 2025, they FID’d train four and then train five.” He noted that five more trains are in development but are likely to receive FID one at a time, to avoid oversupply.

Conclusion

There is no real question about the Permian’s significant role in supplying LNG feedstock due to its growing output and its proximity to terminals.

Challenging this is its high nitrogen content that interferes with LNG train operation, along with whether output will continue to rise, even as the prices of its main crop, oil, continue to reduce drilling activity. Should drilling drop more than expected, would the rising GOR in the Permian cover the gap? Other basins, including Haynesville, may be called on to make up the difference.

It all depends on worldwide demand and the U.S. industry’s position in the marketplace.

 

Paul Wiseman writes in the oil and gas sector. His email address is fittoprint414@gmail.com.