U.S. may struggle to feed LNG terminals, warn analysts at Gastech

U.S. LNG exports are set to double by 2030, and many more LNG projects are proposed around the North American continent. But some analysts warned at Gastech last week that there may not be sufficient U.S. natural gas supply in the long run to feed those LNG export terminals without creating significant upward pressure on prices.

The United States went from exporting essentially no LNG as recently as 2015 to more recently becoming the word’s largest exporter. Henry Hub prices are notoriously volatile, but prices have stayed mostly “range bound” in the past decade, aside from the global energy crisis in 2022, Eugene Kim, research director at Wood Mackenzie, said at the Gastech 2024 conference in Houston on September 17th. Henry Hub has traded well below $3 per MMBtu this year, despite more than 10 percent of gas produced in the U.S. dedicated for export.

“But can we replicate this as U.S. LNG exports are set to double by 2030?” Kim said.

He said that gas demand is displaying more “seasonality” with domestic consumption surging at the same time that LNG exports increase during winter periods. He warned that storage levels are tapped out, so what the market may see in the future is increased “synthetic storage,” by which he meant a drop off in LNG exports during periods of tightness. For instance, if a cold snap swept the U.S. and prices spiked, LNG shipments may grind to a halt for a short period of time so that the gas can serve the domestic market.

However, synthetic storage is “not cheap,” Kim said. “It requires higher gas prices.”

Kenneth Medlock, senior director for the Center for Energy Studies at Texas-based Rice University, was not too concerned about the availability of supply. He noted that the U.S. gas industry has consistently increased production in the past decade, and at lower prices, than industry forecasts had expected.

He pointed to the enormous increase in “associated gas” production — gas that is produced as a byproduct in oil-rich areas of the Permian basin — and the possibility to capture even more of that gas in the future.

“All of the studies that have been done to date have grossly underestimated what associated gas production would look like,” Medlock said. He noted that a lot of that gas is currently flared in West Texas. “You could think about what the implications are if we build pipeline capacity to move those volumes to a place where they could ultimately be consumed or exported.”

Potential supply shortage

Despite the industry’s rapid expansion, U.S. LNG exports may not be able to continue to increase without severely impacting the domestic market.

The global LNG market is set to face oversupply in the late 2020s, with a massive wave of capacity currently under construction, which could weaken prices. But the next tranche of supply in the 2030s could come with many more challenges.

It is not clear that the U.S. has enough gas to continue ratcheting up export volumes, at least not at low prices, said Brandon Stackhouse, an associate partner at McKinsey.

“Are you able to feed these projects with the enormous amount of supply that North America has?” he said at Gastech. “It’s enormous, but it’s not infinite.”

McKinsey’s analysis found a handful of obstacles standing in the way. For instance, in the long run, oil prices may languish around $50-$60 per barrel, which in real terms, will be very low in the 2030s and 2040s. That will reduce drilling activity, and the knock-on effect will be lower associated gas production.

But the bigger problem is that the U.S.’ largest source of cheap gas is concentrated in Appalachia, which has essentially maxed out its ability to build midstream capacity. “It’s very, very hard” to build new pipelines out of the region, Stackhouse said. “We’ve seen pipeline after pipeline…die for a variety of reasons.”

It is unlikely that will change. “We don’t expect there to be that much more” pipeline capacity built, he said. “Appalachia is still going to be the main contributor of natural gas for North America, but we don’t expect it to grow a ton over the next 15 years or so.”

McKinsey estimates that the industry will need an additional 16 billion cubic feet per day (bcf/d) in the long run, a little more than double current export levels.

If Appalachia won’t be able to supply all the new LNG terminals, then the gas will need to come from elsewhere. “You’ve got all of this growth in Gulf Coast LNG, and you aren’t able to actually bring your cheapest source of supply down into the market.”

The problem is that finding supply in other shale formations — the Haynesville, Eagle Ford, mid-continent, the Rockies, or the Permian, for example — will mean sourcing gas from more expensive and less productive regions.

Production rates “are much, much lower than what you have in Appalachia,” Stackhouse said. “That means when you go to do this drilling, you are less capital efficient than you would be if you’re able to do drilling in a region that has more productive wells.”

“Because they produce less from each well, you’re going to need more rigs running in order to get the same level of supply from those regions.”

All told, to supply the increase in U.S. LNG exports without growth from Appalachia would require 100 extra rigs, 10,000 additional wells, and would cost $60 billion more, compared to a scenario in which Appalachia could grow.

In short, the growth of U.S. LNG export capacity will require more expensive gas, which may mean higher domestic gas prices as well. McKinsey said that the long-run equilibrium price could hover around $4 to $4.50 per MMBtu, nearly twice as high as current levels. All that extra drilling will also strain the oilfield services sector — the companies that provide labour, equipment, and fracking crews.

“If you start to see severe services constraints, [gas prices] could go significantly higher,” he said.