US Permian Gas Surge Set to Upend Once-Tight Regional Basis

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The Permian Basin’s bounty of associated gas might be a curse for any supply holder coveting a tight basis to the Henry Hub. And as more gas flows east from the West Texas play, the price-dampening impact will only grow.

Why? Because Permian producers are not interested in whether there is a market for the gas once it exits the basin, they are concerned about producing and profiting from the oil from which the gas rises.

Even with the US gas market at 14-year highs, expansion and new build gas pipeline decisions have little to do with monetizing the commodity. And with 4.2 billion cubic feet per day of new takeaway capacity planned through 2024, it doesn’t matter if the LNG buildout that might absorb the flood could be years away if it materializes at all.

There is no doubt that growing associated gas production in the Permian is already weighing on Texas Gulf Coast markets.

Energy Intelligence data show that in the year before that initial round of egress pipeline projects began being rolled out, Waha spot prices traded at an 84¢ average discount to Henry Hub, while prices along the Texas Gulf Coast traded near parity with Henry Hub.

Today, West Texas prices trade at less of a discount to Henry Hub, but the ability to move associated gas production to the Gulf Coast has depressed prices at markets that have shown relatively little demand growth.

As the Waha discount to Henry Hub climbed to more than $1 in August — due in part to pipeline maintenance — that of Houston Ship Channel and Katy Hub reached 66¢ and 67¢, respectively.

How the next round of takeaway capacity expansions will affect Gulf Coast markets depends on the region’s ability to soak up growing supply. So it’s certain that downward price pressure will get much more pronounced before it recovers.

The midstream sector has done its part to clear the path for a 2.7 million barrel per day growth in oil production since 2017, especially as gas flaring becomes less of an option.

That oil growth also spurred a 11.6 Bcf/d per day jump in gas production since 2017 and an epic glut of gas that overwhelmed exit pipelines by 2019.

Among the major midstream projects contributing or soon adding to oversupply in the Texas market:

— Kinder Morgan's 2 Bcf/d Gulf Coast Express pipeline, the first of three greenfield pipes, came on line in 2019, ferrying gas from the Waha Hub to Agua Dulce just northeast of Corpus Christi, Texas. Additional compression will raise capacity another 570 million cubic feet per day by December 2023.

— Kinder Morgan’s 2.1 Bcf/d Permian Highway pipeline, which moves gas from Waha to Katy, Texas, near Houston, entered service in January 2021. Additional compression will expand capacity 550 MMcf/d by November 2023.

— WhiteWater Midstream’s Whistler Pipeline, which transports 2 Bcf/d from Waha to Agua Dulce, entered service in July 2021. A 500 MMcf/d capacity expansion should come on line in September 2023.

— A WhiteWater-led partnership announced a final investment decision (FID) in May for its proposed Matterhorn Express Pipeline, a 2.5 Bcf/d, 490-mile pipeline that will run from Waha to Katy, Texas. Operations are set to begin in the third quarter of 2024.

As new exit capacity becomes available, the Energy Intelligence Research & Advisory (R&A) unit says there will be more than enough associated gas to fill it. R&A Director Abhi Rajendran sees Permian gas output averaging 24.9 Bcf/d in 2025, 4.3 Bcf/d more than in 2022 in lockstep with the rollout of new Permian takeaway capacity.

LNG Late to Roll Out Party

That 4.3 Bcf/d of anticipated growth in Permian gas will be lumpy, with most of it being front loaded in 2023-24 as new pipeline exit capacity comes on line, according to Rajendran. However, little if any new liquefaction or export capacity will be available to absorb it.

LNG projects won’t see significant new capacity coming on line until late 2025 into 2026 at the earliest, R&A Director Ian Nathan said. And it will still be rolling out in 2027 and into 2028.

Therefore, while the Mexico market might absorb some of the lagnappe, it could be years before most of the 2023-24 associated surge will find a home.

Nonetheless, LNG capacity growth in South Texas is assured after Cheniere Energy’s FID for a seven-train, 10 million tons per year (1.4 Bcf/d) Stage 3 expansion at Corpus Christi LNG.

Cheniere is mulling adding two more trains to the project less than 45 miles southwest of Agua Dulce, but could wait until 2024 to sanction it.

Whatever the final tally, most of Corpus Christi’s additional capacity will start operations in 2027, though some activity should begin in 2026, he said.

The other major slug of demand could come from the Brownsville area on the US-Mexico border in the same 2026-27 time frame.

At least one Brownsville project appears on track — NextDecade's Rio Grande LNG — which if fully utilized could require up to 2 Bcf/d of feed gas as there is a chance that NextDecade could add a third train to a potential FID later this year, Nathan said.

The first two trains that could produce 11 million tons/yr (1.5 Bcf/d) have been substantially contracted by portfolio players Shell and Exxon Mobil as well as mostly Chinese utilities. Rio Grande has signed up a single European off-taker.

Asian Demand in Flux

So, whether there is demand for a third train could depend on what has become a more fluid Asian market. And LNG demand growth in China and Southeast Asia has recently pulled back at current price levels.

However, there is another consideration that could stymie the Rio Grande project from exporting up to 27 million tons/yr (3.7 Bcf/d) and even scale back, or preclude a large Corpus Christi Stage 4 expansion.

"A robust outlook for long-term LNG demand does not mean the window for advancing projects is unlimited," Nathan explained. “Some projects under development and still years away from FID could still be producing LNG around 2050, coinciding with wider efforts to use lower-emission fuels. I start to wonder about the window for these sorts of developments."

Future projects also face increased cost pressures, he said. “Certainly, rising interest rates and higher financing costs are not helpful, but there have been supply chain issues and, I suspect, maybe labor issues that are becoming more pronounced,” Nathan observed.

Bottom line: Sometime in 2027 the probable LNG export capacity buildout in South Texas and Mexico should begin matching rising volumes of associated gas out of the Permian. But until then price pressures are sure to intensify in the Katy and Houston Ship Channel markets.

Gas Supply, Gas Pipelines, LNG Projects
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