U.S. Permian could be building too many gas pipelines

The Permian Basin could see four new major gas pipelines in the next three years, a significant expansion of takeaway capacity aimed at carrying gas to the U.S. Gulf Coast for export.

That could add up to 11.1 billion cubic feet per day of new capacity by 2029— equivalent to moving 9 percent of current U.S. gas production — according ClearView Energy Partners, a Washington-based energy consultancy.

These new pipeline projects include the Tallgrass Energy Partners LP pipeline that would run from the Permian Basin’s Waha hub north and connect into the gas system for the Rocky Mountains. It also includes the Eiger Express pipeline, backed by Oneok and Enbridge, that would run from the Permian to the Gulf Coast and provide another 2.5 bcf/d of capacity. It is pencilled in to start up operations in 2028.

Additionally, the Blackcomb Pipeline would add another 2.5 bcf/d, travelling a bit further south along the Gulf Coast. The Apex pipeline, at 2 bcf/d, would run to Port Arthur, Texas.

Heading in the other direction is the Desert Southwest Pipeline, a 1.5-bcf/d pipeline that would carry Permian gas west to Arizona and New Mexico.

The massive build-out is aimed at connecting the Permian to the wave of new LNG projects that are currently under construction. The U.S. already exports roughly 15 billion cubic feet per day of gas, which is up 2 bcf/d from the same period a year ago, according to ClearView. That figure is expected to nearly double to 24.4 bcf/d by 2028, and continue to climb thereafter.

But it may not all be smooth sailing. There are a series of market risks facing the litany of pipeline projects, the upstream industry, and the U.S. economy.

Some industry analysts are warning that the frenzy of pipeline construction could result in overbuilding. East Daley Analytics said that by 2029 to 2030, pipeline capacity could outstrip throughput by 6 bcf/d, resulting in “challenging the supply-demand balance,” as reported by Natural Gas Intelligence.

For now, the industry is rushing to build new pipelines, with so much gas production trapped in West Texas. In mid-September, natural gas prices at the Waha hub in the Permian basin fell below zero, dipping as low as negative $3.03 per million Btu, a 14-month low. That came after a key pipeline owned by Kinder Morgan underwent maintenance and was taken offline.

But matching future supply and demand is not easy. Texas regulators have a “very hands off approach” to assessing whether or not new pipelines are needed within the state, unlike interstate pipelines that require a more involved regulatory process at the federal level, Ed Hirs, an energy fellow at the University of Houston, told Gas Outlook.

That leaves the viability of new pipelines up to the market, which could result in overbuilding.

“Markets tend to overshoot,” he said. “It’s difficult to be the first pipe. And it could be disastrous to be the last pipe.”

He recalled a moment several years ago when the Gulf Coast had a long list of LNG projects on the drawing board.

“I’d like to be plant three, four, or five. I don’t want to be plant number fourteen or fifteen.”

When pressed on whether or not there were too many pipeline projects moving forward, Hirs demurred, saying he didn’t have a great sense. “I don’t think it’s an issue right now,” he said. “But the midstream business in Texas has whipsawed back and forth a number of times.”

Questions about production and prices

The industry faces a separate problem of increasing gas supply once all of the new pipelines come online. Much of the gas extracted from the Permian basin comes in the form of “associated gas,” or gas that is produced alongside crude oil. Typically, most Permian drillers are targeting the oil, and the gas is something of a byproduct.

As crude oil prices languish in the mid- to low-$60s per barrel, and are expected to drop further in 2026, oil drilling activity will continue to slow down. As of mid-September, there were 254 drilling rigs in the Permian Basin, which is 52 fewer than a year ago. Production has flatlined, and the rig count could continue to decline.

With fewer rigs drilling for oil, less gas will come out of the ground. Or, at least, growing production will become increasingly difficult.

In U.S. shale, unlike conventional production, oil and gas output declines quickly after an initial burst of production. That means that companies have to spend a lot of money and drill hundreds or even thousands of wells just to stay in the same place. As the International Energy Agency noted in a recent report, if shale drilling were to stop immediately, production would decline by more than 35 percent within 12 months. That compares to a global average decline rate for oil fields of just 8 percent annually.

That raises the question of how the industry expects to grow gas production fast enough to fill up all the new pipelines and LNG terminals, at the same time that costs are rising and crude oil prices are down.

“As you would expect, a wide range of market players are counting on continued growth in Permian NGL production, including the owners and operators of gas processing plants, NGL pipelines, fractionators, and ethane and LPG export terminals, many of which continue to make big-dollar investments in new infrastructure,” RBN Energy, an energy consultancy, wrote in an analysis on September 12th that looked specifically at natural gas liquids. “[S]ome of these same companies have been expressing concern that the production growth they’ve been banking on may be undermined by less favorable WTI pricing and a prospective slowdown in Permian drilling-and-completion activity.”

The extended period of weak oil prices will cut into the growth of gas.

“If OPEC continues with this price war, that will continue to put a damper on production in the Permian basin and certainly that will have a negative impact on gas production,” Hirs said.

He did not see U.S. Permian gas reserves as the problem. “We have plenty of natural gas,” he said.

But in addition to weaker crude oil prices, the LNG market is also staring down a period of oversupply and potentially much lower prices.

“Quite honestly, most of the players in that market can undercut the U.S. The marginal cost of a thousand cubic feet of gas in Qatar is about 5 cents,” Hirs said.

“If LNG gets to a price war situation, we are going to find ourselves in a similar boat to what we are in with oil. We are definitely the high-cost producer.”

And if both LNG and crude oil markets experience a slump? “That would hurt,” Hirs said.

(Writing by Nick Cunningham; editing by Sophie Davies)