Methane Woes Vex Permian Producers' Effort to Win Gas Customers

Copyright © 2023 Energy Intelligence Group All rights reserved. Unauthorized access or electronic forwarding, even for internal use, is prohibited.

A growing glut of associated gas in the Permian Basin has producers eyeing growing markets along the US Gulf Coast, particularly LNG exports. But the region’s methane problem may prove an obstacle to competing in those arenas, especially as competing plays take collective action to improve methane intensity at a basin-wide level.

“A gassier Permian is going to set up a clash between US producers and potential buyers looking to minimize their supply chain emissions,” Jim Krane, a fellow for energy studies at Rice University's Baker Institute, told Energy Intelligence. “It’s going to be up to the [Texas] Railroad Commission to decide. Are we going to keep permitting oil-focused operations with no capacity to market the associated gas? Are we going to maintain the view that gas is a waste product?”

If that’s the case, "the Permian producers are going to come under more scrutiny for flaring and venting, which will eventually bleed into their ability to attract investment and for US LNG exports to compete on a carbon basis with cleaner producers,” Krane said.

The US Energy Information Administration (EIA) estimates the Permian today produces about 21.6 billion cubic feet per day, dwarfed only by Appalachia’s 35.3 Bcf/d. A trio of long-haul pipelines totaling 6.1 Bcf/d of capacity running from West Texas oilfields to the Texas Gulf Coast entered service in 2021, enabling the region’s latest gas production surge. In February, Permian gas output will have grown 2.8 Bcf/d year over year, the fastest rate of all seven major US shale plays, the EIA estimates.

Despite that scale, the Permian is predominantly an oil play, and that complicates the picture when it comes to methane intensity, said Amber McCullagh, senior advisor at Validere, a company that provides methane measurement, reporting and verification services to the oil and gas industry.

“Most measurement-based, third-party studies find higher methane intensity for Permian volumes relative to other basins,” she told Energy Intelligence. “But often third parties calculate methane intensity as volume vented as a share of sales gas, effectively attributing all Permian methane emissions to its gas production. We think this metric disadvantages mixed-phase plays like the Permian and doesn't give as full a picture of the emissions intensity of their entire operation relative to other basins."

“To avoid flaring — which itself contributes to higher methane emissions rates via things like unlit flares — Permian operators need to have sufficient gas gathering infrastructure, access to enough gas processing capacity, and sufficient residue gas takeaway," McCullagh said. "This infrastructure takes time to build and generally also long-term commitments, and delays or mistiming in any part of that buildout will cause either higher emissions or deteriorating capital efficiency if operators delay completions until infrastructure is in place. In part, Permian emissions are worse because the infrastructure development challenge is genuinely harder, not because its operators are more careless.”

Krane said he suspects that "self-interest will eventually convince Permian producers to do the right thing, even if the Railroad Commission continues greenlighting their worst instincts. Bigger producers are already on board with this."

Indeed, Pioneer Natural Resources CEO Scott Sheffield has called on regulators to rein in private operators that he accuses of excessively flaring. Yet while operators in the Permian have made individual efforts or joined coalitions aimed at curbing methane emissions, so far there is no industry partnership aimed at monitoring and addressing the issue on a Permian-wide basis.

Dearth of New Pipelines

Despite the addition of significant takeaway capacity through 2021, the Permian’s infrastructure problem has again been brought to the fore. West Texas natural gas prices have fallen to a significant deficit to Henry Hub, with producers once again intermittently paying customers to take their gas production.

Pioneer CEO Scott Sheffield predicted earlier this month that this pattern will continue to play out for the next decade as the region’s largest oil producers will see their gas-to-oil ratios climb.

David Braziel, CEO of energy consulting firm RBN Energy, agreed, predicting that Permian gas production will reach 30 Bcf/d by 2030. “We’re talking about wellhead gas, not [pipeline quality] residue gas, which would be closer to 22.5 Bcf/d in 2030,” he told Energy Intelligence. “We’ll need another 2 Bcf/d of capacity every couple of years given projected growth.”

About 3.55 Bcf/d of incremental capacity is slated to come online through the third quarter of 2024. Of that, 2.5 Bcf/d is from the WhiteWater Midstream-led, 490-mile Matterhorn Express Pipeline that will ferry gas from Waha to Katy, Texas.

Kinder Morgan (KMI), the region’s largest midstream developer, owns interests in more than 7 Bcf/d of the basin’s takeaway capacity. But after building the 2 Bcf/d Gulf Coast Express and 2.1 Bcf/d Permian Highway pipelines, KMI says it is less interested in such large-scale projects.

“We’re able to make relatively modest capital efficient investments in our grid to serve the supply and demand growth that we’re seeing across the network,” KMI CEO Steve Kean told investors Wednesday. “It’s a collection of a lot of smaller projects and mostly buildups of the existing network. … It reduces the execution risk on them, and we get as best a return as we can that’s available for the market.”

KMI is adding 550 million cubic feet per day of capacity Permian Highway with a target in service date of Nov. 1. But the pipeline developer has put on hold an effort to add additional compression to Gulf Coast Express, a project that would raise capacity by 570 MMcf/d and had been slated to begin operating by December 2023.

“That hasn’t been very active, although with lower gas prices now there may be some opportunities there,” KMI President of Natural Gas Pipelines Tom Martin said. “As you recall, fuel cost was a bit of a headwind for us on that expansion project. As gas prices are lower, that may bring that one more into an actionable opportunity.”

Executives say the company is making progress on commercial discussions regarding another greenfield long-haul pipeline, the 2 Bcf/d Permian Pass pipeline, but there are timelines to consider on the demand side as well.

“What we are hearing from our customers is that the next need for incremental capacity out of the basin is sometime in late 2026, maybe early 2027. And so as we work with our producer customers and also align them with their desired customer, which I think largely are going to be LNG related along the Gulf Coast, we need to figure out exactly where and when those volumes need to be there,” Martin said. “So I think that’s still out there. The overall market still needs that capacity.”

Methane Emissions, Gas Supply, Policy and Regulation
Wanda Ad #2 (article footer)
Freeport LNG on Thursday cleared another hurdle in its plans to restart operations at the Texas Gulf Coast export terminal. But the resumption of exports may still be a ways off.
Fri, Jan 27, 2023
Market participants can express interest in additional regasification capacity at Spec LNG until Feb. 20.
Wed, Feb 1, 2023
The BP subsidiary is relying on grid power and centralized processing facilities to reduce emissions in the basin.
Thu, Jan 26, 2023