As the United States works toward casting a wider net on the global natural gas market via exports, key domestic markets could be turned upside down in 2023 as midstream bottlenecks leave gas stranded in producing basins.
LNG developers on the Gulf Coast are in a race to boost liquefied natural gas exports to capitalize on rising demand in Europe and Asia. Some projects are under construction and could begin operations in 2024. A handful of others could be sanctioned this year.
East Daley Analytics Inc. projects U.S. liquefaction capacity could swell to nearly 30 Bcf/d by 2030. That’s up from around 13 Bcf/d in 2022. Gas companies up and down the value chain also see continued momentum for LNG.
Producers have taken notice of the export growth potential. As head of one of the largest North American independents, Ovintiv Inc. CEO Brendan McCracken told investors on the 3Q2022 earnings call that “what we see unfolding is a call on North American gas supply and global LNG demand, whether it’s in Europe or Asia or other parts of the developing world…That’s durable pricing that we see unfolding over decades…”
U.S. regulators share a similarly optimistic view. The Energy Information Administration sees export demand growth driving an increase in natural gas production this year. The agency expects output to average 100.4 Bcf/d in 2023.
At the heart of the increased supply is rising output in the prolific Permian Basin of West Texas and southeastern New Mexico, and the Haynesville Shale in East Texas and southwestern Louisiana.
The problem is, pipelines in the Permian and Haynesville are nearly tapped out and could fill completely this summer. That means any additional production hitting the market this year is likely to struggle to make its way downstream. It’s a sore spot for the midstream sector, one that isn’t likely to be remedied anytime soon.
For the Permian in particular, East Daley’s Rob Wilson, vice president of analytics, said he expects supply growth to fill basin takeaway sometime in the first quarter of 2023.
West Texas Woes
The lack of takeaway out of the Permian has been an issue before.
In 2019, swelling gas output filled pipelines, and the market awaited Kinder Morgan Inc.’s Gulf Coast Express (GCX). The 2.0 Bcf/d conduit was a boon for producers, which sometimes were forced to pay customers to take their gas before GCX began service in the fall of 2019. Gas prices at the Waha Hub in West Texas at one point fell to negative $9.00/MMBtu.
Pipeline space grew hard to come by the following year, with prices tumbling to negative $10 as producers paid to get gas off their hands. Kinder then brought online the 2.1 Bcf/d Permian Highway Pipeline (PHP).
WhiteWater Midstream LLC and its partners brought online the Whistler Pipeline in the summer of 2021. However, Whistler began operations in a far different landscape than its predecessors. After Covid-19 upended the energy industry and decimated demand, Whistler started flowing gas when there was pipeline capacity to spare in the Permian. That didn’t last long, though.
Permian production was reported to be close to a record 16.5 Bcf/d in December. Though estimates vary, more growth is expected.
East Daley’s analyst team sees a Permian exit-to-exit growth rate of 1.8-1.9 Bcf/d this year. Wood Mackenzie expects production out of the basin climbing only around 0.5 Bcf/d in 2023. Aegis Hedging Solutions LLC, meanwhile, expects growth somewhere in the middle of that range.
What’s preventing analysts from providing clearer guidance? Tightening egress and uncertainty over when more pipeline capacity may hit the market.
Projects In The Works
There are some projects underway in West Texas to add takeaway. Kinder is planning to add compression along PHP. The midstreamer sanctioned the 550 MMcf/d expansion project last June and is targeting start-up in November.
An open season was launched last May to gauge interest in boosting capacity on GCX as well, but few details have been provided. Notably, PHP’s planned expansion is not quite as big as the 650 MMcf/d previously outlined in Kinder’s open season.
WhiteWater, meanwhile, is forging ahead with plans to expand Whistler’s mainline capacity to about 2.5 Bcf/d with the addition of three compressor stations. Those are expected to be in service by September.
“We need everything online as planned,” East Daley’s Ajay Bakshani, senior capital markets analyst, told NGI. Even then, those pipelines are likely to fill quickly, he said. No significant alleviation in constraints is expected until 2024, when WhiteWater’s Matterhorn Express greenfield project is due online, according to the analyst.
“It’s not a great outlook for Permian gas overall,” Bakshani said. “We’re cutting rigs back a decent amount, but we’re still seeing growth. Matterhorn provides some breathing room, but we expect constraints to materialize again in late 2025 or early 2026.”
Energy Transfer LP has discussed building the Warrior Pipeline, which could move 1.5-2.0 Bcf/d from the Permian toward Dallas, where it would access existing pipes to the Gulf Coast. Management was evaluating the project last summer, but expressed optimism that it could bring the project to a positive final investment decision.
“I wouldn’t be surprised to see additional development,” Bakshani said. “Those conversations will be happening now.”
Situation Worse Before It’s Better?
Until then, things could get ugly in the Permian.
Wood Mackenzie’s Ben Chu, head of Trading Analytics and Proprietary Data, explained that it’s not that the market is awaiting new pipeline capacity out of the Permian. What’s making matters worse is that gas flows on existing pipelines are being restricted because of maintenance or otherwise.
Chu said Kinder has reduced capacity on GCX to 1.855 Bcf/d since Dec. 28 because of repairs at the Devil’s River Compressor Station. Meanwhile, PHP’s throughput has been restricted to 1.8 Bcf/d since Dec. 17.
“Interestingly, both outages were related to compressors in recently installed Kinder Morgan pipelines,” Chu said.
It’s its last update in late December on GCX, Kinder said, “Due to unforeseen circumstances, it is necessary to keep the reduction in place until further notice.”
Similarly, Kinder said the PHP restrictions would likely continue for several weeks after it was determined that one of the units at the Coyanosa Compressor Station would have to be evaluated and repaired following an inspection.
There’s also Kinder’s El Paso Natural Gas, which shut its Line 2000 in August 2021 following a deadly blast in Arizona. That outage took 450-500 MMcf/d of pipeline capacity out of the market.
“The important thing to note though is that the Line 2000 explosion was due to stress-related corrosion cracks eating away at the steel. There’s nothing special about the spot that exploded, and El Paso is an old line,” Chu said. “Timing is still an unknown, and further findings on an old pipe is just a steadily growing risk over time.”
Given Wood Mackenzie’s modest Permian production growth estimate, Chu said one could argue the basin would have enough takeaway if Line 2000, GCX and PHP were to return to service. The planned expansions on Whistler and PHP, meanwhile, should help accommodate any Permian growth.
That said, when West Coast demand slows down in the shoulder seasons, all bets are off, according to Chu. The demand sink can only take so much, and California’s flexibility in storage is down this year too.
“So there’s definitely risk for 2023, and perhaps a higher degree of it going into the fall shoulder season due to both West Coast seasonal demand and any construction timing risk while production steadily grows. Any unexpected outages at that point in time could be highly impactful,” he said.
If it weren’t for natural gas flaring, Chu said, Permian gas would need to price anywhere from negative $6.00 to negative $40 in order for oil and natural gas liquids producers to fully offset their uplift and still cover operating costs. Waha has already hit negative $10 again this year.
Rough In Haynesville Too
The Haynesville also is growing considerably, according to Bakshani. He noted the myriad of offtake agreements signed between U.S. LNG developers and global customers, especially in the wake of Russia’s invasion of Ukraine.
“Clearly, the market is very excited,” he said. “The overall attitude toward natural gas is improving with the world realizing how much we need.” However, most of the growth in LNG demand is not expected until 2025 and beyond. Until then, the market has to be careful in managing that risk, according to Bakshani. “We view the market being oversupplied in 2023.”
Chu agreed.
While Energy Transfer last month started service on the 1.65 Bcf/d Gulf Run Pipeline in Louisiana, gas near the Texas Gulf Coast/South Louisiana border is struggling to find an outlet because Freeport LNG is still offline following a June explosion, according to Chu. This has left 2 Bcf/d of additional gas to be cleared from Texas markets.
“Pipes from Texas to Louisiana are effectively full, whether at the border or a little further downstream, so there’s near-term risk of clearing more Haynesville gas through Gulf Run until Freeport comes back online,” Chu said.
Further into the year however, Texas production should continue to grow, according to Chu. At the same time, pipes from the Permian to South Texas would put more gas into the area.
“Eagle Ford is also still growing, so further along in the year, there is risk of more gas-on-gas competition as any Haynesville gas pointed to Gillis Hub or near the Texas/Louisiana border will need to compete with Texas molecules.”
There are wildcards in the mix. Summer weather should be a key indicator of how much gas is replenished in storage. So far this winter, withdrawals have been light and an end-of-summer storage inventory level well above 4 Tcf is not out of the question, according to Chu.
“There’s a good chance Texas storage will have a little less flexibility in the fall shoulder season than normal,” he said.
There are more projects underway to help alleviate the pipeline capacity issues in Louisiana. Enterprise Products Partners LP is targeting the second quarter to bring online its 400 MMcf/d Acadian Expansion II. DT Midstream Inc. expects its 300 MMcf/d Louisiana Energy Access Project (LEAP) Expansion Phase 1 to begin service in late 2023.
Still, Chu, Bakshani and Wells Fargo analysts see Haynesville takeaway remaining tight absent more capacity additions. There are several in the works, but those aren’t slated for in-service for another two years or more.
MVP Fight Continues
The solution to the Northeast’s lack of takeaway, meanwhile, has fallen to producers.
Years after major pipeline projects like PennEast Pipeline, Constitution Pipeline and Atlantic Coast were scrapped, Appalachia-focused producers have had to operate mostly in maintenance mode. By and large, flat production profiles have been adopted by most major producers in the basin.
EQT Corp., for example, curbed production in the third quarter of 2022 as it faced supply chain issues, midstream constraints and adverse weather. The nation’s largest gas producer doesn’t expect to be back on track until the middle of the year. Appalachian stalwarts Range Resources Corp. and Antero Resources Corp. also reported midstream issues last year.
With a hostile regulatory environment contributing at least in part to the scrapping of several large pipeline projects in recent years, Mountain Valley Pipeline (MVP) stands alone in potentially bringing an incremental 2 Bcf/d of takeaway capacity to Appalachia. Total work on the project is nearly 94% complete, but the pipeline has faced staunch opposition that has resulted in multiple delays – and uncertainty for the market.
MVP, a joint venture of EQM Midstream Partners LP, NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream, and RGC Midstream LLC, has said it remains “committed to working diligently with federal and state regulators to secure the necessary permits to safely and responsibly finish construction, and we remain committed to bringing” the project “into service in the second half of 2023.”
