Midstream companies will spend $50 billion this year and next to keep up with surging volumes of natural gas from prime shale basins. Nevertheless, another round of investment is likely to be needed before the end of the decade as the next generation of LNG export terminals are built in the U.S., Canada and Mexico

“It’s all about timing,” Ryan Smith, vice president of advisory services at East Daley, told Oil and Gas Investor. “Infrastructure is not currently a constraint, but six to eight months ago you could not get gas from Texas to Louisiana. There was a $2 discount at the Houston Ship Channel. That has now gone away.”

Several major long-haul gas pipeline projects are expected to alleviate tightness in midstream capacity in North America when they come into service in 2022-2023. Gas storage, however,is emerging as a potential area of interest as the sheer volume of gas produced, consumed and exported grows dramatically.

The next round of LNG investments is expected to be operational in or around 2029, taking total gas demand for LNG to about 33 Bcf/d. So far, infrastructure investment has been able to keep pace.

From 2016 to 2021, U.S. LNG export nameplate capacity went from essentially zero 10 Bcf/d. In another six years, that total will rise to  20 Bcf/d.

How much new infrastructure will be needed by 2029, and how much it will cost, are not yet clear. Given the long lead times for permitting and equipment fabrication for liquefaction trains, midstream companies and the investors that back them are awaiting final investment decisions on the projects under development before deciding to put new steel into the ditch. When that time comes, there is widespread confidence that both public and private equity will be eager to underwrite the necessary investments.

ConocoPhillips has already put skin in the infrastructure game to support its natural gas production growth. Late last year, the company purchased a 30% stake in Sempra’s Port Arthur, Texas, LNG development and signed a 20-year offtake agreement.

“Port Arthur LNG will benefit from intrastate pipelines out of the Permian Basin,” said Bill Bullock, executive vice president and CFO at ConocoPhillips, during its April analyst presentation.

Independent producers seem to have a similar sentiment. UpCurve Energy, a portfolio producer of Post Oak Capital, operates in the Delaware Basin. “We have had one rig running for several years,” said Zach Fenton, co-founder and president. “It is a nice measured development. At the beginning of 2022 we were at about 20 MMcf/d, and now we are close to 50 MMcf/d.”

UpCurve works with the larger midstream operators and has secured firm capacity, Fenton said. “Things are tight, especially for producers that do not have firm service. If you have interruptible service, you are going to get interrupted. It has happened and will continue to happen.”

He also noted that differentials indicate the market expects tightness to continue in the near term. “There is a lot of progress on new capacity,”Fenton said. “All the big midstream groups are working. The investment is taking place, but the new capacity will come on in blocky chunks, so the tightness will continue intermittently. That will especially be the case in the Permian because operator economics is driven by crude and there is a lot of associated gas.”

In both the Delaware and Haynesville, “gas has been crushed,” said Frost W. Cochran, managing director at Post Oak Capital. “There has been significant cash price degradation in the Delaware Basin but oil production is still driving activity.” Post Oak is primarily upstream, but also has some midstream operations, which gives Cochran and his colleagues good insight into both sectors.

The tightest infrastructure capacity for the major U.S. horizontal plays is in the Haynesville, according to Cochran. “We have primarily seen tightness manifest itself in slightly higher line pressures. That means that wells are fighting to get on and its impacting production. I keep expecting more tightness in the Permian, but we have not experienced it yet in the primary revenue generating commodity—oil.”

He also noted that midstream operators seem to be adding gathering and processing just as new wells are being brought into production. “That is mostly because of their own supply-chain issues with equipment and construction, but it means that the timing is tight.”

The oil side is “no big deal,” in terms of transportation, Cochran said. “We have our strong connections to the Oryx system in the Delaware, so there are minimal oil takeaway issues there, or in the Midcontinent.” Post Oak was a founding investor in Oryx before selling it to Stonepeak.

Enough LNG tankers?

The numbers support the assertions that midstream investment is taking place. East Daley forecasts capex and EBITDA for 22 of the largest midstream companies. East Daley expects the group to spend $25.6 billion in capex in 2023, decreasing to $20.6 billion in 2024. Enbridge and TransCanada are the top companies with capex spending in 2023, which include large-scale pipeline expansions in Canada.    

Midstream companies have been busy building “a runway of new pipe through 2025,” Smith said. “But by 2028, there will be 18 Bcf/d of new LNG export demand4.2 Bcf/d in Texas and 13.8 Bcf/d in Louisianaand only about half that capacity of new pipe.” He noted that some LNG operators, but certainly not all, make it a point to contract capacity all the way back to the supply basin.

“The due diligence for an LNG project is based on global demand and funding for the project,” Smith explained. “The long lead times are for permitting and larger components. The need for new pipe is more of an opportunity than a problem. There is plenty of time.”

He also noted two other infrastructure elements that bear watching. The order book for new LNG tankers is full, so there could be some short-term disruptions in actual loading and sailing if there are not sufficient vessels at any time.

That variable, along with spikes and dips in demand driven by heat waves or severe storms, mean that storage will matter more than ever. “Storage capacity becomes very important in volatile markets,” Smith said. “Midstream is clued in to this already, and some large operators have been investing in buying storage capacity.” As far back as 2021, Kinder Morgan purchased Stagecoach Gas Services for $1.23 billion.

“The big area of focus has been gas takeaway from the Permian,” said Hinds Howard, portfolio manager at CBRE Investment Management. Noting that there have been both expansions and greenfield development, he added, “capacity is not the current constraint there,” but there are some pinches starting to show in other basins.

“The Haynesville has a lot of projects under development,” Howard explained. “Overall, it’s about 85% full, but going south is a constraint, which is actually where the gas wants to go. The major players, the ones with the big footprints already, are the ones adding capacity.”

Bakken gas takeaway is also constrained. “Producers are recovering more ethane to free capacity,” Howard said. “As we approach BTU limits we may need more of that.” Next steps would include reconfiguring existing infrastructure. For example, TC Energy is considering options for the Bison Pipeline that connects the Powder River Basin in Wyoming to the Northern Border system in North Dakota.

The Appalachian has long been the most constrained basin, and that is expected to remain the case. “Existing infrastructure is at about 90% of capacity. Most expectations are for that to hold steady on, with normal incremental increases, Howard said.

Equitrans is sticking to its projection of having the $6.6-billion Mountain Valley Pipeline development completed by the end of the year, and though greenlit in early June by Congress, the embattled project, the embattled project still has remaining permitting and litigation hurdles..

Gas Takeaway by market
By mid-2026, natural gas production is forecast to surpass takeway capacity. (Source: Enverus Intelligence Research, Bloomberg, companies)

Macroeconomic shift

In all the examination of specific basins and individual projects, it is important to bear in mind the broader context, noted Kate Hardin, executive director of Deloitte’s Research Center for Energy and Industrials. “We are seeing gas production at more than 100 Bcf/d. That is significant production in response to real demand, especially in power generation and LNG.”

That is a major success story, but a very recent one. “If you look at infrastructure in the Permian, we are at about 90% utilization for gas but only about 70% for oil,” said Hardin. “Looking ahead to 2026, gas takeaway is expected to be at 80% to 100% of capacity, with oil at plus or minus 60%. So, it is clear to see where the infrastructure investment has been to this point.”

Permian production is still strong, Hardin acknowledged, “but as decline rates set in, the gas-to-oil ratio will shift. At the same time, the market for gas is changing. And producers are starting to understand that. There is more attention to gas than ever before. In 2022, about 82% of upstream deals included gas assets.”

The macroeconomic shift is the U.S. becoming a major gas exporter worldwide, not just to Europe, explained Amy Chronis, vice chair, U.S. oil, gas and chemicals leader at Deloitte. “A lot of the U.S. LNG contracts have no destination clauses,” she added, noting how that flexibility came to the fore through the pandemic and the embargos on Russian gas as cargoes were traded globally. “The highlight here is gas transport,” Chronis stated emphatically.

Transportation capacity is more complex than just solving for the production volumes out of a basin, said Baran Tekkora, a partner at Riverstone Holdings. “The demand locations for natural gas are also changing. As the energy transition continues to gain attention, demand in historically high areas of consumption is leveling off and may decline. At the same time, demand in U.S. export areas is on the rise, as LNG is a growing global energy source. That change in demand location is driving the continued transportation infrastructure needs just as much as the overall demand growth for natural gas.”

Tekkora made a point to dispel a common misperception across the industry about how much infrastructure has been completed. “Midstream went through a very disciplined capital deployment period during the pandemic, but infrastructure did not catch up as much as might be expected. Long-haul infrastructure projects in execution phases continued, but some key operators put the development of additional projects on hold due to lack of demand for capacity from both the supply and market side.”

That, in turn, “created a pinch coming out of the pandemic, which caused the pricing spread between high-production basins and the market to widen significantly,” he continued. “While that began to come back into balance, now that production numbers are back on the rise, the phenomenon will continue.”

‘Catch-up mode’

Broadly speaking, “the industry has been able to maintain capital discipline through volatile prices in the last few years, primarily due to investors rewarding such capital discipline, but also other factors including supply-chain issues and dearth of available skilled labor,” said Amol Joshi, vice president and senior credit officer at Moody’s Investors Service. “All that has kept a lid on production growth as well as [has] available oilfield-services capacity.”

So, there is little surprise that long-haul gas transportation in the Permian “is in catch-up mode,” Joshi added, “caused by associated gas growth and rising gas/oil ratio in mature areas, and there have been routine price dislocations and basis blowouts such as at the Waha Hub. New gas takeaway capacity is being added to mitigate this, with projects such as the Permian Highway expansion and the greenfield Matterhorn pipeline project.” Crude oil takeaway does not face this issue yet in the Permian, he added.

“We see the need for a massive amount of transmission pipeline infrastructure to be built out in the Haynesville and Permian to support the next wave of LNG projects coming online in the second half of the decade,” said Jon Snyder, vice president of intelligence at Enverus. “For the Haynesville, we see almost 5 Bcf/d of new north-to-south Louisiana takeaway coming online by the end of the 2025. For the Permian [we see] nearly 4 Bcf/d by the end of 2024. Even after this Permian buildout, we see the basin needing a new 2 Bcf/d pipe every 18 to 24 months to support continued oil production growth.” 

The slowdown in Permian development in 2020 did help provide some relief to the basin, “but as production has recovered, the basin has started to bump up against available takeaway,” Snyder said, “and needs expansion projects to come on line at the end of the year to help support continued growth. The decrease in activity in the Haynesville also provided temporary relief, but new north-to-south Louisiana projects are needed to supply more gas to third-wave LNG projects. Those projects are under construction.”

The fundamental challenge in the midstream is that the economics always favor bigger pipes and compressors, said Ben Dell, co-founder and managing partner at Kimmeridge Energy Management. “The midstream is dependent on the upstream to deliver volumes, but the upstream is dependent on price. If a producer could commit to $5 gas for 10 years, any midstream operator would be happy to invest in as much capacity as they could ship.”

As big as pipes can get, LNG trains are even more chunky in terms of capacity. Each standard liquefaction terminal of 4.2 million metric tons/day needs about 600 MMcf/d.

“That is a lot of demand coming on in a relatively short time,” said Dell. “There is about 25 million tons a year on LNG coming on in the next few years just in Texas. Across the industry, it could be as much as 50 million tons. So, gas is going to be firming in 2025, [20]26, [20]27. Every producer wants to develop its assets into that. We are just in a bit of an air pocket this year and perhaps into next year.”

Infrastructure for crude has plenty of capacity relative to production with the possible exception of long-haul pipeline to Corpus Christi, Texas, said Stephen Ellis, energy strategist at Morningstar. In contrast, gas gathering, processing and transportation face an inflection from ample capacity now, to tight in the medium term, to balanced in the longer view.

“The oil side is a bit easier,” said Ellis. “It’s oversupplied with transportation. Some pipes are going from very under capacity to only a bit under capacity. Maybe we need more transportation into Corpus, or maybe carriers can shift volumes to Houston where there is more capacity. There are discussions about moving things around.”

On the gas side, “there is an undersupply,” of transport “at least in the next few years: 2024 and [20]25, maybe into [20]26, Ellis said.For the rest of this year there is actually an oversupply in transportation. That is because the European Union did not end up needing as much LNG as was thought it would need going into this winter. Gas production in North America has gone up, consumption has gone down, and so gas in storage has increased.”

Looking south, Ellis noted significant improvements in gas exports to Mexico. “There has been good progress in Mexico. TC Energy came to some agreements with Mexican utilities on financial terms. The permitting and the infrastructure on this side of the border are mostly in place. What is needed now is for the Mexican midstream to connect. ONEOK is also planning Mexican pipelines. There is definitely a lot of progress, which is good after years of low volumes of as low as 10% or 20% of capacity.”

Balance is always temporary, reiterated Riverstone’s Tekkora. “I believe the next imbalance or bottleneck is likely to occur in natural gas liquids fractionation and infrastructure. The sector was arguably overbuilt in 2019 and 2020, but the industry has done a good job of filling that same capacity. I believe there’s likely to be some tightness in 2024 and 2025 ahead of new infrastructure and fractionation capacity coming available.”

Processors will have some flexibility in NGL production if the tightness comes sooner by switching to ethane rejection mode, Tekkora suggested. “However, that same molecule taken out of the NGL supply chain finds its way into the natural-gas transportation infrastructure and further complicates the congestion there.”