November 2018


Permian Basin — Where Midstream Infrastructure Needs Take on Outsized Importance

By Richard Nemec, Contributing Editor

The ever-stronger attractiveness of the Permian Basin as the global hot spot for new oil and natural gas development could not have been any clearer than in August 2018, when an independent pure-play exploration and production (E&P) company based in Midland, Texas, swallowed up a Birmingham, Ala.-based firm with a West Texas focus in an all-stock deal valued at $9.2 billion. Easy come, easy go in West Texas. 

Diamondback Energy Inc. paid its multibillion-dollar price in an all-stock deal for Energen Corp., just two months after strengthening its Permian position with a $1.2 billion purchase of Midland sub-basin acreage from Ajax Resources LLC.

Enterprise Products Partners placed 70 miles of high-pressure residue gas pipeline into service this year to connect the expanding Orla natural gas processing complex. (photo: EPP)

In the San Andres formation, new bursts of infrastructure from 2017 could be seen sprouting up literally all over this corner of the Permian Basin that encompasses some of west Texas and the southeast corner of New Mexico. Firms like Stakeholder Midstream LLC and Santa Fe Midstream LLC have stayed busy since early in 2017 expanding gas gathering systems and crude oil gathering arteries. Stakeholder CEO Rob Liddell was on the record almost two years ago making the commitment to meet the challenges of providing more takeaway capacity in his corner of the mighty Permian.

Enterprise Products Partners placed 70 miles of high-pressure residue gas pipeline to connect the expanding Orla natural gas processing complex. (photo: EPP)

The beat goes on. And the repetitiveness of the transactions continues to put real pressure on the midstream infrastructure for an area historically interwoven with gathering and processing capability. Mix in advanced gas treaters, injection wells, a nitrogen rejection unit, and a best-of-its-kind cryogenic processing plant. Stakeholder officials at the end of 2018 expected to have low-pressure, sour gas gathering lines stretching across Yoakum County, Texas, into Lea County, N.M., along with expanding its existing San Andres crude gathering system.

U.S. oil and gas industry veterans recognize the Permian as the grandfather, perhaps, of major basins in North America with a deep, rich history that has been reinvigorated by the shale and hydraulic fracturing (fracking) revolution unleashed in the past decade. A close observer of the basin with both Wall Street and oil patch ties described the Permian this way:

“It’s been drilled for many, many years, but has become a major player in the world oil industry thanks mostly to a combination of (a) technology in horizontal drilling and fracking, (b) stacked plays with literally layers and layers of oil- and gas-bearing formations stacked on top of each other so these are like having 10 or more oilfields all in one, and (c) access to capital and favorable oil/gas rules/regulations in these states.”

In 2018, speculation and debate was growing about whether the Permian was heading toward a slowdown based solely on the inability of takeaway capacity to keep pace for both oil and gas, although everyone agreed it is oil that the majority of the exploration and production (E&P) companies are seeking there.

Even with the focus on oil, production growth in the Permian will not continue at its precedent-setting levels without growth in gas production. (In the second quarter of 2018, one analyst was predicting that the Permian will account for up to 60% of the world’s oil production growth over the next three to five years.

Projections from the likes of Kinder Morgan (KM) and Cheniere Energy Inc., the LNG supplier, are bullish about gas production longer term in the Permian. Some of their projections predict that the Permian will surpass the Marcellus/Utica (Appalachia) as the fastest growing U.S. gas production area. That will have major pricing and infrastructure implications, they have said. 

Rusty Braziel, founder and head of RBN Energy LLC, stresses that all of the liquids and gas growth is driven by the export markets. This is spurring five major greenfield crude oil pipeline projects, plus a bunch of expansion projects that Braziel’s analysis said will add about 4.7 MMbpd of takeaway capacity in the Permian. For gas, in late summer, Braziel counted seven new pipelines in the works offering 2 Bcf/d capacities each for Corpus Christi, Houston or Louisiana. He also counted 27 new gas processing plants under development, and five other pipelines (1.6 MMbpd) for natural gas liquids (NGL). 

The topic of “flow assurance” was popping up during the second quarter of 2018 earnings conference calls, prompted by concerns over oil and gas production growing too fast for takeaway capacity to keep pace. Some of the smart money has followed the producers and operators who locked up adequate takeaway capacity or are selling to companies who own their own takeaway capacity. 

Drilling rig fleet operator Nabors Industries in mid-2018 surveyed 20 Permian operators and found only two concerned about takeaway capacity. Others like Centennial Resource Development CEO Mark Papa was saying publicly that he expected a scaling back of private equity plays in the Permian the last half of 2018.

One New York City-based analyst put it this way at the end of summer: “Expect some choppiness out of the Permian Basin for the next year or so, but it should resume more of a growth trajectory starting in late 2019 and will continue to have a major impact on both the U.S. crude oil and natural gas industries.”

In the meantime, the midstream infrastructure will need to keep on pushing forward.

Stephen Robertson, executive vice president at the Permian Basin Petroleum Association (PBPA), acknowledges that the Permian is dealing with the age-old struggle in the oil and gas industry to keep production and takeaway capacity in as close to balance as possible. The good news, he thinks, is that in 2018 there were a variety of plans in place to bring the situation more into balance.

“The midstream folks I talk to sing a song they say is as old as the oil and gas industry itself,” Robertson said. “It is namely that production goes up and takeaway capacity gets built and eventually surpasses production, and then all of a sudden the production surges and catches up again. It is all part of the market economy that we operate in and trying to find that balance is the reality of it.”

In mid-August total rigs in the Permian totaled 446, 301 of those by large- and mid-cap publicly traded companies, including all of the world’s super majors. With the remaining 145 rigs coming from privately held entities, the Permian rigs represented half of the rigs deployed in the United Sates, and one-fifth of the rigs operating globally.

In the gas sector alone, one analyst charting production growth for the first quarter of 2016 through first quarter of 2023 as going from 7 Bcf/d to 17 Bcf/d listed 13 existing or proposed pipeline projects to accommodate this projected future growth. All the major midstream players are involved in one or more the projects – Williams, Kinder Morgan, ETP, Oneok and Sempra Energy.

ExxonMobil Corp., a highly integrated global super major that sold off its marine shipping and pipeline companies in recent years, announced in May that it is partnering with a couple of midstream operators, Plains All American Pipeline (oil) and Kinder Morgan (gas).

PBPA’s Robertson said some of his E&P members are stepping in to address midstream needs, but usually on a non-ownership basis contracting for pipe capacity rather than taking an equity interest in the gathering lines. Major midstream operators, such as Plains All American, Enterprise Products Partners and Energy Transfer Partners are the ones really pushing a lot of the infrastructure projects, he said. Some of the producers are just guaranteeing enough production to allow projects to move forward.

“There is no lack of interest in all the building plans I have seen, the needed response has been there,” Robertson said. “Prices have gotten to $10 and $20 differentials, and the operators are still willing to drill and develop because we have been able to keep prices down. The pipeline companies also have stepped up to the need.”

Since the spring, Ares Management LP and ARM Energy Holdings LLC have been working in partnership to develop multiple cryogenic processing facilities, gas and oil gathering lines, and compression/treating facilities in the Permian Delaware sub-basin. Named Salt Creek Midstream LLC, it is being operated by ARM Midstream. This project is an example of the sheer size of the landscape in the Permian as the combined projects cover more than 250,000 acres across five West Texas and two New Mexico counties.

For the observers new to the Permian, one of the common misunderstandings is about its size, said PBPA’s Robertson. “It is about the same size in square miles as the state of Alabama, so just like a state that size the problems on one end of the state won’t be the same on the other side,” he said. “Thus, the problems you have in the Midland sub-basin aren’t going to be the same as you have in the Delaware sub-basin. It is such a large area and it covers land in two different states, Texas and New Mexico, with different kinds of cultures and regulations. New Mexico has a lot of federal lands; Texas does not.”

Coming off a successfully developed and sold midstream Permian project, ARM Energy is reinvesting in the basin, eyeing a new set of 260 MMcf processing capacity for the start of 2019. Officials at the midstream partners tout their industry and long-term Permian experience as an invaluable attribute in the current competitive climate surrounding the region and its proximity to market hubs. The partnership was also riding a $350 million term loan facility from Deutsche Bank, acquired earlier in 2018.

An analysis from financial services giant Baird identified upward of 3.9 MMbpd of incremental takeaway capacity coming to the Permian by the end of 2020, in addition to 3.4 MMbpd of capacity in place in 2018. This included added capacity projects from ETP’s Permian Express II, Phase 2 (200,000 bpd), and Permian-to-Nederland project (600,000 bpd, expandable to 1 MMbpd), the consortium-led EPIC pipeline (590,000 bpd), Plains All American’s Permian-to-Cushing, Okla., expansions, Cactus II (670,000 bpd), and Phillips 66 Partners’ Gray Oak (385,000-700,000 bpd).

In underscoring the prediction of up to 7 MMbpd of takeaway capacity by the end of 2020, Baird noted that in mid-2018 45% of the active rigs in the United States were in the Permian, and since 2016, it has been the national leader in well productivity, having surpassed both the Bakken and Eagle Ford shale plays in North Dakota and Texas, respectively. It also sees this added takeaway going to both Cushing and the Gulf Coast and including more than pipelines through both rail and regional refinery demand.

The gathering infrastructure in the basin itself had not lagged at the midpoint of 2018 as had the takeaway capacity to markets, PBPA’s Robertson said. “It is easier to put in the flowlines in the gathering process when you’re already leasing from those people and you can negotiate service contracts with them vs. when you’re making a service buy to go for hundreds of miles in the Permian.” 

“Pipelines are probably No. 1,” Robertson said. “For our members who are largely producers, once product is produced they are trying to get it to a purchaser. Whatever happens with the processing side of things or with transport outside of pipe – the rails are very busy moving sand and other supplies for the industry – there is not much extra capacity to put product on the rails.”

The bottom line for all the growing list of players in the Permian is that there are both opportunities and risks inherent in the current state of the market in this venerable basin. Rusty Braziel called both “unprecedented” and went on in an August analysis to note that there are more than just crude oil and gas bottlenecks to contend with there. “There are other constraints that hold back the pace of drilling and completions, including gathering, gas processing capacity, NGL takeaways, NGL fractionation and a worsening takeaway problem with produced water disposal,” he said.

An experienced Texas midstream player, Enterprise Products Partners LP (EPP), has abundant assets from the Permian to the Gulf Coast, and still its Executive Vice President Bill Ordemann earlier this summer was telling an industry conference that his company has 1,000 miles of new pipeline, two processing plants, a petrochemical facility and an ethylene export facility all under construction in 2018. With pipelines, storage, processing and export facilities, EPP is connected to domestic and international energy demand with ties to all the major U.S. shale basins, every domestic ethylene cracker, and 90% of the refineries east of the Rockies.

In regard to the Permian, Ordemann said that in addition to announced plants, “we believe the Permian will need another 7 Bcf/d of new processing capacity to support growing rich-gas production between now and 2022.” He called the current gas processing capacity “a lot, but not nearly enough.” Ordemann supports Braziel’s contention that exports are where most of the added U.S. production is heading.

“There is a growing emerging market demand for U.S. energy and petrochemicals,” said Ordemann, adding that U.S. Gulf Coast refiners prefer heavy crude, but the bulk of the added U.S. production is light. “Much of the U.S. production growth will be headed to the water.”

Ordemann’s EPP projects are for a potential of more than 4 million bpd oil exports, along with 1 MMbpd of LPG, and 300,000 bpd of ethane.

While the current capacity cycle is just unwinding, Ken Snyder, chief commercial operator for Frontier Midstream Solutions, told a session of a Permian midstream conference last June that a new capacity cycle will start again after 2020. Snyder expects Permian production to “flatline” and then ramp up again in 2020, following basin crude price differentials swinging from more than $20 to about $3 when ramping begins.

Snyder sees the ying and yang effect as a constant struggle toward rebalancing production and infrastructure that affects producers, pipelines and service companies alike. The by 2020 will begin to see rig counts, well completions and sand volumes flatline prior to ramping up again in the 2020-23 time frame.

In the midst of the Permian’s seemingly endless hyperbole in 2018, most knowledgeable industry observers conclude there is plenty of “there there” given the fact that billions of dollars are still pouring in on both the E&P and infrastructure sides of the business. PBPA’s Robertson sees investments continuing in buying companies or their assets.

Citing the earlier mentioned Diamondback-Energen transaction, Robertson said Diamondback is growing and there are a lot of other companies in the Permian doing the same. “With BP plc’s acquisition of BHP all of the former Big Sisters-related majors are back in the Permian,” he said. “If prices continue to stay where they are, and the costs do the same, then robust operations will continue out here for a good long while.”

The industry professionals who offered their insights for this P&GJ examination of the Permian midstream needs all agree with the extraordinary growth projections for this one-of-a-kind petroleum basin. One commentator called the work on adding new takeaway capacity “the most far-out gas takeaway capacity pipeline project” ever undertaken, noting that an even more robust build-out will probably come later in the 2023-28 period. P&GJ

Richard Nemec is P&GJ’s correspondent based in Los Angeles. He can be reached at


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