September 2021, Vol. 236, No. 9

Features

Permian Update: America’s Oilfield Builds Back from Another Bust

By Jeff Awalt, Executive Editor 

Stop me if you’ve heard this one before. 

Photo: Plains All American
Photo: Plains All American

Oil and gas producers in the prolific Permian Basin of West Texas and New Mexico respond to surging global demand by ramping up drilling to record highs. As production threatens to outpace takeaway capacity, pipeline operators answer with a slew of new projects to deliver more product to key markets. Economics shift, the bottom falls out and the cycle moves from boom to bust. Then another recovery begins. 

Three quarters of the way through what was to be a post-pandemic year, the midstream sector of America’s biggest oilfield is slugging its way back from the bottom again. 

Building Up 

The Permian Basin was nearing the end of a pipeline construction boom that had already expanded crude oil takeaway capacity well above production levels even before the 2020 pandemic shutdown devastated the world economy, sharply reducing transportation and power-generation demand. 

Shale advancements and the removal of a U.S. ban on oil imports in late 2015 had combined to create a perfect storm for Permian Basin expansion. Average daily production was growing at a rate of roughly 1 million barrels per year to about 4.5 MMbpd by mid-2019. 

Pipeline operators answered the growing oil production and shrinking takeaway capacity with a half-dozen major construction or expansion projects, starting with Enterprise Products’ 575,000-bpd Midland-to-Sealy pipeline, which commanded a 25% tariff premium when it started commercial operation in 2017.  

That project was followed by Plains All American’s 500,000-bpd Sunrise Pipeline expansion in late 2018, Enterprise Products’ 200,000-bpd conversion of the Seminole-Red natural gas liquids (NGL) pipeline to crude oil in early 2019 and Energy Transfer’s 120,000-bpd Permian Express 4 expansion in mid-2019.  

Still another 4 MMbpd of takeaway capacity was added to the route in 2019–2020 with completion of Plains’ Cactus II Pipeline, Epic Midstream’s Epic Crude oil pipeline, Enterprise Products’ Wink-to-Webster Pipeline and Phillips 66’s Gray Oak Pipeline. 

Hitting the brakes 

Since then, overall midstream spending in the Permian has scaled way back, and it’s expected to be years before major new pipelines are needed again, starting with natural gas projects. 

Plains All American and Phillips 66 canceled plans for their proposed 400,000-bpd Red Oak Pipeline, which was to have transported oil from the Permian Basin and Cushing, Okla., with a targeted completion date this year. The proposed 650-mile (1,046-km) Jupiter Pipeline from the Permian Basin to Brownsville also fell by the wayside. 

“Capex [capital expenditures] has been reduced significantly across the board,” said Ryan Smith, senior director of Commodity Markets at East Daley Capital. “And in those instances where we see some continued spend, it’s mostly limited to projects that were already in the hopper before COVID. 

“Over the next four years, we expect cumulative capex in the Permian Basin to be less than what companies spent in 2019,” said Smith. 

Although activity is growing upstream, pipeline operators have taken a beating on the pipeline capacity glut.  

Just how over-piped is the Permian?  

Before COVID, there was about 1.75 MMbpd of excess crude oil takeaway capacity. As of June 2021, that had grown to 3.82 million. Of that number, 2.87 million is on Permian-to-Gulf Coast lines. 

Photo: Kinder Morgan
Photo: Kinder Morgan

With all that excess capacity, the rates that pipeline operators get for crude transport have plummeted. In 2018–2019, when capacity was tight and pipeline projects were still under construction, tariffs from the Permian to the Texas Gulf Coast rose to the $3.00–$4.00 range. Now they’re under $1. 

Consolidation 

Upstream and midstream companies alike have scaled back, with downsized operations, reduced staff, bankruptcies and consolidation. On the upstream side, there was no less than $26.2 billion in acquisitions during the first quarter of 2021 alone, according to World Oil. 

Consolidation impacting the midstream in recent months includes the $9.7 billion ConocoPhillips acquisition of pure-play Concho Resources, one of the largest unconventional shale producers in the Permian Basin. 

Chevron, the second-largest U.S. oil producer, closed a $4.1 billion all-stock purchase of smaller rival Noble Energy in October, making Chevron the No. 2 U.S. shale oil producer behind EOG Resources. Now Noble Midstream’s largest customer, Chevron in May bought all of the remaining shares of Noble Midstream in a deal valuing the company at $1.13 billion. 

More recently, Plains All American and Oryx Midstream Holdings agreed to merge their assets, operations and commercial activities in the Permian Basin into a newly formed joint venture (JV), Plains Oryx Permian Basin LLC. The transaction included all of Oryx’s assets and the majority of Plains’ assets in the Permian Basin, but the transaction excluded Plains’ long-haul pipeline systems and some of its intra-basin terminal assets. 

Plains holds 65% of the JV and Oryx holds 35%. Plains’ assets in the JV include 3,900 miles (6,300 km) of pipeline and related operational storage capacity located within the Permian Basin, long-term acreage dedication and marketing agreements covering approximately 2.8 million acres (1.1 million ha). Oryx assets include 1,600 miles (2,600 km) of pipeline, operational storage capacity and agreements covering 1.3 million acres (526,000 ha).  

Upstream Discipline  

Upstream activity drives midstream, of course, and for all the similarities with past cycles, there are some differences this time around. 

For starters, many U.S. producers who followed the “drill, baby, drill!” mantra whenever prices rose in the past have, so far, demonstrated rare fiscal restraint in this cycle.  

Taylor Vactor, a commodity analyst at East Daley, said that trend is largely limited to publicly traded upstream companies that have been under pressure from investors to hold down costs and increase their returns on investments. 

“We definitely have seen an impact of the public producers, in particular, being fiscally disciplined, prioritizing their investors and paying down debt,” Vactor said. “I, for one, have been super impressed that they’ve stuck to what they had said they would do and didn’t jump at higher oil prices.” 

Among those is Pioneer Natural Resources, a New York Stock Exchange (NYSE)-traded company and the largest independent producer in the Permian Basin. Its CEO, Scott Sheffield, said in early August that U.S. shale production is “not going to grow that much” in coming years, as companies continue to focus on shareholder returns.  

But the Permian is abuzz with drilling by privately owned exploration and production (E&P) companies.  

“The private Permian operators are reacting to prices as they normally would –bringing rigs back and being fairly aggressive with drilling and production,” Vactor said. 

Among privately held producers, U.S. Energy Development Corporation is the latest to signal expansion in the Permian Basin. In August, it announced a JV with Midland-based Atlantic Energy Partners to develop and operate three horizontal wells in the Permian Basin at an estimated cost of about $22 million. 

Past cycles have not seen drilling activity split between public and private companies, because there was little discipline among either of them. Despite recent austerity, some analysts think public operators may change their tune in the latter months of 2021 and early 2022. 

One recent indicator of this was an August announcement by ExxonMobil and Chevron that they would ramp up drilling in the second half and likely surpass 600,000 bpd by the end of 2021. Although they expect their full year to be in the lower end of their guidance range, they expect more spending in the Permian for the rest of this year. 

Focus on Natural Gas 

While most pipeline construction in recent years has focused on oil transport, Kinder Morgan has led the way in expanding takeaway capacity for high volumes of gas associated with Permian oil production.  

Photo: Kinder Morgan
Photo: Kinder Morgan

The first big natural gas pipe to enter service in the Permian in recent years was Kinder Morgan’s $1.75 billion Gulf Coast Express in September 2019, which provided the region with much needed takeaway capacity to the Gulf Coast.  

Major new Permian gas pipelines that began full service this year include the Permian Highway Pipeline and Whistler Pipeline. 

In January, Kinder Morgan began full service on its Permian Highway Pipeline, a 430-mile (692-km) system that transports up to 2.1 Bcf/d (59 MMcm/d) of natural gas from the Waha area in Texas to U.S. Gulf Coast and Mexico markets. It is fully subscribed under long-term, binding agreements.  

Kinder Morgan Texas Pipeline LLC owns a 26.7% interest in Permian Highway Pipeline and operates the pipeline. Other equity holders include Altus Midstream, EagleClaw Midstream and an affiliate of an anchor shipper. 

“We believe that the Permian Basin will remain an important supply basin for decades, and our strong network of pipelines provides the ability to connect this supply to critical markets along the Gulf Coast,” Kinder Morgan Natural Gas Midstream President Sital Mody said. 

Kinder Morgan was evaluating the potential construction of Permian Pass Pipeline from the Permian Basin to the Southeast Texas/Louisiana market but postponed the project last year as market conditions changed. The Houston-based company thinks there may be sufficient demand for the project around mid-decade. 

“The real winner in all of the gas pipeline projects is Kinder Morgan,” said East Daley’s Smith. “They were able to integrate those two big pipeline expansions with intrastate pipelines along the Texas Gulf Coast. So, they have vertical integration on both sides of the pipe. 

Whistler Pipeline is the latest major project completed in the Permian. The 450-mile, 42-inch natural gas pipeline began full commercial service to Texas Gulf Coast markets on July 1. The project stretches from the Waha Header near Midland to the Agua Dulce near Corpus Christi and includes a 50-mile (80-km), 36-inch lateral for connectivity to the Midland Basin. 

It is owned by a consortium of MPLS, WhiteWater Midstream and a JV between Stonepeak Infrastructure Partners and West Texas Gas. 

Perking Up 

Oil and gas production in the Permian has continued to recover through 2021, and some analysts believe it may fully recover from the pandemic by next year.  

Active rigs in the Permian Basin had climbed to 253 rigs by mid-2021, representing nearly half of the rigs operating in the United States, according to Enverus. 

Analytics firm GlobalData noted that Permian oil production had climbed to 4.6 MMbpd by August of this year and is projected to surpass 4.9 MMbpd by mid-2022. That compares with 4.8 MMbpd of Permian production in February 2020, before the COVID-19 crisis struck the United States. 

With major pipeline projects completed and a significant oversupply of crude oil transportation available, it appears the greater opportunity for midstream growth in the Permian will be in natural gas. But the outlook is still hazy. 

Natural gas pipeline rates have weathered the downturn better than crude, but that may partly reflect their typically longer contract terms. 

“Most of the contracts for natural gas pipelines like Gulf Coast Express, for example, are 10-year contracts, but you tend to see shorter terms of 3 to 5 years on the crude side,” said Smith. “So, we haven’t seen much movement on the gas pipeline rates.” 

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