April 2019

Majors double down as takeaway crunch eases

They may have arrived late to the shale soiree, but the super-majors have shown up with overflowing wallets, lofty production targets, and they’re setting the tone for the next wave of development in the transcendent Permian basin.
Jim Redden / Contributing Editor

They may have arrived late to the shale soiree, but the super-majors have shown up with overflowing wallets, lofty production targets, and they’re setting the tone for the next wave of development in the transcendent Permian basin.

“The race doesn’t go to the one who gets out of the starting blocks the fastest,” Chevron Corp. CEO Mike Wirth said on March 5, per Dow Jones. “The race goes to the one who steadily builds the strongest machine.”

Over the next four years, the Chevron and ExxonMobil machines are gearing up separately to increase combined production to nearly 2 MMboed from the Permian’s smorgasbord of stacked pay targets beneath West Texas and southeastern New Mexico. For perspective, total Permian oil and gas production is estimated to reach 4.177 MMbpd and 14,075 MMcfd, respectively, in April, according to the U.S. Energy Information Administration (EIA), Fig. 1.

Fig. 1. Month-over-month oil and gas production in the Permian basin is estimated to increase 43,000 bpd and 219 MMcfd, respectively, in April. Source: U.S. Energy Information Administration (EIA).
Fig. 1. Month-over-month oil and gas production in the Permian basin is estimated to increase 43,000 bpd and 219 MMcfd, respectively, in April. Source: U.S. Energy Information Administration (EIA).


Between them, Chevron and ExxonMobil subsidiary XTO Energy are running nearly 70 of the 463 rigs that Baker Hughes, a GE Company reported as active during March, up from the average 438 active rigs in March 2018.

The prodigious spending of the majors contrasts sharply with the slew of independents—many with their eggs entirely in the Permian’s multi-zone basket—which are forced to rein in expenditures to appease cranky investors. They also must cope with lingering takeaway restrictions and associated price differentials, as illustrated by ConocoPhillips, which last year laid down one of the three rigs it was operating “as the differentials blew out,” COO Matt Fox said on Jan. 31.

Excluding roughly 600,000 bpd of local refinery demand, the current Permian oil pipeline capacity is 3.2-to-3.3 MMbpd, but it is expected to increase by at least 3 MMbpd over the next two years, says IHS Markit V.P. of North American Unconventionals Raoul LeBlanc. Later this year, the Cactus II, EPIC and Grey Oak networks are scheduled to go into service, with more pipelines to follow through the end of 2020, building to a capacity of nearly 6.5 MMbopd, he said.

Rail and truck transport, as well as flow enhancements and extensions to existing pipelines, have helped take some of the bite out of takeaway headaches. “Everybody expected last year to see a real bottleneck develop, and you did see distress last summer, but these guys figured out a way to get the oil to market, so it wasn’t as bad as feared. Gas has been more problematic,” LeBlanc said in an interview. “Differentials are tough, however, and could get more difficult over the course of this year, until these pipes come on.”

The added capacity and initiation of large-scale field developments also are likely to whittle down a drilled but uncompleted (DUC) inventory of 4,004 wells as of February, 568 wells shy of the combined DUC stockpile of the other six major U.S. shale plays the EIA tracks.

For now, Permian operators have seen costs drop from 5% to 10%, driven partly by a surfeit of locally produced sand and an overall service sector characterized by “expectations not meeting reality,” Le Blanc said. “The service companies expected and built equipment for the kind of activity levels we were on our way towards, until the price got derailed in the fourth quarter.”

Meanwhile, amid continued price volatility, it remains to be seen if the no-less-than $29.2 billion in 2018 acquisitions will come close to being replicated this year. For the time being, acquisitions are replaced with basin-wide asset swaps to block up acreage for longer lateral lengths, coinciding with widespread spacing tests to help mitigate production-draining “parent-child” well interference issues.


Between Jan. 1 and March 16, the Texas Railroad Commission (RRC), the state’s chief regulator, approved 1,916 horizontal drilling permits for the Greater Permian districts of 08, 8A and 7C, compared to 1,612 authorizations for the same period last year. Of the permits authorized this year, 1,647 were for horizontal wells in District 08, which takes in the rapidly expanding Delaware basin on the western side of the Central basin Platform/Northwest Shelf, which separates it from the more well-defined Midland basin. The Delaware extends into New Mexico, where much of the prospective acreage is under federal control.

In an updated assessment released on Nov. 28, the U.S. Geological Service (USGS) pegged the Delaware’s Wolfcamp and Bone Spring shales as holding more than twice the reserves of the Midland basin. The USGC assessed the Delaware with undiscovered and technically recoverable resources comprising 46.3 Bbbl of oil, 281 Tcf of gas and 20 Bbbl of natural gas liquids (NGL).

Two months before the USGS release, the U.S. Bureau of Land Management (BLM) collected nearly $1 billion in the sale of 142 federally owned parcels in the three core New Mexico counties of Eddy, Chaves and Lea, exceeding the bonuses received in 2017 from all nationwide lease offerings combined. One 1,240-acre parcel in Eddy County brought in $81,889/acre, according to the BLM.

Compared to the more weathered Midland basin, the mercurial growth and higher costs of Delaware wells can make for a taxing proposition. In what he described as “a tough first half,” Noble Energy Inc. President and COO Brent J. Smolik said the company had to work through “the growing pains of early-phase development and rapid facility build-out,” and scattered parent-child issues. Nevertheless, Noble managed to more than double, year-over-year, production to 60,000 boed in the fourth quarter. The company holds 94,000 net acres in the southern Delaware basin and will run four rigs (Fig. 2) and two frac spreads this year, and bring between 50 and 55 wells online at average laterals longer than 8,700 ft. Production was expected to commence late in the first quarter from the first row development in Reeves County, Texas, located near one of the five central gathering facilities (CGF), with a cumulative 90,000-bopd capacity.

Fig. 2. A Noble Energy drilling location in the southern Delaware basin, where it plans to run four rigs this year. Image: Noble Energy Inc.
Fig. 2. A Noble Energy drilling location in the southern Delaware basin, where it plans to run four rigs this year. Image: Noble Energy Inc.



Chevron has earmarked $3.6 billion for the Permian in 2019 and “over time, I think that number is likely to grow rather than shrink,” said Wirth. Chevron is running 20 rigs on 1.7 million unconventional acres in the Midland and Delaware basins.

From 2018 production averaging 310,000 boed—up 71% over the year prior—Chevron plans to ramp up to 600,000 boed by year-end 2020, and 900,000 boed by 2023.

ExxonMobil set an even more ambitious target to increase production five-fold, to more than 1 MMboed by 2024. The major’s XTO Energy subsidiary will jump from 48 to 55 rigs by year-end. ExxonMobil more than doubled its resource base two years ago with the $6.6-billion acquisition of 3.4 Bboe and 227,000 net acres in the New Mexico Delaware basin.

Shell Oil Co. aims to increase Permian production by 30%/yr from the current 145,000 boed output, while making clear it is on the lookout for opportunities to expand a comparably modest leasehold. A spokesperson, however, declined comment on reports that Shell was in talks to acquire privately held Endeavor Energy Resources LP and its 300,000-net-acre Midland basin leasehold.

Shell holds interests in 260,000 acres in the Texas Delaware basin, largely held in a once-shaky joint venture with Anadarko Petroleum Co. The partners made nice last year after a tiff over spending and operatorship issues.

While Shell provided no specifics on current activity, CEO Ben van Beurden paints a rosy picture of where the Permian ranks in its portfolio. “We’ve matured an inventory of resources in excess of 1 Bboe in the Permian, with forward-looking break-even prices of less than $40/bbl. So, we expect to deliver continued growth through 2020,” he told analysts on Jan. 31.

Elsewhere, BP is the outlier, with the newly acquired 83,000-net-acre Delaware position temporarily on the backburner. The Permian asset is part of the $10.5-billion acquisition of BHP’s three U.S. shale plays, which closed on Oct. 31, 2018.

Bernard Looney, chief executive, upstream, says most of the $2-billion shale-directed expenditures this year will be diverted to the Eagle Ford and Haynesville properties included in the blockbuster deal. “Over time, we’ll probably ramp capital up to around $2.5 billion, with the majority of the capital overtime, as the logistics constraints get lifted, shifting towards the Permian,” he said.

With $2.6 billion allocated to Permian resources, Occidental Petroleum Corp. is one of the top 2019 spenders among the non-majors. The company will operate 12 rigs in the Delaware basin, with up to seven targeting the Bone Springs and Wolfcamp shales in New Mexico, and the remainder focused primarily on developing the Wolfcamp A and Hoban formations in Texas. The unconventional leasehold of 1.4 million net acres includes 25,000 net acres of swaps completed last year.

Oxy exited 2018 with combined shale and enhanced oil recovery (EOR) production exceeding 400,000 boed. “We’re trying to outperform the majors, and I think that we’re clearly doing that in the Permian at this time,” said President and CEO Vicki Hollub. “We’re doing a lot more with the rigs we employ today than many other companies are with almost double the rigs we have.”

Anadarko, for its part, expects to average 10 rigs and five completion crews (Fig. 3), following a fourth quarter that delivered record 127,000-boed production. Anadarko holds nearly 600,000 gross acres in the Delaware, with some 8,500 ft of stacked pay potential. Last year, Anadarko started up two regional oil treating facilities to support the Silvertip-A development in northern Loving County, the company’s first Permian multi-well pad development.

Fig. 3. An Anadarko drilling site within the rapidly expanding Delaware basin. Image: Anadarko Petroleum Co.
Fig. 3. An Anadarko drilling site within the rapidly expanding Delaware basin. Image: Anadarko Petroleum Co.


Like many of its peers, Anadarko will operate under a leaner capital budget this year compared to 2018, while projecting 10% year-over-year production growth.


Apache Corp.’s budgeted 2019 upstream expenditures of $2.4 billion represent a 22% reduction over 2018’s level, reflected in a smaller active rig fleet across the more than 2.8 million gross acres under control. Apache will average 12 rigs (Fig. 4) and four frac spreads in 2019, with half directed to the Alpine High resource play, covering some 300,000 net Delaware acres in Reeves County, Texas. Apache expects to drill 85 Alpine High wells, focusing primarily this year on wet gas targets, with 55 wells on tap for the Midland basin and elsewhere in the Delaware.

Fig. 4. Apache will dedicate up to six rigs, like this one, to its Alpine High play in the Delaware basin. Image: Apache Corp.
Fig. 4. Apache will dedicate up to six rigs, like this one, to its Alpine High play in the Delaware basin. Image: Apache Corp.


Apache formed Altus Midstream Co. last year to independently fund the midstream investments at Alpine High. The entity now comprises 380 MMcfd of in-service rich gas processing capacity, more than 111 mi of gas gathering pipelines and associated market connections.

Fresh off closing the $1.6-billion acquisition of Resolute Energy Corp. in March, Cimarex Energy Co. is running 10 rigs and three completion crews, with 66 new drills on tap for the Delaware. The 2019 focus is on long-reach (10,000 ft) Wolfcamp wells and stacked-pay prospects, combining the Upper and Lower Wolfcamp, the Second and Third Bone Spring and the Avalon shales.

The bolt-on Resolute acquisition added 21,100 net acres and 35,000 boed of production in Reeves County, bolstering Cimarex’s pre-closing position of 259,000 net acres.

After increasing production by 138% in the fourth quarter compared to the year-ago quarter, Marathon Oil Corp.’s 2019 activity will remain “at a level that’s more or less on par with 2018,” said President and CEO Lee Tillman. Between 55 and 60 gross wells are slated to initiate production, as part of the transition to multi-well pads. Marathon owns 91,000 net acres in the Northern Delaware of New Mexico, where it concentrates on continued delineation of the Red Hills asset in Lea County and, following a series of lower Wolfcamp spacing tests last year, development of the upper Wolfcamp in the Eddy County Malaga asset.

With rights to 46,000 net Delaware acres, Carrizo Oil & Gas, Inc., will run two to three rigs this year to drill between 20 and 25 net wells, while completing 15 to 20 net wells. In a related development, Carrizo has not commented on a Bloomberg report from March 18 that has it in negotiations to acquire SM Energy Co., which expects to drill and complete some 100 wells in the Midland basin this year. SM Energy planned to add a sixth rig in March to join three operated completion crews.

Among the more-active pure-play operators: 

Concho Resources Inc., just under a year removed from the $9.5-billion acquisition of RSP Permian Inc., will average 27 rigs, down from 34 active rigs and seven completion crews in 2018. Nonetheless, Concho expects production to reach 300,000 to 306,000 boed in the first quarter, compared to 263,000 boed last year.

With the RSP merger, Concho holds 930,000 gross acres, including an aggregate 60,000 net acres included in 15 asset trades last year, “improving the company’s development platform for large-scale, long-lateral manufacturing projects.”

Some five months after finalizing the $9.2-billlion deal to buy Energen Corp., Diamondback Energy projects 27% year-over-year production growth in 2019, to 275,000 boed to 290,000 boed. Within a post-closing leasehold of more than 364,000 net acres, Diamondback will run 18 to 22 rigs and two frac fleets in 2019, and complete 290 to 320 gross wells with average lateral lengths of around 9,400 ft.

Parsley Energy Inc. will average 12 to 14 rigs and three to four frac spreads, down from six rigs and five frac spreads in 2018. Parsley, which owns 192,000 net acres, drilled 38 wells in the fourth quarter, including a Wolfcamp well in northern Midland County with a 3-mi (15,840 ft) lateral, and brought 43 wells to production with average lateral lengths of 9,300 ft.

Callon Petroleum Co. will drop from six to four rigs at mid-year, but projects year-end production growth of 39,000 boed to 41,500 boed. With a leasehold of roughly 85,000 net acres, Callon plans to put 47 to 49 wells on production, while building a DUC inventory in the Delaware basin to support “the transition to larger-scale development.”

Jagged Peak Energy Inc. expects 51 net wells to be put online at a capital cost of around $605 million in 2019, compared to $690.8 million spent in 2018 to start production on 48 net wells. Jagged Peak will average five rigs and one frac spread across 75,000 net acres in the southern Delaware basin, concentrating mainly on developing the Wolfcamp A and Third Bone Spring zones on the Cochise and Whiskey River assets in Texas, in Winkler and Ward counties.

Centennial Resource Development Inc. will operate a reduced six-rig fleet this year, but the firm expects to grow yearly oil production by 12%. Centennial will focus activity on the Upper Wolfcamp A in Reeves County, while testing additional formations, including the Bone Spring. Formed in 2016, Centennial owns around 80,000 net acres in the Delaware basin, where it has set a 2019 oil production target of 61,500 bpd to 70,500 bpd (36,500 boed to 41,500 boed).


Imminent pure play operator Pioneer Natural Resources Co., meanwhile, has identified savings exceeding $1 million/well by self-sourcing finer-grade sand and signing a 10-year dedicated services agreement with a homegrown pressure pumping company.

After decommissioning its Brady sand mine, Pioneer switched to predominately 100-mesh, locally produced sand, saving $350,000 to $400,000/well, “with no impact on well performance,” said Executive V.P. of Permian Operations J.D. Hall. Correspondingly, transitioning to a lower viscosity fracturing gel reduced surfactant consumption, saving an estimated $200,000/well. “We’re able to deliver the same amount of sand for less cost,” Hall said.

Pioneer also sold its pressure pumping entity last November to Midland-based ProPetro Holding Corp. for $400 million and, in turn, signed a services agreement that provides dedicated capacity for up to a decade, saving around $650,000/well. Pure play ProPetro has a now-combined fleet of 28 pressure pumping spreads with more than 1.4 million hp capacity.

Pioneer owns 680,000 net acres in the Midland basin, where 2018 production increased 26% year-over-year to 283,000 boed, setting the stage for a 2019 year-end target of between 320,000 boed and 335,000 boed. Pioneer will average 21 to 23 rigs and place 265 to 290 wells on production, with average lateral reaches around 9,800 ft.

Following the second “Stackberry” appraisal pad in Midland County, comprising eight wells divided between the Middle Sprayberry, Jo Mill and Lower Sprayberry, more multi-well developments are planned this year. The pad went on line in the fourth quarter at rates roughly 35% higher than offset Sprayberry wells. A third Stackberry test was online and cleaning up in the first quarter.

A prime mover of the cube development strategy, Encana Corp. has driven down costs 20%/well over the past four years, thanks partly to a sweeping self-sourcing initiative. An average Midland basin well, completed with an 8,500-ft lateral, now costs around $6.1 million.

Encana will run four rigs and two to three completion spreads on average this year, and drill between 105 and 120 wells and complete 150 net wells on 115,000 net acres.

Between self-sourcing 25% of total well costs and flexible rig contracts, EOG Resources, Inc. is looking at cutting spending on a typical Wolfcamp oil well with a 7,000-ft lateral from $7.5 million in 2018 to $7.2 million this year. EOG will average 20 rigs and six frac crews on a 579,000-net-acre Delaware basin and Northwest Shelf leasehold, with 270 planned completions. The asset is said to contain 4,800 ft of stacked pay from the Woodcamp, Second and Third Bone Spring and Leonard shales.

Production exceeded 220,000 boed in 2018, “making it our fastest-growing asset for the third year in a row,” said Ezra Yacob, executive V.P., exploration and production. WO

About the Authors
Jim Redden
Contributing Editor
Jim Redden is a Houston-based consultant and a journalism graduate of Marshall University, has more than 40 years of experience as a writer, editor and corporate communicator, primarily on the upstream oil and gas industry.
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