ShaleTech- Permian shales: Production hits new high amidst talk of looming plateau

In what proved to be a prescient, albeit conservative, prognostication, the former IHS Markit (now S&P Global) issued a forecast in 2018 that the Permian basin would hit the 5.4-MMbpd production mark in 2023. 

As it is, the West Texas and southeastern New Mexico juggernaut is expected to deliver record production of just over 5.6 MMbopd and 22,496 MMcfd of largely associated gas in April (Fig. 1), according to the U.S. Energy Information Administration (EIA). This would represent a year-over-year increase of 567,000 bopd and 2,963 MMcfgd, respectively.  

Fig. 1. March-to-April oil and gas production is expected to increase by 26,000 bpd and 93 MMcfd, respectively. Source: US Energy Information Administration (EIA)

However, if recent commentary is to be believed, enjoy it while you can. Analysts and others contend a production plateau is on the near-term horizon, in the Midland and Delaware sub-basins of the widely heterogeneous Permian. Quoting data from analytics firms Flow Partners LLC and Novi Labs, the Wall Street Journal on March 8 singled out the Delaware specifically, noting that production from the best 10% of wells drilled in 2022 was 15% lower on average than the top wells put-on-line five years earlier. A BloombergNEF analysis in December has the Permian peaking within five years. 

At CERAWeek by S&P Global in Houston March 6-10, ConocoPhillips CEO Ryan Lance was quoted as conceding as much. "I think that's one of the issues the U.S. is going to grapple with, as it probably does start to plateau later this decade," he reportedly said.  

ConocoPhillips' Permian acreage produced 671,000 boed during fourth-quarter 2022, some 188,000 boed higher than production in the final quarter of 2021. 

The record production comes as crude and especially gas prices have swung wildly this year, with West Texas Intermediate (WTI) settling at 79.72 on April 1, while Henry Hub spot gas prices dropped to 2.21 MMBtu on March 14, down from  $6.50/MBtu year-over-year. Scotttt Sheffield, CEO of Pioneer Natural Resources Co., believes the volatility on oil prices will continue but move to the upside. "I'm still very optimistic that we'll move back into that $90- to-$100 range sometime earlier this summer, as we move it and get away from this $78 to $80 swing in Brent prices," he said.  

A relatively steady average of 347 rigs was active in March (Fig. 2), according to Baker Hughes, with the Texas Railroad Commission (RRC), the state's chief regulator,  having approved 1,823 horizontal drilling permits for the agency's three Permian-centric districts over the first quarter, matching the prior year's quarter. A dissection of data from the New Mexico Oil Conservation Division (OCD) shows some 138 204 drilling permits issued for the same period for the Delaware fairway of Lea and Eddy counties, up by around 74 authorizations from the year prior.  

Fig. 2. Permian drilling activity over the first quarter averaged 352 rigs with 347 rigs at work in March. Source: ConocoPhillips

What has not declined is inflation, as the Permian's consistently high activity brings with it equally higher costs for everything from rigs to labor. "The biggest headwind over the last six quarters has been casing costs," says pure play Diamondback Energy Inc. President and CFO Kaes Van't Hof. "Casing has moved up from what's called $40 or $50 a foot to $110 a foot. We can certainly see around the corner that maybe we're seeing some softening there, but I'm not going to count on it until we see it." 

A measure of relief may, indeed, be in store, says Ovintiv Corp. Executive V.P. and COO Gregory Givens. "We saw quite a bit of inflation throughout 2022, but as we started into the first quarter, it feels like the rate of change has really subsided, and we're seeing a leveling off," he said on March 1. 

For its part, Ovintiv's 2023 drilling campaign will largely mimic that of 2022, with an average three-rig fleet. Following fourth-quarter production, averaging 122,000 boed, the company plans to spend $850 to $950 million in the Permian this year, with 70 to 80 net wells put on production. 

RACE TO 1 MILLION BPD 

Despite "higher-than-expected depletion" from Delaware basin wells last year, Chevron leads the super-major pursuit of the 1-MMboed production milestone. Permian production is expected to hit 1 MMboed by 2025, before plateauing at 1.2 MMboed later in the decade, CEO Mike Wirth reinforced at the Feb. 28 investor day. 

Nevertheless, Wirth takes issue with the notion that the Permian's best days are behind it. "The Permian growth doesn’t end in 2027. We’ve got decades of inventory in the Permian," he said. "The Permian is a resource I wouldn’t trade for anything in anybody else’s portfolio in the industry. We are not falling off the edge of a cliff anytime soon." 

Chevron closed out 2022 with Permian production estimated at around 700,000 boed. While not providing specifics, the company said the performance of Midland basin wells exceeded expectations but acknowledged production and wells fell short in the Delaware, primarily driven by interference issues arising when whittling down a sizeable stockpile of drilled but uncompleted (DUC) wells, many drilled five years ago.  

"We saw some wells impacted by horizontal interference and long-sitting DUCs. We saw some vertical interference, where we piloted multi-bench development, primarily on the southern area of the Delaware basin and the western area of the Delaware basin," said EVP of Oil, Products and Gas Nigel Hearne. "With our large inventory, we’re able to shift our operated program to more single-bench, high-return developments in New Mexico." 

Chevron also was not wholly immune to the Permian's double-digit inflation rates. "The Permian had the highest inflation last year in the industry," V.P. and CFO Pierre Breber said during the investor confab. "Our cost to develop for expected ultimate recovery stayed at $8 a barrel last year, which is the same as it was in 2021, in a different inflation environment." 

Fellow super-major ExxonMobil pushed back its 1 MMbpd target by two years. "When we were talking about our strategy in the Permian in 2018, we had said at that time our plan was to grow to a million barrels a day of production by 2025," says CEO Darren Woods. "When the pandemic hit, we basically said there's going to be a delay in a lot of our plans. We're now forecasting that our Permian production will reach about 1 million barrels a day by 2027." 

Toward that end, the company’s XTO Energy subsidiary grew Permian production by roughly 90,000 boed last year—basically flat year-over-year—much of which, likewise, came from downsizing a DUC well inventory. "As we go into next year (2023), we're going to rebuild that inventory, get to an optimum level that we can then use and maintain as we go through the next several years," Woods said.  

Like Chevron, ExxonMobil has not disclosed how many rigs it intends to run or how many wells will be drilled and/or completed in the Permian.  

Pioneer is gaining ground on the majors, with 2023 production guided at between 600,00 and 700,000 boed (357,000 to 372,000 bopd), operating exclusively from a roughly 820,000-net-acre position in the “high-margin" Midland basin, where 2022 production averaged 650,000 boed.  

The play's most active operator will run 24 to 26 rigs and three simul-frac fleets this year, with 500 to 530 wells put on production, up from 483 new producers in 2022. Last November, Pioneer sold a 92,000-net-acre position in the Texas Delaware basin to the now-private Continental Resources Inc. for $3.25 billion. Continental has not responded to requests for an update on 2023 plans for the asset. 

Following close behind, Occidental Petroleum Corp. averaged 565,000 boed in the final three months of 2022, citing record Delaware well results as helping grow full-year 2022 production by 90,000 boed. "We delivered our best year, ever, in Delaware new well productivity, making 2022 the seventh year in a row that we were able to increase our average well productivity," President and CEO Vicki Hollub said in a Feb. 28 call.  

Among the 191 wells put online last year were two of the company's highest-performing New Mexico wells, specifically targeting the First Bone Spring horizon. In the Midland basin, where the Barnett formation delivered the top six wells, Oxy also drilled the company's longest lateral at over 18,000 ft.     

Occidental controls a commanding 2.8 million net acres, equally split between unconventional and conventional assets, and will run an average of 10 net (23 gross) rigs this year, with 380 to 410 wells expected to go online.  

In a related development, construction is underway on Occidental's direct air capture (DAC) plant in Ector County, Texas, the most ambitious of basin-wide emission control initiatives, Fig. 3. The DAC will begin capturing carbon in late 2024, as a prelude to commercial operation in mid-2025. Designed to capture 500,000 tons/year of carbon dioxide (CO2), inflation has driven the price tag of the facility from $800 million to $1.1 billion. 

Fig. 3. A rendering of a replica of the direct air capture (DAC) plant Occidental is building in the Permian. Image: Carbon Engineering Co.

DELAWARE KEEPS GIVING 

The younger and costlier Delaware basin has been scrutinized over annoying zonal interference issues and notoriously high water cuts, with Coterra Energy Corp. singling out one recent pad that flowed 100,000 bpd of produced water. Regardless, the latest production volumes suggest no let-up is nigh. 

Count Devon Energy Corp. among those convinced that prolific rocks remain to be drilled in the Delaware basin—a conviction reinforced by the 407,000 boed that the company's "franchise asset" produced in the fourth quarter. "A new all-time high for oil production that was underpinned by another year of world-class well productivity in the Delaware," COO Clay Gaspar said. "Once again, the Delaware basin will be the top-funded asset in our portfolio, representing roughly 60% of our total capital budget for this year."  

That asset encompasses around 400,000 net acres, where Devon targets multi-zone development of the Wolfcamp, Bone Spring, Avalon and Delaware formations. A 14-well development, targeting three intervals in the oil-rich Upper Wolfcamp, achieved IP rates as high as 4,200 boed.   

The 2023 campaign, which will average 16 rigs (Fig. 4) with a fourth frac crew added in the first quarter, is expected to result in some 220 new wells. 

Fig. 4. One of the 16 rigs Devon is running in its Delaware basin assets. Image: Devon Energy Corp.

Water cut aside, Coterra, likewise, foresees no decline in well productivity in its Delaware-exclusive Permian assets, with a three-year growth horizon aimed at increasing production from the 87,000 bpd produced last year to an average of 97,100 bpd between 2023-2025. "Over a three-year landscape, we don't see a significant change in our Delaware productivity," says President and CEO Thomas Jorden. 

Coterra added the largely bypassed Harkey shale in Culberson County, Texas to the multi-zone targets that distinguish the Permian as a whole. In what is described as a "promising new development," the operator sees the Harkey and Wolfcamp formations as a single petroleum system, which ostensibly would raise interference concerns. 

"There will be some degree of pressure communication between the Wolfcamp and Harkey, depending on where you are in the basin," Jorden said. "But our thinking is that having the two landing zones does not interrupt or impede your overall recovery out of that drilling spacing unit, so we don't see that as a significant issue for the Wolfcamp Harkey." 

Coterra expects 49% of an $880 million-to-$970 million 2023 capital budget to be earmarked for the 307,000-net-acre Delaware leasehold, with five to six rigs primarily targeting the Wolfcamp and Bone Springs intervals. The company plans to put between 75 and 85 wells into production this year—up from 61 new wells last year—including 13 gross (6.5 net) Wolfcamp and Harkey wells, expected to go online in the fourth quarter. 

Driven partly by preliminary results from a new pad featuring co-developed Woodford/ Meramec wells, Marathon Oil Corp. has graduated the Delaware from exploration to development. "Our Texas Delaware position is no longer an exploration play," says Executive V.P. of Operations Michael Henderson. "The asset is now fully integrated into our Permian asset development team, where it will compete for capital on a heads-up basis with all the other assets." 

For now, however, the Delaware is losing that competition to the Eagle Ford and Bakken shales, which will share 80% of the $1.9-to-$2-billion 2023 capital budget. Marathon plans to run around two rigs in the Permian this year, compared to four in the Eagle Ford and three active rigs in the Bakken.  

"But there’s no doubt that the Permian, now coupled not only with the northern Delaware position, but also with the Texas Delaware Woodford/Meramec is going to start stepping up and competing more directly for capital," says President and CEO Lee Tillman.  

Results from three recently completed Woodford/Meramac co-developed wells on the subject pad "are performing well to date and consistent with our pre-drill expectations," Executive V.P. of Corporate Development and Strategy Patrick Wagner said on Feb. 20, noting early indications show the wells exhibiting high oil cut, low water ratios and low decline rates. 

"The key takeaway, so far, is that there’s no communication we’ve seen between the Woodford and the Meramec, which gives us strong evidence that we can successfully co-develop those two reservoirs," he said. "We need some time to look at longer-term performance, but early indications are good. We will drill another multi-well pad this year to continue the development, and we’ll see how it goes." 

The northern Delaware portion of Marathon's 150,000-net-acre Permian position produced 33,000 net boed (20,000 bopd) in the fourth quarter, with six operated wells put to sales. Marathon plans to spud 25-30 wells this year, with up to 20 Permian gross operated wells expected to be put on production. 

Conversely, Callon Petroleum Co. says more than 80% of a $1-billion 2023 capital budget is earmarked primarily for the Delaware, with what remains directed to the Eagle Ford. Four of the five to six rigs the company will operate this year will target the Delaware's Wolfcamp A, B and C benches, with up to 63 wells turned-in-line, compared to 26 in 2022. Callon's overall Permian leasehold comprises 128,000 net acres, where 2023 production is forecast to average 104,000 to 107,000 boed. 

Recently formed Permian Resources Corp., however, lays claim to being the largest pure-play Delaware operator. Springing out of the $7-billion merger of Centennial Resource Development Inc. and Colgate Energy III, LLC in September 2022, the company controls over 180,000 net acres, with estimated 2023 production of 155,000 to 168,000 boed (82,000 to 88,000 bopd).  

In the first full quarter as a new company, Permian Resources reported oil production of 81,400 bpd in the last three months of 2022, representing a 9% increase over previous guidance. Total production this year is expected to range from 150,000 to 165,000 boed, with 150 wells turned-in-line. The operator will lay down one of the seven active rigs in the second quarter but still intends to spud 135 to 155 gross wells, while completing 140 to 160 gross wells in 2023. 

BEEFING UP 

While not featuring the mega-deals of a couple of years ago that trimmed a number of established players from the active roster board, operators in 2022 leaned more toward acquiring bolt-on route acreage, to enable longer laterals that, on some pads, have extended up to 3 mi.  

Back-to-back acquisitions added 83,000 net acres and an estimated 37,000 bpd of oil production to Diamondback's Midland basin leasehold. The company now controls 497,000 net acres across the Midland and Delaware basins, though activity has concentrated largely in the lower-cost Midland. 

Diamondback closed the $850 million cash and stock deal for privately-held Lario Permian, LLC on Jan. 31, following the Nov. 30 purchase of FireBird Energy LLC in 2022, which included $775 million cash and stock.  

Adding in the two acquisitions, the company expects 2023 production of between 256,000 and 262,000 bpd, with 325 to 345 gross (293-311 net) wells drilled and 330 to 350 gross (297-315 net) wells completed. The 2023 program includes 15 rigs and four simul-frac crews.   

Last year, Diamondback drilled 197 gross Midland wells, where costs per lateral ft range from $620 to $680, and turned 213 operated wells online in a multi-zone development strategy that largely targets the Lower and Middle Sprayberry, Wolfcamp A and B benches and the Jo Mills. With costs ranging from $900 to $1,000 per lateral ft, 43 gross wells were drilled and 42 put on production in the Delaware. 

APA Corp., aka Apache, placed a reported $555 million bet on the Delaware with the acquisition of privately held Titus Oil and Gas assets in Texas' Loving and Reeves counties on July 29, 2022. Few details have emerged since the so-called "tuck-in acquisition," other than that the properties were expected to add an average of 12,000 to 14,000 boed to 2022 production.  

The newly acquired position is located near the company's once-ballyhooed Alpine High gas-rich resource play in Reeves County, where results thus far have fallen short of expectations. Citing limited infrastructure and low gas prices, APA suspended activity in the play in early 2020, but it tentatively expects to restart production this year, although tumbling prices may throw a wrench in the plans. 

"We've got five (Alpine High) wells that will be coming on by year-end. But it is something we can toggle, and we'll tend to leverage that," President and CEO John Christmann said in a Feb. 23 call. "What you've seen this year is that given the weakness in Waha (West Texas) and U.S. gas, there's no reason to be bringing on incremental volumes, but it's really about prepping for the opportunity and having that optionality when you look at 2024 and beyond, as some of the basin bottlenecks open up." 

The company averaged three rigs in the Delaware in the fourth quarter, with no new wells put on production and two rigs in the Midland basin, with one well turned-in-line. 

Following on the heels of record yearly production, Matador Resources Co. added 18,500 bolt-on acres in the northern Delaware in January, with the $1.6-billion acquisition of Advance Energy Partners Holdings, LLC. The transaction, which is expected to close in the second quarter, also provides for Matador to pay an additional $7.5 million for each month during 2023 that the average oil price exceeds $85/bbl.  

Upon closing, the Dallas-based operator will hold 147,900 net acres in New Mexico and West Texas. The deal includes contiguous undeveloped acreage in Lea County, N.M. and Ward County, Texas. 

Matador's average 2022 production of 105,500 boed is expected to increase 18% this year. The Delaware acreage, which averaged 106,100 boed in the final quarter, is forecasted to average 73,000 bopd in 2023, compared to 60,100 bpd last year. 

Matador's guided 2023 development pace calls for 92.7 net (118 gross) operated wells to go online this year, which will be the first time the company has ever put more than 90 net operated wells on production in a given year. Matador plans to run eight rigs, with one dedicated solely to the newly acquired Lea County properties. 

Newly rebranded Vital Energy Inc. (formerly Laredo Petroleum) expanded a Midland Basin footprint by 11,200 net (16,500 gross) acres with the Feb. 14 acquisition of Driftwood Energy Operating, LLC. Valued at $127.6 million cash and stock, the deal comprises around 5,400 boed of production.  

Upon closing in April, Vital will control 163,000 net acres and will largely maintain the average of two rigs and a one-frac spread program in force at year-end 2022, but it will drop from two to one completions crew for the final nine months of 2023. "We plan to develop these assets over the next two to three years, without increasing our current activity levels," says President and CEO Jason Pigott. 

Total fourth quarter production of 77,000 boed (35,900 bopd) exceeded the high end of guidance. Over the final three months of 2022, Vital completed 12.8 net (13 gross) wells with 10.8 net (11 gross) wells put online. 

OIL, WIND JOIN FORCES 

Pioneer Natural Resources is turning to the brisk West Texas wind to help completely electrify Permian basin operations. 

In October 2022, Pioneer teamed up with Florida clean energy company NextEra Energy Resources LLC to build a 140-MW wind farm on a portion of its Midland basin leasehold, Fig. 5. The electricity generated will be used to power field operations, as well as the gas processing facilities of Pioneer partner Targa Resources Corp. Construction is underway, and the farm is expected to go online in 2024.  

"NextEra is the owner of the project, and we will be taking the electricity that's generated and using it in our operations and our gas plant operations with Targa," said President and COO Richard Dealy.  

Pioneer expects 100% of its completion fleets to be either electric or dual-fuel-powered by the second half of 2023, with all Permian operations to be fully electrified no later than 2025.  

Fig. 5. A smattering of the 627 terminals on the Roscoe Wind Farm, one of the world's largest, tower over the irrigation system of a West Texas cotton field. Wind power is being seen as a potentially viable solution to electrify Permian basin field operations. Image: RWE Renewables.

Lead photo: The alleged Permian decline has certainly not occurred yet, as reflected in the record 407,000 boed that Devon pulled from this and other Delaware basin production locations in the fourth quarter of 2022. Image: Devon Energy Corp

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.