Don’t look now, but the United States rig count has inched up in recent months, and the driver has been the old reliable of onshore oil production, the Permian Basin of west Texas and New Mexico.
While some observers might see the scenario as a simple case of drillers responding to the recovery of oil prices over the spring and summer, the fact that rig growth occurred chiefly in the Permian indicates there is more to the story. And along with a similar, smaller shift of gas rig activity toward the Marcellus and Utica basins in Pennsylvania and Ohio, the statistics suggest what the geographic footprint of an eventual, long-term recovery may look like in the US.
The number of active oil rigs nationwide rose to 407 for the week ending on 2 September, according to Baker Hughes, up from 316 for the week of 27 May. Of the additional 91 rigs, 65 were activated in the Permian Basin. Beginning from a low point of 132 rigs operating in the week of 29 April, the basin has added 70 rigs, and it currently has more than 50% of the horizontal oil rigs operating in the US, up from 15% in 2011.
A smaller growth trend has emerged in Oklahoma, where 10 rigs were added between 13 May and 2 September to bring the statewide total to 66. The increase has centered on the SCOOP (South Central Oklahoma Oil Province) and STACK (Sooner Trend, Anadarko [Basin], Canadian [County], and Kingfisher [County]) plays.
On the US natural gas side, the 88 rigs operating at the beginning of September reflected little change since spring. However, a shift in deployment had added six rigs to the Marcellus since 5 August and four rigs to the Utica since 20 May. The total number of rigs operating in the two basins were 27 and 14, respectively.
High-Grading Portfolios
“Companies are high-grading within their portfolios, which leads to an overall high-grading within the domestic system in the Lower 48,” said Reed Olmstead, director of commercial plays and basins at IHS Markit. “So that’s why we see operators dropping rigs out of the worst parts of their acreage, and that leads to a natural contraction of where activity is happening. Operators are looking to focus their money on areas that can generate economic returns at depressed oil prices, and the Permian keeps rising to the top when you look at cost and performance.”
The attractions of the Permian Basin are high-quality rock with significant stacked play opportunities, well-developed infrastructure in many areas, and the fact that the industry has a wealth of experience in the basin.
The most active driller is Pioneer Natural Resources, which is adding a 17th rig to its Permian operations. Others with high activity levels include Concho Resources, ExxonMobil’s XTO unit, and Parsley Energy, while Anadarko, Chevron, Cimarex Energy, Apache, EOG, and Occidental are among the companies with substantial current activity and/or high production.
Permian Resurgence
For a basin that has produced oil since 1920, the Permian has seen a remarkable resurgence. In its core Central Basin platform (CBP), the location of most of its conventional fields, production in 2007 stood at a nearly 6-decade low of less than 800,000 B/D. Since then, production has grown to 2 million B/D, a level not seen since the early 1970s, with a shift toward horizontal drilling since 2011 driving most of the increase.
In the Midland Basin, adjacent to the CBP, the Spraberry and Wolfcamp plays have generated an increase of approximately 850,000 BOE/D since 2009, according to data from IHS. Initial growth primarily reflected vertical well activity, but horizontal drilling has taken over in the last 4 years.
The surging production has made the Permian the only major US oil shale play to experience growth since crude prices began to fall, with US Energy Information Administration data showing an almost 20% rise in basin output since the start of last year.
Long-Term Production Growth
Scott Sheffield, chairman and chief executive officer (CEO) of Pioneer, told a plenary session audience at the SPE-cosponsored Unconventional Resources Technology Conference in August that the Permian will drive long-term US oil production growth. He forecast that the basin’s production will increase by an average of 300,000 B/D annually over the next 10 years and reach 5 million B/D by 2025.
The Permian Basin is now in direct competition with Saudi Arabia, Sheffield said, noting the basin has produced 35 billion BOE over its commercial life and has an additional 150 billion BOE of recoverable reserves that can be produced as the Midland and Delaware basin plays expand to their potential.
Sheffield said that Pioneer expects to achieve a 30% annual production growth in the Permian and that the company’s Midland Basin horizontal drilling prospects can break even at an average price of USD 25/bbl—which he noted was the price needed to earn a 10% return on the present value of investment.
The opportunities present in the Permian have spurred a rash of acquisitions and land deals, including EOG’s September announcement that it would purchase privately held Yates Petroleum for USD 2.5 billion. The additional Permian acreage would complement EOG’s current acreage there as the company shifts emphasis away from the more expensive Eagle Ford Shale. With the acquisition, EOG Chairman and CEO Bill Thomas said, “We’ll be able to grow oil [production] with less capital and more efficiently than we do now.”
The news followed Concho’s mid-August announcement that it would buy 40,000 core Midland Basin acres from Reliance Energy for USD 1.6 billion.
Land Deals
Recent land deals have transacted at per-acre prices of USD 58,000 in the Midland Basin and USD 27,000 in the more remote Delaware Basin, although one independent reportedly paid USD 150,000 per acre to acquire some Delaware Basin holdings.
Acreage swaps have also become commonplace, as land is a currency available regardless of commodity prices.
Bruce Palfreyman, general manager of the Permian asset at Shell, discussed swaps in the Delaware Basin at a recent presentation on the company’s unconventional resources business. “There is going to be continued consolidation across the basin in terms of people putting acreage together,” he said. “Everybody knows the value enhancement of long laterals, so you’re going to see lots more trading and swaps as we go forward from smaller to larger units, where they can lay out their development programs with as long a lateral as they can execute.”
Shell holds a net 300,000 acres in the Delaware Basin through a 50/50 joint venture to develop an area of mutual interest with Anadarko. Assets include 400 Shell-operated wells and more than 5,000 possible well locations. “In the current environment, we’re ready to move a few things into development, and that’s going to be our focus going forward,” Palfreyman said.
Overall, Delaware Basin operators have been shifting from delineation to optimization, which is reflected in longer laterals and higher proppant loading.
According to Jeanie Oudin, a senior research manager at Wood Mackenzie, “The Midland and Delaware basins hold the largest number of undrilled, low-cost tight oil locations in the Lower 48. No other region comes close.”
Apache’s Big Discovery
One company that has been patiently drilling the Delaware is Apache, which announced a major discovery on 7 September.
The Alpine High discovery, primarily in Reeves County, Texas, in the southern part of the basin, holds an estimated resource in place of 75 Tcf of gas and 3 billion bbl of oil in the Barnett and Woodford formations. Apache has also confirmed oil-bearing potential in the Pennsylvanian, Wolfcamp, and Bone Springs formations, company CEO and President John J. Christmann IV said. He called Alpine High “a world-class resource play.”
The discovery followed a meticulous 18-month process of assembling a position of 307,000 net contiguous acres among 352,000 gross acres and drilling 19 wells, nine of which were on production when the discovery was announced. To accelerate delineation and development at Alpine High, Apache boosted current capital spending by USD 200 million. The new play represents more than 25% of the company’s 2016 capital budget.
SCOOP and STACK Plays
Interest has also been building in Oklahoma. Continental Resources, a leading operator and the largest acreage holder in the Bakken Shale of North Dakota and Montana, has shifted significant attention to the SCOOP play, which represented 29% of company production at the end of last year.
“When you look at their presentations and have conversations with them, they’re much more focused on Oklahoma than they had been, say, 2 or 3 years ago,” said IHS’ Olmstead. “When you look at where their growth story is and where they feel their best returns are, it’s the SCOOP.”
Continental had significantly delineated various SCOOP discoveries before oil prices fell and thus has been able to move quickly into development drilling. Marathon Oil and Newfield Exploration are also major operators in the SCOOP. Some smaller companies active in the play hope to be able to prove up acreage to sell to the larger companies, Olmstead said.
In the STACK play, Devon Energy has a strong legacy position that it enhanced early this year with the USD 1.9-billion acquisition of privately held Felix Energy, which held key prospects in the Anadarko Basin.
Similarly, Marathon is bolstering its presence in the Anadarko with the USD 888-million purchase of privately held PayRock Energy Holdings, which was due to close by the end of the third quarter. Newfield, Husky Ventures, Cimarex, and Chaparral Energy are other major STACK play operators.
At least some operators have turned toward the SCOOP and STACK plays, Olmstead said, because “they’re at a point in their portfolio where they need another asset—whether it’s because they are running out of inventory in other assets (or) they don’t like the economics and think that despite the risks the economics here are worth it.”
Marcellus and Utica
In natural gas activity, the Marcellus and Utica plays have lately attracted additional rigs. “We’re very bullish on those plays,” Olmstead said.
Similar to Continental’s refocus from the Bakken to the SCOOP play, Southwestern Energy curtailed gas drilling in the Fayetteville Shale to concentrate “on the better part of their portfolio, the Marcellus acreage,” Olmstead said. The best near-term opportunities, he believes, lie in the northeastern Pennsylvania dry gas window.
“We’ve seen some very strong wells out of the Utica,” Olmstead continued. “EQT and a couple of other companies have had some amazing results. The question is really just the repeatability.”
The Shape of Things To Come
Current trends suggest that the geographic footprint of the US shale oil industry will be more centered on the Permian Basin when drilling activity recovers than it was before oil prices collapsed. The case is plausible, but there are some caveats when projecting to a full recovery environment.
Analyst Richard Zeits, who covers oil, gas, and commodities on the website Seeking Alpha, believes that Pioneer’s projection for 2025 industry production in the Permian is achievable and possibly conservative. Nonetheless, he notes some hurdles to be scaled as a recovery builds.
- Additions to processing, storage, and takeaway capacity and particularly the time and expense to develop processing capability for liquid-rich natural gas.
- The need to spread drilling to less-productive acreage.
- Eventual cost inflation in the supply chain.
Zeits emphasizes shale oil’s broadly distributed US production base that he believes can again come to the fore in a full recovery. “The industry will likely continue to rely on several prolific basins, most of which will contribute significantly to production growth in an upcycle,” he said.
However, it appears safe to say that while the Permian Basin did not lead the shale oil revolution, it will lead the US shale oil industry into the next recovery when it happens. And the same can be said of the Marcellus for shale gas.