September 2015

Regional report: Permian Basin

Memo to bulls-in-waiting: If your recovery models are built around operators in the Permian basin choking down the spigot, now would be a good time to recalibrate.
Jim Redden / Contributing Editor
One of the four horizontal and five vertical rigs that Encana is running on its recently acquired Midland basin leasehold. Photo: Gaylon Wampler for Encana (left). Aerial view of the Barker Trust No. 1 vertical well. Photo: Patriot Energy Inc. (center). Apache is operating 10 rigs in the Permian basin, including this unit drilling on the McElroy unit in Crane, Texas. Photo: Apache Corp.
One of the four horizontal and five vertical rigs that Encana is running on its recently acquired Midland basin leasehold. Photo: Gaylon Wampler for Encana (left). Aerial view of the Barker Trust No. 1 vertical well. Photo: Patriot Energy Inc. (center). Apache is operating 10 rigs in the Permian basin, including this unit drilling on the McElroy unit in Crane, Texas. Photo: Apache Corp.

Even as the release of second-quarter earnings was greeted with oil price futures at a more than six-year low, Permian basin legacy players and newcomers alike, for the most part, say they have no intention of putting the brakes on production, at least in the near term. In fact, while the outlook for overall activity bears no resemblance to the optimism writ large of 2014, “down” or “flat” were not in the general lexicon of quarterly conference calls, when it came to discussing 2015 production guidance for this enduring geological hodgepodge, spreading some 75,000 mi2 across West Texas and southeastern New Mexico. A sampling:

Occidental Petroleum, thanks in no small part to an aggressive CO2 enhanced oil recovery (EOR) program, saw a 50% year-over-year increase in production, which it expects to climb still further, to 117,000 boed by year’s end.

Chevron’s Permian basin production has remained on an upward trajectory since 2012 and will continue in that direction this year and beyond, with its 2.2-million-acre leasehold expected to be delivering at least 250,000 boed by 2020.

Diamondback Energy has increased its production guidance twice this year and now says it will be pumping at least 32,000 boed by year-end, up from its original 29,000-boed projection.

Encana, in just its first year of operations in the Permian basin, plans to average 50,000 boed by year’s end, compared to around 40,000 boed delivered during first-half 2015.

Cimarex Energy, fresh off a record second quarter, said it expects to exit 2015 with at least 13% higher year-over-year production.

Pioneer Natural Resources is increasing full-year production in its seemingly ageless Sprayberry/Wolfcamp asset by as much as 24%.

Oil production is expected to increase in September, while gas will decline.  Source: U.S. Energy Information Administration (EIA)
Fig. 1. Oil production is expected to increase in September, while gas will decline. Source: U.S. Energy Information Administration (EIA)

These are, but a few, of the scores of Permian basin operators that point to comparably higher margins, especially from seemingly inexhaustible conventional fields, as sufficient justification for keeping pumpjacks running full bore. The latest data available from the Texas Railroad Commission (RRC) have the three sub-basins of the greater Permian eclipsing the 2014 daily rate by more than 38,000 bopd. According to the state’s chief regulator, the Texas portion of the basin was producing 1.278 MMbopd between January and May, compared to a 2014 average of 1.239 MMbopd, with gas production increasing to 4,225 MMcfd, compared to 4,157 MMcfd at year-end 2014. The best guesstimate by the U.S. Energy Information Administration (EIA) has cumulative Permian basin production jumping to 1.8 MMbopd by December. In the near-term, the EIA estimates that shale production, alone, will increase 8,000 bopd between August and September (Fig. 1), while month-over-month gas production is projected to drop by 9 MMcfd.

Moreover, as reflected in recent acquisitions by Exxon Mobil, Noble Energy and WPX Energy, even with distressingly low commodity prices, the world-class reserves encased within multiple, and largely well understood, targets, with readily accessible takeaway capacity, are too good to ignore.

On Aug. 7, Exxon Mobil subsidiary XTO Energy acquired, for an undisclosed price, the horizontal drilling rights to an additional 48,000 acres in the fairway of the Midland sub-basin, adjacent to its existing leasehold in Martin and Midland counties. XTO now holds 135,000 net acres, where it is operating 11 horizontal and four vertical rigs, with net production of 115,000 boed. “We are encouraged by the horizontal well productivity and cost reductions we have achieved to date,” XTO president Randy Cleveland said in a statement. “We expect to drive continued improvements in productivity and cost, as we develop our substantial inventory of wells across the multiple, stacked pays.”

Noble completed its $2.1-billion acquisition of Rosetta Resources on July 21, giving it access to 46,000 net acres in the Delaware sub-basin and 10,000 acres in the Midland basin. The purchase also includes 50,000 acres in the Eagle Ford shale.

On Aug. 18, WPX Energy finalized its $2.35-billion acquisition of privately held RKI Exploration & Production, and with it, 92,000 net acres in the multi-zone Delaware basin. The newly acquired leasehold is producing approximately 22,000 boed, largely from stacked-pay Wolfcamp, Bone Springs, Avalon and Delaware sands.

Just prior to the WPX acquisition, former RKI V.P. Timothy Haddican, was named CEO of start-up Red Bluff Resources Holdings, which began operations in August with the $300-million backing of the Pine Brook investment firm. The new company will focus on prospects in the Permian basin and Mid-Continent areas.


Though more than 300 rigs have been furloughed since the overheated peak that marked most of 2014, the active rig count throughout the Permian basin has been rising, albeit modestly, since July 14. The week of Aug. 16 saw 255 rigs making hole, including 49 operating across the border in the New Mexico swath of the Delaware basin, according to Baker Hughes data. While the Aug. 16 count was up one from the week prior, it is far below the 558 active rigs tallied at the same time last year.

A drilling rig at work on Kinder Morgan’s SACROC field in Scurry County, Texas, one of four CO2 and waterflood EOR projects that the company is operating in the Permian basin. Photo: Kinder Morgan.
Fig. 2. A drilling rig at work on Kinder Morgan’s SACROC field in Scurry County, Texas, one of four CO2 and waterflood EOR projects that the company is operating in the Permian basin. Photo: Kinder Morgan.

Drilling permits, likewise, are on pace to fall well short of the 10,966 authorizations that the RRC issued in 2014 for the three districts (8, 8A and 7C) comprising the state’s portion of the Permian basin. Between Jan. 1 and Aug. 21, the RRC issued 2,911 permits for new oil and gas wells, compared to 5,222 authorizations for the like period last year.

Not surprisingly, given today’s economic climate, the capacity to wrestle lower-cost reserves from graybeard fields provides added incentive to keep production climbing. A case-in-point is the 26,000-acre Yates field of Pecos County, Texas, which began production during the Roaring Twenties. As part of its four-field EOR program (Fig. 2), leading CO2 marketer Kinder Morgan plans to produce an estimated 19,216 bopd this year from the field, which was discovered in 1926, compared to an average of 19,531 bopd last year. Yates joins the SACROC, Katz and Goldsmith EOR projects, which Kinder Morgan expects to add a cumulative 59,665 bopd this year, up from the 57,584 bopd that the quartet delivered in 2014.

Elsewhere, operators say deep cuts in total well costs, high-intensity completions and enhanced efficiencies across-the-board are contributing to higher margins in typically stacked unconventional plays. Early this year, legacy player Pioneer Natural Resources completed the wholesale transition to horizontal drilling in its 825,000-acre Sprayberry/Wolfcamp play, which began producing from vertical wells more than 70 years ago in the Midland basin. CEO Scott Sheffield said that between the increased estimated ultimate recoveries (EUR), high-quality rock, cost reductions and efficiencies, the operator is seeing returns “averaging 50% to 60% at current strip commodity prices.”

While remaining steadfast in its drill-but-not-complete, strategy until prices recover, EOG Resources says alluring returns differentiate the Permian from its unconventional counterparts. The Houston independent pointed to its Delaware basin Leonard shale play, which it says delivers 80% and 50% after-tax rates of return (ATRR) at oil prices of $65/bbl and $55/bbl, respectively, compared to 35% when crude was selling for $95/bbl. “Our goal this year is to remain laser-focused on improving returns,” chairman and CEO Bill Thomas told analysts in early August. “At the beginning of the year, we noted that our after-tax rate of return at $65 oil were better than at $95 oil three years ago. We are pleased to report that we have further improved these well economics, even as oil prices have declined. Through improved well productivity and lower cost, our key oil plays now are in a 30% after-tax rate of return with a flat $50 oil price.”


Conventional wisdom holds that when prices collapse, protecting some semblance of reasonable cash flow means more funds being diverted into drilling shallower conventional wells. This trend would bode especially well for the vertically mature Midland basin, home of the Yates and other, still-producing ancient fields. Interestingly, however, as a percentage of the total new well permits issued thus far this year, only 32.8% were for vertical profiles, compared to 56.6% during the like period of 2014, when oil was still in the $90/bbl range.

One of the 957 vertical wells permitted as of Aug. 21 is Patriot Energy’s Barker Trust No. 1, which spudded in early August to kick off a planned, seven-well, conventional drilling program in the eastern shelf of the upper Permian basin. The inaugural well is part of the Sandhill-7 prospect, which encompasses 8,500 net acres under lease in Kent and Knox counties. Dallas-based Patriot Energy entered the emerging play through a “substantial non-operated position” with Atoka Operating. The initial well is programmed for a 5,000-ft TD, where its primary objective is the widely explored Tannehill sand. The remaining six wells will target divergent formations, such as the Mississippian, Ellenburger, Strawn and Frye sands, as well as the Bend Conglomerate.

Patriot president and founder Michael Miller said that the shallow prospects offer low risk and are economic at $40/bbl oil. “The Sandhill-7 is a perfect example of a scaled, multi-well prospect, involving shallow vertical wells, that make economic sense, even below today’s prices,” he said.

 Encana, for another, plans to continue running four horizontal and five vertical rigs in its 140,000-net-acre Midland basin leasehold that came with its $7.1-billion acquisition of Athlon Energy in November 2014. During the quarter, the Canadian operator drilled 23 horizontal and 29 net vertical wells. “Production growth will accelerate in the second half of 2015, starting with 53 wells coming on production in third-quarter 2015,” said Executive V.P. and COO Michael McAllister. “We had introduced simultaneous drilling and completion operations on our horizontal pads. This has reduced our spud-to-initial-production times by approximately 30 days. This lowers cost, and speeds the time to positive cash flow, therefore improving returns.”


Given market volatility, today’s activity levels and near-term guidance could be rendered obsolete tomorrow. And, while the Permian basin, for now at least, is the exception, where production is concerned, a survey of select players suggest they are firmly in lockstep when it comes to reducing total well costs.

Occidental’s well-established Permian basin infrastructure includes a wide distribution network for CO2, which the operator describes as its most profitable business. Source: Occidental Petroleum Co.
Fig. 3. Occidental’s well-established Permian basin infrastructure includes a wide distribution network for CO2, which the operator describes as its most profitable business. Source: Occidental Petroleum Co.

To meet its ambitious production target, Occidental plans to drill and complete a minimum of 100 horizontal wells and operate 12 rigs for the remainder of the year. In second-quarter 2015, Oxy put 71 wells online, including 53 horizontals, and estimates 60% of its Permian basin production is derived from an aggressive CO2 EOR program, Fig. 3.

The operator’s drive for cost efficiencies was reflected in a recent Delaware basin well completed in the Wolfcamp A bench, where drilling time was cut in half with a corresponding 40% reduction in costs. Aside from service company discounts, Oxy Oil and Gas president Vicki Hollub said technology enhancements were largely responsible for the well coming in at $6.8 million down from the $10.9 million required for a comparable 2014 well. “Our improvements were driven by adopting and adapting oilfield technology, including an advanced mud system to eliminate casing across the salt interval in the wellbore. Oxy Drilling Dynamics is a proprietary system we have developed also, that expands upon mechanical specific energy concepts to improve rates of penetration. This improvement in drilling efficiency is a structural change to our business that will sharply lower our cost, irrespective of pricing concessions from our suppliers,” she said.

Apache operated 10 rigs during the second quarter, down five from the preceding three months, but still managed to increase average production by 9% to 172,100 boed. The Houston-based independent, which holds more than 3.2-million gross acres, drilled 22 gross horizontal wells during the quarter, but reduced completions by 40% compared to the first quarter. Apache says 70 horizontal and seven vertical wells remained drilled, but uncompleted at the end of the second quarter.

Apache CEO and president John Christmann said the company’s Delaware basin wells averaged $8 million in November 2014, but “today we are drilling those wells in the mid-to-upper $5 million range, and our target is to get down closer to $5 million, which would represent an approximate 35% reduction from Nov. 20.”

Chevron plans to average 22 rigs for the remainder of the year, split nearly evenly between its play-leading acreage in the Midland and Delaware basins, where it remains on-track to drill 325 gross wells. In a June investor presentation, Chevron reported shale and conventional production increasing to 46,000 boed in its Midland holdings and 57,000 boed in the Delaware basin, while reducing drilling and completion costs by 20% and 28%, respectively.

Cimarex says it hit a production milestone in the first half of the year, despite putting three fewer net wells onstream, compared to the first six months of 2014. The Denver-based independent, which holds 235,000 net acres in the Delaware basin, including some 100,000 acres in the Culbertson County, Texas joint development agreement (JDA) with Chevron, put 48 net wells on production in the first half of the year, down from 51 during the same period last year.

Cimarex focuses primarily on the Second Bone Springs and the multi-bench Wolfcamp, where it completed five and 20 wells, respectively, during the most recent quarter. As of now, Cimarex has 11 Wolfcamp D producing wells completed with 10,000-ft laterals, averaging 30-day peak IP rates of 2,255 boed and with total year-over-year well costs some 20% less, the company said. More recently, Cimarex completed a 7,000-ft lateral in the Bone Spring sands with a 30-day IP of 2,753 boed.

After averaging 18 rigs in 2014, Denver-based Cimarex is running three rigs and “plans to add more” later this year, says V.P. of Exploration John Lambuth. Of the aggregate $190 million invested in the second quarter, Cimarex said 66% went into its Permian basin operations.

Pioneer Natural Resources, flush off the $2.15-billion liquidation of its Eagle Ford midstream asset, as of August, was operating 10 rigs in its 600,000-acre northern Sprayberry/Wolfcamp leasehold, where it still plans to add two rigs per month, according to CEO Sheffield. The Fort Worth, Texas, independent placed 28 horizontal wells on production during the second quarter, mostly targeting the Wolfcamp B and Lower Spraberry Shale intervals. In addition, five Lower Spraberry wells went onstream, with preliminary production results tracking average EUR of 1 MMboe and average 24-hr peak IP of approximately 1,900 boed, the company says.

Driven by its Bone Springs asset, Devon Energy recorded net production of 64,000 boed in the second quarter, up 40% from the like period of 2014. Devon holds 585,000 net risked acres in the Permian basin, where it drilled 16 Bone Springs wells in the second quarter with 30-day IP of 1,400 boed. The Oklahoma City, Okla., operator says it has reduced total well costs more than 30% since the end of last year.

Devon is focusing on down-spacing pilots, where it is testing eight wells/section in the lower Second Bone Springs, as well as evaluating completion strategies. “We probably have about seven or eight different designs across the Delaware basin, and those are all customized based on the portion of the basin and the type of rocks we have,” says president and CEO David A. Hager. “In 2016, we’re going to come out and have a full development plan for all horizons that we think will increase the returns of these projects, even greater than what we have done just with our pad work, mostly centered in the Second Bone Springs.”

EOG Resources, while maintaining its flat production strategy, plans to complete around 80 wells this year, 35 each in its Bone Springs and Wolfcamp holdings, and 10 in the Leonard shale. In the second quarter, EOG introduced high-density completions to its Bone Springs play, which it plans to replicate in the Wolfcamp in the third quarter. “The plays in the Delaware basin are proving to be very good examples of how EOG is repositioning itself to generate strong returns in this period of low commodity prices,” says Executive V.P. of Exploration and Production Bill Helms. “We have made improvements to productivity, while significantly lowering completed well costs.”

At $40/bbl oil, pure play operator Diamondback Energy says it is generating nearly 70% returns from the Lower Sprayberry in its Spanish Trail play, where it plans to add a fifth rig in the third quarter. In the first quarter, the Midland-based operator augmented its 85,200-net-acre leasehold with the acquisition of 12,000 acres in the northern Midland basin. Diamondback, which transitioned to horizontal development in 2012, plans to initiate drilling on the newly acquired acreage later this year or in early 2016.

Concho Resources averaged 18 rigs during the second quarter, down from the 30 making hole in the first quarter within its 605,000 net acres spread throughout Texas and New Mexico. Concho drilled and completed 91 and 137 gross wells, respectively, during the quarter. Production from its Delaware basin horizontals averaged 81,600 boed, up 66% year-over-year and 18% higher than first-quarter 2015. Of those, 58 targeted the Bone Springs, while the remainder produced from the Wolfcamp and Avalon shales.

To the east, Concho put 21 horizontal wells online in the Midland basin, where it says average drilling days per well decreased 25% year-over-year. The new producers averaged peak 30-day and 24-hr rates of 758 boed and 996 boed, respectively. An additional 17 new horizontal wells were hooked up on the New Mexico shelf, delivering average peak 30-day and 24-hr rates of 331 boed and 477 boed, respectively.

For the remainder of the year, BHP Billiton plans to operate two rigs and a frac spread on its 74,000-net-acre position in the Texas segment of the Delaware basin, where the operator targets the Wolfcamp with a production target of 150,000 boed, says Robert J. Manelis, general manager of the Permian Production Unit. “We are drilling and completing with a focused priority of meeting lease obligations; completions will be flexed according to market conditions,” he said.


Meanwhile, separate projects by Magellan Midstream Partners, Plains All American Pipeline and Sunoco Logistics Partners have, over the year, collectively added more than 750,000 boed of takeaway capacity for Permian basin crude, for delivery to Gulf Coast refineries, according to Bloomberg. The added capacity allows producers to now sell at a slight premium, relative to the West Texas Intermediate (WTI) benchmark, effectively helping to alleviate a bottleneck and corresponding discounts.

Elsewhere, open season ended Sept. 4 on Energy Transfer Partners’ Delaware Basin Crude Gathering Pipeline network with a planned capacity of 120,000 bpd, comprising three gathering systems and a cumulative 130 mi of pipeline. The interstate line is expected to be in service in the first half of 2016, with delivery points in Loving County, Texas, and Lea County, N.M.

However, Energy Transfer Partners is encountering pushback toward its plans to lay a 143-mi pipeline to deliver as much as 1.4 Bcfd of West Texas gas, south of the border, into Mexico. A coalition of landowners and environmentalists objects to the 42-in. Trans-Pecos pipeline, as the route would traverse the Big Bend wilderness area. The issue has since been referred to the U.S. Federal Energy Regulatory Commission (FERC). wo-box_blue.gif 

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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