Payback time, as LLS pricing lifts netbacks

The Eagle Ford is enjoying a comeuppance, of sorts. Once left to pick up Permian basin leftovers, the unconventional elder has emerged as a veritable hedge against the bottleneck-induced price differentials of its high-flying neighbor to the immediate west.

A Chesapeake-operated rig stands out amid the distinctive South Texas terrain. Image: Chesapeake Energy Corp.

“If differentials stay depressed or widen further, we may evaluate shifting capital away from the (Permian) Delaware basin and into the Eagle Ford shale, in order to avoid bringing on a substantial amount of production into a depressed local price environment,” Carrizo Oil & Gas Inc. President and CEO S.P. Johnson warned on May 8. If it follows through, Carrizo would join Houston’s EP Energy Corp., which rerouted the next round of its drilling joint venture from the Permian to the Eagle Ford, which stretches across South Texas and into Mexico.

The distinctive oil, wet gas and dry gas windows of the Upper and Lower Eagle Ford, often developed in concert with the overlying Austin Chalk, are expected to produce 1.396 MMbopd and 6.942 Bcfgd in July (Fig. 1), according to the U.S. Energy Information Administration (EIA). While delivering nearly 2 MMbopd and 3.757 Bcfgd less than the Permian basin, the capacity to readily access a prodigious domestic and export market allows for higher Louisiana Light Sweet (LLS)-based prices. “No North American basin compares with the Eagle Ford for low transportation cost and access to Gulf Coast pricing,” says Ezra Yacob, executive vice president of exploration and production for early mover EOG Resources, Inc.

Fig. 1. July oil and gas production is predicted to increase month-over-month by 43,000 bpd and 140 MMcfd, respectively. Source: U.S. Energy Information Administration (EIA).

While acknowledging  wells in the highly exploited western section under-perform compared to their eastern counterparts, EOG Resources says tightly concentrated acreage evens out the margins. “While the wells in our western acreage position have lower initial rates, the combination of less faulting and our contiguous acreage position allows for consistently longer laterals than in the East, which drives operational efficiencies. Therefore, the wells across our entire 520,000 net acres in the oil window are all equally competitive on a rate-of-return basis,” said Yacob.

All but 62,000 net acres of EOG’s leasehold is concentrated in the oil window, where first-quarter wells with 9,200-ft laterals averaged 30-day IP rates of 1,375 boed. By contrast, wells on the eastern fringe of the EOG position averaged IP-30 rates of 1,810 boed.

After completing 217 wells in 2017, EOG plans to up the ante this year with around 260 net wells on tap. The Houston company operated 11 rigs in the first quarter and expects to average nine rigs and seven completion spreads throughout 2018.

AGING EFFICIENTLY

The Eagle Ford averaged just over 80 active rigs in June, compared to the 84-rig average in June 2017, according to Baker Hughes. Meanwhile, the Texas Railroad Commission (RRC) approved 1,423 horizontal drilling permits for the three core districts (01, 02 and 04) between Jan. 1 and June 12, while 1,313 horizontal well authorizations were issued for the like period last year. The state’s chief regulator issued a cumulative 2,123 Eagle Ford drilling permits in 2017.

The more than 10 years of shale drilling and completion experience in the Eagle Ford helps reduce, to a degree, the relevance of the rig count as a measure of wellness. To point, according to the latest EIA drilling productivity index, each rig in the Eagle Ford during July is expected to deliver a U.S.-leading 1,503 bpd of new oil, up 33 bpd/rig from only a month earlier. By contrast, a Permian basin rig is estimated to be responsible for 620 bbl of oil, unchanged from June. “In the time we can drill one well in the Permian, we can drill over three wells in the Eagle Ford,” said Carrizo V.P. and COO Brad Fisher.

Fig. 2. The Atascosa in-basin sand mine began operation in February, at its current capacity of 1.5 million tons/yr. Image: Preferred Sands LLC.

Meanwhile, driven by the progression of high-density completions and high proppant loadings per capita, two in-basin frac sand mines are either in operation or planned for this year. “It was no accident that the Eagle Ford was one of the first markets we studied, when we first set out on our national localization strategy and have been essentially working on markets in order of frac sand demand expectations,” said T.J. Doyle, president and COO of Preferred Sands LLC of Radnor, Pa.

The company’s Atascosa sand mine began operating in February (Fig. 2), with capacity expected to double to 3 million tons/yr by August. Preferred joins Black Mountain Sand of Fort Worth, Texas, which also plans to open an Atascosa County mine before year-end.

EASTERN PIVOT

The more advanced shale acumen partly drove EP Energy’s April 27 decision to re-direct the next phase of its 1.5-yr-old Wolfcamp Drillco joint venture with Apollo Global Management from the Permian. “The Eagle Ford is a little bit more mature in terms of completion design, landing intervals and the knowledge there,” said President and CEO Russell E. Parker. “For us and our Drillco partner, we feel like the best choice right now was to place this particular part of the partnership, or this tranche, in the Eagle Ford.”

The two-phase tranche will initially include 34 wells, with drilling commencing in the second quarter. EP averaged two rigs in the first quarter, during which 24 wells were competed with production reaching 35,900 boed, a 17% quarter-over-quarter increase.

Fig. 3. An average 80 rigs, like this one drilling for ConocoPhillips, were making hole in the Eagle Ford during June. Image: ConocoPhillips.

EP beefed up its leasehold with the February closing of the $245-million acquisition of roughly 24,500 net producing and undeveloped acres in the LaSalle County fairway held by Carrizo Oil & Gas. Carrizo still holds 79,100 net acres, which yielded first-quarter post-divestiture production of 35,600 boed. While weighing a potential shift from the Permian, Carrizo plans a two to three-rig development program in the Eagle Ford, with the drilling of 56 to 61 net (60 to 65 gross) wells and the completion of 56 to 61 net (60 to 65 gross) wells.

For its part, ConocoPhillips welcomes the siphoning of resources to the west. “While everyone else has been banging away in the Permian—a lot of people left the Eagle Ford to do that—there’s just been less competition for goods and services in the Eagle Ford and better netbacks, because there’ve been less people trying to jam their barrels down the same takeaway capacity,” says Executive V.P. of Production, Drilling & Projects Al Hirshberg.

ConocoPhillips’ 210,000-net-acre Eagle Ford position produced an average 163,000 boed in the first quarter, compared to the combined 87,000 boed from its Bakken and Delaware basin leaseholds, Fig. 3.

Murphy Oil Corp, likewise, says less competition, for now, has kept a rein on inflation. “At the end of the day, the cost per foot of the 18 wells we drilled in the first quarter, versus what we had in 2017, is slightly lower,” said President and CEO Roger Jenkins.

Murphy plans to complete 45 wells in 2018, spread out among the four operating areas within a 122,538-net-acre leasehold.

Sanchez Energy Corp, for another, has laid out an aggressive multi-bench development program this year across the Catarina, Maverick and Comanche operating areas of its approximately 285,000-net-acre leasehold. Of the 153 and 197 gross wells to be drilled and completed, respectively, 122 gross (32 net) wells will be drilled and 166 gross (45 net) completed in the western Comanche assets acquired from Anadarko Petroleum Corp. in March 2017. 

First-quarter activity focused primarily on full-field development of the Catarina and Comanche assets, with the drilling of 49 gross (25.67 net) and completion of 73 gross (23.3 net) wells. Sanchez operated between six and eight rigs, and five frac spreads during the quarter.           

Elsewhere, Canada’s Baytex Energy Corp. credits the handy proximity to Gulf Coast markets for an operating netback of $32.48/boe—the company’s highest since 2014. First-quarter production from a contiguous 20,200 net acres in the Atascosa County oil window averaged 36,017 boed, down from 37,362 boed in the final quarter of 2017, which was attributed to completion timing. 

After participating in the drilling of 25 gross (6.9 net) wells in the first quarter, Baytex plans to run two to three rigs and one to two frac crews for the remainder of 2018. The company says the 2018 activity level, which will include up to six Austin Chalk wells, will mirror 2017, with around 30 wells put on production.

The Austin Chalk, likewise, remains on the immediate radar of fellow Calgary operator Encana Corp., which says around 40% of its 2018 program will be directed to the chalk. Two Austin Chalk wells completed in the first quarter averaged 30-day IP rates of 1,925 boed. “Because it overlies our Eagle Ford (holdings), the land is already held by Eagle Ford production, and where we’re drilling the wells is accessing facilities that were built for the Eagle Ford development,” says President and CEO Doug Suttles.

Encana ramped up activity in the first quarter with three rigs, but has since laid down one rig across its 43,200-net-acre leasehold, where it plans to drill and complete 45 to 50 wells.

Chesapeake Energy Corp. will maintain a four to five-rig program, with 2018 guidance calling for 150 wells to be turned in line. With 23 wells put onstream in the first quarter, production increased to 102,000 boed, compared to 96,000 boed in the first quarter of 2017. 

 Touting an enhanced completions strategy as “uplifting inventory” outside its Karnes County core, Marathon Oil Co. said 11 wells brought online in Atascosa County in the first quarter averaged 30-day IP rates of 1,615 boed. A cumulative 34 gross wells are online across the 150,000 net acres that Marathon controls at average 30-day IP of 1,759 boed.

 Marathon says the Eagle Ford assets generated “significant free cash flow,” thanks largely to LLS-based oil pricing $1.50/bbl higher than the West Texas Intermediate (WTI) benchmark.

Boasting the Eagle Ford’s second-largest leasehold (404,000 net acres), pure play operator WildHorse Resource Development Corp. plans to drill and complete between 100 and 110 wells this year. The private company brought 19 gross Eagle Ford and four gross Austin Chalk wells online in the first quarter, contributing to a 251% yearly increase in production to 40,400 boed from 11,500 boed during first-quarter 2017.

WildHorse also is investing between $65 million and $75 million in a proprietary in-field sand mine in Burleson County, expected to be in operation by the first quarter of 2019.

NEW FACES

With a number of once-entrenched players falling to the wayside, the newcomers setting up shop amid the mesquite of South Texas include start-up Magnolia Oil & Gas Corp., headed by former Occidental Petroleum chief Steve Chazen. The newly formed company acquired around 360,000 net acres from EnerVest, Ltd., in an approximately $2.66 billion deal. Acreage included in the transaction, which was expected to close late in the second quarter, is prospective for both the Eagle Ford and Austin Chalk.

Also in March, Venado Oil and Gas, LLC, and private equity firm KKR teamed up in a $765-million deal to snap up the Eagle Ford assets of Cabot Oil & Gas Corp. The acquisition includes 303 gross producing wells and 74,400 net acres in the oil window of Atascosa, Frio and LaSalle counties.

Perhaps one of the biggest prizes up for grabs is the estimated 300,000 first-mover acres held by BHP Billiton Ltd., which may be sold separately or lumped in the package comprising the company’s entire U.S. shale holdings. The BHP shale portfolio has reportedly attracted such heavy hitters as Shell, Chevron and BP.

BHP has operated the Eagle Ford asset under a 50/50 joint venture with Devon Energy Corp., which separately holds 65,000 net acres. Devon plans to bring 35 to 40 new wells online in the second quarter, with quarter-over-quarter production expected to increase around 30%, from 52,000 to 57,000 boed.

Again in March, Australia’s Sundance Energy Ltd. paid $102 million to acquire 10,200 acres controlled by Pioneer Natural Resources in the western section. Sundance wasted no time getting to work with two rigs and a frac spread at work in the second quarter. With control of 56,600 net acres, the pure play operator plans to drill 30 to 40 development wells this year. 

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.