HOUSTON—Three top E&P executives highlighted development plans in three different plays—the Eagle Ford, the Stack and the Bakken—at Hart Energy’s recent DUG Executive conference.

“We continue to focus on the western part of the Eagle Ford, where we have 487,000 gross/285,000 net acres,” said Tony Sanchez, CEO of Sanchez Energy Corp. The concentrated acreage position translates into over 15 years of drilling inventory, he said, and “we’re really pushing the scale that we’re using to drive a manufacturing concept.”

After spending more than $100 million on its Maverick position last year, Sanchez Energy plans on focusing its 2018 capex on its Catarina and recently acquired Comanche properties in the Eagle Ford. The company has a $445 million budget that provides for 180 gross wells. The budget, down from $550 million last year, keeps spending within cash flow, assuming benchmarks of $55/bbl and $3.00/mcf.

Production by Sanchez was running at 82,000 barrels of oil equivalent per day (boe/d) in the fourth quarter of last year. From an average of 70,320 boe/d last year, Sanchez expects to grow production to 90,000 boe/d this year and from there further grow “with an expectation that we’ll top 100,000 boe/d in 2020 with our existing asset base. And that’s while keeping our $445 million capital budget flat.”

The roughly 400,000 gross acres in Comanche and, in particular, Catarina, are largely contiguous, allowing long lateral wells to be drilled up to or exceeding 10,000 ft, with the average lateral length in 2018 expected to approach 7,700 ft. Wells are completed with 40-45 stages and cost about $4.6 million, with an estimated ultimate recovery (EUR) of 936,000 boe on a three-stream basis.

A focus has also been on “direct sourcing” the inputs needed for drilling, whether its completion crews, sand, chemicals, fuel, etc., said Sanchez. “In order to do that, you need to effectively turn your company into what is a logistics company,” he observed. “That’s what enables you to drive costs down, and to maintain that lower cost through the cycle.”

The “really good rock” in the area has contributed to some “outstanding well results,” said Sanchez. “It’s common now for us to get wells that, from an oil perspective alone, are coming in at anywhere from 800-1,200 bbl/d regularly. It really drives margins.”

With the uplift in West Texas Intermediate (WTI) oil prices to $60/bbl and higher, and realized prices for Sanchez being based more closely to Louisiana Light Sweet (LLS), the company’s EBITDA per barrel margin for Sanchez expanded to “just under $18/bbl” in the fourth quarter, according to Sanchez.

In the Comanche area, internal rates of return (IRR) at the wellhead exceed 100%, according to Sanchez, based on three-stream EURs of approaching 1 MMboe and costs of $4.2 million to get wells on-line. If an area can’t compete for “meaningful” capital within a 3-year to 5-year timeframe, the process of high-grading the asset base means the area may be sold to allow for more drilling or debt reduction, he said.

Alta Mesa Resources LLC has drilled over 250 horizontal wells in the Stack play over the last five years. The company, formerly known as Silver Run Acquisition II, is a recently-formed E&P resulting from the combination of core upstream assets of Alta Mesa Holdings LP with the gas processing assets of Kingfisher Midstream LLC. Its stock recently began trading on the NASDAQ under the symbol “AMR.”

Hal Chappelle, president and CEO of Alta Mesa, said plans called for the company to grow from 4 to 6 rigs to about 10 to 12 rigs. The company’s strong balance sheet would enable it to outspend cash flow for a couple of years, in which Alta Mesa could continue to grow production and build reserves. Finding and development (F&D) costs have been “below $10/bbl,” with lease operating costs “below $5/bbl.”

Now in “development mode,” Alta Mesa is drilling about 75% of its wells on multi-well pads, according to Chappelle. The company’s production team has experience with wells that have now been producing for five years, he noted, and its completion team is currently running four frac spreads. “Moving into this multi-well pad development on our highly contiguous acreage is a competitive edge for us,” he said.

Related articles:

Chappelle pointed to a five-year compound annual growth rate (CAGR) of production through 2017 of over 80%. He also showed a slide indicating that, even as Alta Mesa made up only about 25% of wells in Kingfisher County, the company’s wells accounted for 27% of top quartile wells after six months, growing to 32% after 12 months and 44% after 24 months.

“We think this is an indication of the strength of our resource and the way we’re producing our wells.”

As measured by its type curves, probably 57% of the oil is produced by Alta Mesa wells occurs in the first five years, according to Chappelle, but the remaining reserves are “very valuable.” As a result, he said, a “concerted effort” is made by the artificial lift optimization team to find a “fit-for-purpose solution.”

Returns are “fantastic” in both of its key areas—the Williston and the Delaware basins—according to Taylor Reid, president and COO of Oasis Petroleum Inc. In the Williston, Oasis will do “nothing but full field development,” with all wells having high-intensity completions, he said, while the Delaware will be focused mainly on holding acreage.

In terms of rig activity, the Delaware will run a single rig, drilling 12 to 16 wells and completing 6 to 8 wells in 2018. In the Williston, plans call for five rigs to drill 100-120 wells, but also include non-core assets sales of $500 million, with proceeds to be applied to the Delaware. Oasis forecasts exit-2017 to exit-2018 growth in overall production of over 20%, while spending within cash flow.

In the Williston, F&D costs have come down very significantly, to “under $8/bbl” from $13/bbl to $14/bbl three years ago,” said Reid. This reflected an over 25% decrease over three years in well costs, which he put currently at $7.5 million for a 10 million lb frack, slickwater well. Oasis was seeing outperformance v. type curves on the part of core acreage wells, both in and outside Wild Basin, he said.

On the midstream side, Oasis is building an additional gas processing plant, which is due to come online by year-end with a capacity of 200 mm cubic feet per day. “This turned out to be a great advantage for us. The infrastructure is getting super tight in the basin,” he said. In addition, in terms of third-party opportunities, “a lot of guys are seeking a home for their gas right now.”

In the Delaware, Oasis’ 20,000 net acres is all considered core acreage, and its contiguous nature sets it up mainly for wells with two-mile laterals. Wells drilled nearby by third parties are outperforming a 1.2 MMboe type curve, according to Reid, and typically have an oil cut of over 80%. Oasis estimates it has “a little over 500 net locations.”

Chris Sheehan can be reached at csheehan@hartenergy.com.