Looking at U.S. plays in late 2015, Mark Whitley put the northern Delaware Basin at the top of his target list. At the time, southern Delaware activity was heating up; the northern Delaware, not as much yet.

After retiring from Range Resources Corp. in 2012 as senior vice president, a friend of 42 years—both worked at Shell Oil Co. in the 1970s—was working for Warburg Pincus LLC. Whitley joined the board of a Warburg-backed E&P focused on the Montney play in British Columbia. He joined two additional boards, while also advising Warburg in evaluating management teams and assets.

“I had thought about starting an E&P company,” he said, “but not just with any team.”

The team he wanted came together in early 2016 as four Range employees “decided they wanted to do something new.” Whitley, president and CEO, formed Fort Worth, Texas-based Chisholm Energy Holdings LLC with Mike Middlebrook, COO and formerly a Range vice president; Martin Emery, senior vice president of geosciences, and formerly vice president of geology; Andrew Tullis, vice president of engineering, and Brad Grandstaff, vice president of operations. Both were formerly directors of operations.

Also joining: Scott Herstein, vice president of business development, and with whom Whitley worked while at Quicksilver Resources Inc., and Aaron Gaydosik, CFO, who was CFO for Gulfport Energy Corp. Whitley had met him through Warburg.

Warburg made a $500-million commitment to the group, which closed on its platform acquisition this past May: acreage in Lea and Eddy counties, N.M. An edge in Chisholm’s plan is that some operators would rather not work on federal acreage, Whitley said. Most of what Chisholm acquired is federal. Some is state; the rest, private.

“This operating team largely came from Range. They’ve operated on federal leases in this area in New Mexico,” he said. (Range exited the Permian in 2014.) “The team here is familiar with the process and it is just that: It’s a process. You know going in it’s going to take six-plus months to get a permit and you just have to build that into your plan.”

The leasehold Chisholm acquired is HBP except for a couple of parcels. Production in the past was from deep, vertical wells tapping the Pennsylvanian-age Morrow and Atoka. For the most part, rights aren’t split. “We made a point of getting into an area where we could get the rights to all depths,” Whitley said.

While Range grew into a gas- and NGL-focused producer, Whitley likes the northern Delaware for the mix of commodities it offers. “You have the Bone Spring, which is basically oil-saturated sands, and at least a portion of the geologic section is overpressured. You have big wet-gas wells in the overpressured section that produce a lot of liquids.”

The Wolfcamp is, “by and large, a gas play.” In the early stage of development in southeastern New Mexico, the wells’ production has gotten bigger and bigger. They make a lot of condensate, so they’re rich-gas condensate wells and are in the overpressured section.”

Together, the plays include some 5,000 feet of stratigraphic section. “It has hydrocarbon throughout, and we’re a little bit agnostic as to whether it is oil or gas.”

The Avalon Shale is thin or isn’t present in Chisholm’s area. Main targets are the second and third Bone Spring, the upper Wolfcamp XYA and the middle Wolfcamp. D&C costs are making economic wells at $45 oil.

“The breakeven is more like $35 in the northern portion of the Delaware. Natural gas at $3—it works very well at that also.” While operators’ well results vary, “the important thing is they’re all significant,” he said. “There are high rates of return on these wells.”

Chisholm, which had spud its first well at press time, was expecting to add a second rig this summer and possibly a third in the fall, particularly testing the Wolfcamp. “The Wolfcamp is just beginning to have a life of its own, if you will.”

Some pieces of the D&C recipe remain unknown without more wells drilled. “A lot of people can condense everything down (in a play) to one particularly important thing or process that is the reason—the reason du jour, so to speak—why it works.

“Well, it’s many things. You have to be in the right target in these zones and have the fracture intensity. People talk about pounds per foot. That’s not the only thing that makes a good well. You can pump a lot of sand and still not make a good well, if you’re not in the right target.”

But fracture intensity is critical. Stages are getting shorter and shorter; the number of perf clusters per stage, more and more. “Now you’re ending up with these more intensely fractured wells. That’s really what makes a difference—assuming you’re in the right target of each of these benches.”

Whitley would like to take Chisholm to 30,000 net acres. “It will take time, perseverance and the right opportunities. There is an upper limit on the dollar amount per acre we’re willing to pay.”

Where Chisholm is locked in, forced pooling may result in additional acres. “So we have a three-pronged attack: leasehold acquisition and property acquisition through public offerings and forced pooling.”

Some other basins ranked well on Whitley’s short list, but “we are going to remain for the foreseeable future a New Mexico, Delaware Basin-focused company.”

Starting a U.S.-onshore-focused E&P, say, 20 years ago would have been much different. “The target list [of plays] today is so much bigger and there is a tremendous amount of money these private equity firms have. The target environment is so rich in the U.S.—and in Canada as well—because of the unconventionals.”

In addition, there are ready buyers when a portfolio company is ready to exit. Today, they include majors such as Exxon Mobil Corp.’s XTO Energy Inc. “Those types of deals did not occur in the 1990s. They didn’t really start until mid-2000.”

Several retired E&P executives, such as Mark Papa and Jim Hackett, are taking the special purpose acquisition company approach to building an E&P company. Whitley said it’s of interest to him, but “that’s not on our list right now.” With Warburg’s initial $500-million commitment, “we can go a long way with that.”

Eastern Eagle Ford

Michael Rozenfeld and most of the team at Houston-based Boomtown Oil LLC met while petroleum engineering students at the University of Texas at Austin. Rozenfeld, Sean Fitzgerald and Richard Wilde completed their undergraduate studies in 2006; Hakim Benhammou, in 2005.

Rozenfeld and Fitzgerald both went on to work for Shell and, later, Rosetta Resources Inc. in the Eagle Ford. Benhammou worked for Citation Oil & Gas Corp. and Linn Energy LLC, including in the Permian Basin. Wilde joined XTO after UT and worked in the Barnett and Niobrara.

A fifth team member, Angie Galvan, a paralegal, joined them at their first start-up. The sixth, Justin Martinez, had been an intern a few years back while a petroleum engineering student at the University of Houston. In addition to his reservoir-engineering work for Boomtown, he writes custom programs for the group.

“We’ve managed to create our own methods and processes that are the equivalent of what most large companies have, using Justin’s programming knowledge,” Rozenfeld said. “It’s rare to get someone who programs and has industry knowledge. It allows you to create a lot of specialized tools.”

Boomtown is the group’s third start-up. The last, South Texas Reservoir Alliance (STXRA), was just sold. “We were contract operating to pay our G&A, while we did deals with private equity and sold prospects.”

The group became familiar with Houston-based Juniper Capital Advisors LP while working on a property in Colorado. A Juniper partner had a water disposal company; STXRA was the first client. “The relationship went from there,” Rozenfeld said. “We liked all the principals, and they seemed to be similar to us in how they do things—very analytically driven.

“They’re not focused on just the financial side, but on the engineering and technical side. They have a lot of knowledge they’ve built internally and they’ve also built tools. They’re a small group, but they’re able to do a lot because of their internal capabilities.”

In partnership with Juniper, Boomtown’s first asset is 20,000 contiguous net acres in Lavaca and Dewitt counties, Texas, targeting the Eagle Ford, the upper Eagle Ford and the Austin Chalk. “We also look outside the Eagle Ford for acquisitions, but we feel that the best value is in the Eagle Ford vs. other plays right now.”

The block was put together by picking up leases other operators were letting expire during the downturn. “It’s all new leases, which is shocking for the Eagle Ford,” Rozenfeld said. “You would think there isn’t anywhere left to lease. But there are still a lot of acres that are available, if you know where to look.”

In the leasehold, the Eagle Ford is found at between 8,000 and 14,000 feet. Wells cost between $5- and $8 million, depending on lateral length and vertical depth.

Nearby, Penn Virginia Corp. reported a preliminary 24-hour IP of 2,511 barrels of oil equivalent (boe), 77% oil, from its Lager 3H in a slickwater test. The lateral is 8,000 feet; open stages, 40. Flowing casing pressure was 4,373 psi; the choke, 20/64. It estimated in early June that the 30-day IP would be between 1,800 and 1,900 boe/d. The gas is 1,400 British thermal units.

Rozenfeld said, “So you’re getting new wells out here that are 700,000 to 800,000 boe. It is basically the Permian Basin without all the failures. The Eagle Ford wells tend to have consistency in results—not a lot of variability.

“We’re getting Permian-style EURs, and the cost is a lot less because the infrastructure is already there—the hard work on that has already been done—and the price is right to lease.”

In addition, he said, EUR may improve further with longer laterals, “since the majority of the wells have lateral lengths that do not exceed 7,000 feet. If we put this acreage in the Permian Basin, people would pay $20,000 an acre for it because the EUR is equivalent on a lateral-normalized basis.

“The Eagle Ford has fallen out of favor with public companies due to the belief that the Permian has more prospective formations. However, many targets in the Permian are considered future upside. Most companies are only paying for the value of two to three proven zones.

“The Eagle Ford provides a superior value, if you are primarily focused on net present value as opposed to future reserve upside. We’re getting Permian EURs without having to pay the Permian price.”

Some well control in the Boomtown leasehold exists as a result of legacy, vertical development in the area along with 3-D seismic. “Much of our acreage is considered to be in the gas window of the Eagle Ford. It’s not dry gas; it’s retrograde condensate gas.”

When Rozenfeld and Fitzgerald were about to quit Rosetta in 2011, they talked to Benhammou and Wilde about joining them in a start-up. “They were very interested too. We felt very capable of doing it.”

Their idea is that much of the knowledge gained about developing unconventional resources has been while each had been working in them post-UT. On that timeline, both long-timers and newcomers have about as much experience, Rozenfeld said.

“We felt that we’re as much experts as anyone else in shale because we were around when it began. There’s no need to wait 30 years to start your own business when you have the same amount of unconventional experience as others in the industry.”

All of industry is still learning, he added. “When [tight-gas plays] started, they wanted to do slickwater fracks because it worked in the Barnett. Then, everyone went away from slick water: It didn’t work in other plays. They went to hybrid and gel fracks and now we’re back to slickwater fracks again.

“We’ve actually gone full circle. We’re still learning and nothing is set in stone.”

Super-high-intensity, slickwater completions have been underway in the Eagle Ford for a couple of years now. “And EURs are increasing significantly,” Rozenfeld said. For example, the area of the Penn Virginia well wasn’t very attractive two years ago.

“They switched to slickwater fracking. All of a sudden, wells are 700,000- to 800,000-boe EURs. And that was with just one change to completion design.”

The partners’ past start-ups’ work has been multibasin. “We like to bring best practices from everywhere. The more basins you look at, the more knowledge you gain about what other people are doing. And the better you’re going to be.”

He encourages others to “take the leap” and start their own E&Ps. “The downturn can make your life very bad in many ways, but there can be some positive outcomes from it.” He pointed to those who bought properties in the 1980s downturn, such as in the Permian Basin, and have done well.

“There are still opportunities out there for people to start their own business and I’m supportive of people doing that. I think it’s important. What drives the industry, really, are the independent companies that discover things.”

‘Arkoma Stack’

Nathaniel Harding describes Antioch Energy LLC as “a 34-year-old start-up.” Based in Oklahoma City, its predecessor, Harding & Shelton Inc., was founded by Harding’s father, Charles, and his partner, John Shelton, in 1983. “It definitely is a success story—getting through the hard times and finding opportunities.”

Nathaniel Harding is Antioch president; Kevin Dunnington, who joined H&S in 2004, is CEO.

“Some of our team has been with us for a while,” Harding said. “We really have the best people for each role and are fortunate for that. If you’re in the business and try to do the best work and find the opportunities, a lot of times you bump into the best people. You get lucky if you can bring them onboard.”

Harding himself worked previously for Encana Corp. in the Rockies and Texas; Occidental Petroleum Corp. in Bakersfield, Calif.; Marathon Oil Corp. in Wyoming; ExxonMobil in New Orleans; and Burlington Resources Inc. in the San Juan Basin. He also served in Afghanistan as a captain in the U.S. Air Force.

Back in Oklahoma, Antioch’s focus is on the “Arkoma Stack.” While the Stack play in the Anadarko Basin is named for the Sooner Trend in the area of Canadian and Kingfisher counties, Antioch adopted the name as its target in the Arkoma is also a multiformation play on the same formations.

“It’s the geological equivalent,” Harding said. “It’s not as deep, but it’s the same rocks. Being shallower and liquids-rich lead to lower well costs and lower declines. As a result, we’re seeing tremendous economics with some of the best breakevens and F&D in the Lower 48.”

Antioch’s leasehold is in Hughes County immediately west of the original Arkoma Basin shale play. In 2005, after horizontal Barnett development was looking successful, Newfield Exploration Co. tried laterals in the Woodford Shale in the Arkoma. It and others have made more than 1,000 wells in the formation since then, primarily in Pittsburg, Hughes and Coal counties.

That play was in the deeper, gassier area of the basin, Harding said. “We’re seeing an extension of the Woodford, but we also see opportunities in other zones.”

In the Anadarko Stack, the Woodford is less thermally mature moving updip, yielding more liquids. Antioch’s play in Hughes County is to tap the liquids-rich Woodford updip of the gassier focus of the original Arkoma play. The stream is about 50% liquids—both NGL and condensate.

“By having the NGL production along with the natural gas, we have some optionality. We have exposure to more than just the dry-gas market.”

He and the team brought their plan to TPH Partners LLC and, together, formed Antioch in September 2016. “We had a lot of great PE partners to choose from, and we’re thrilled to work with TPH Partners, particularly George McCormick and Curt Schaefer.”

The pair recently spun out of TPH but continue to serve on the Antioch board and manage the private equity funds under the new name, Outfitter Energy Capital LLC, Harding said. “We found that we have a like-minded approach to our strategy and they have been value-added partners in building an asset base.”

Modern completion techniques are key to Antioch’s development plan. “The Haynesville is an appropriate example. You have a renaissance of the Haynesville and you’re starting to see that in the Arkoma, where people are applying concepts and practices from other areas, like the Stack, that have worked.

“The Arkoma Basin still has a lot of upside to realize in drilling optimization and modern completions. We’ve barely scratched the surface of what would be modern completions—higher density, optimized cluster spacing and understanding what really happens between perf clusters.”

Hughes County was the most actively leased county in Oklahoma in April and May, Harding said. “You’re also starting to see permits. And there has already been an uptick in rigs.”

D&C costs for 1-mile laterals are about $3.5 million. “With modern completions, we continue to see upticks in EURs up to 6 Bcfe [billion cubic feet equivalent] per 1-mile lateral in our area. For 2-mile laterals—there isn’t enough data to fill that out with confidence. Some operators are doing 1.5- and 2-mile laterals. We’ll do extended laterals where it makes sense.”

Severed rights are common in Oklahoma, but there are relatively few in Antioch’s leasehold. “It’s Oklahoma; you see everything. In our acquisitions, we’ve been very diligent about not having severed rights. Sometimes it just requires a number of transactions to piece it all together.”

As the area is a longtime producer, takeaway capacity is abundant. “Certainly, there is a need to have more capacity for liquids processing and takeaway. There are a number of midstream players that recognize this and are already trying to get out in front of the oncoming wave.”

While Antioch is looking to add to its position, its primary focus now is on operations. Meanwhile, it continues to hold about 8,000 HBP acres in the western Anadarko Basin primarily in Custer, Dewey and Woodward counties, into which the Anadarko Stack play is extending.

“We’re participating in several wells in that area, but our position in the Arkoma Stack is where we will focus our efforts.” It sold other Anadarko Basin properties in 2013 for $120 million to Lighthouse Oil & Gas LP.

The “34-year-old start-up,” while newly named Antioch Energy and with PE backing, has a “legacy of success in Oklahoma going back to the early days,” Harding said.

“We continue to innovate and our story is that we are early-play developers. We try to utilize our local knowledge and relationships to find undervalued opportunities. That’s really where we have success in Oklahoma.”

Nissa Darbonne can be reached at ndarbonne@hartenergy.com.

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