At a gathering of A&D professionals to discuss the hotly contested Scoop/Stack plays in Oklahoma, HighMark Resources LLC president Ali Ahmed predicted major consolidation is coming, and that undeveloped acreage prices in the Stack region could leap to $25,000 to $35,000 per acre. This would surpass the high mark of $20,000 per acre set by Devon Energy Corp. in its acquisition of Felix Energy LLC in late 2015 given the rapid delineation taking place in the plays.

“A couple of deals are going to be announced shortly,” he said, “which should be accretive to our valuation.”

Ahmed made his comments at the Society of Petroleum Engineer’s Business Development Group meeting in Houston in late March. He was joined by Jeff Tanner, executive vice president of geosciences and business development for Jones Energy Inc., and James Royal, CEO of Staghorn Petroleum LLC.

Irving, Texas-based HighMark, formed in February 2016 with backing from Natural Gas Partners, holds approximately 13,000 net acres primarily in Blaine County, Okla., with about half acquired by leasing; the other half through buying smaller companies. “I wish I had 25,000, but the area is picked over pretty well,” he said. Highmark had studied the Stack for almost eight months before deciding where it would be a buyer.

The current leasing and regulatory environment is dog-eat-dog, he noted, with greenfield leasing opportunities scarce in the heart of the Stack play. “The time to start leasing is gone; you’ve got to buy companies now.”

Using a per-acre valuation is essentially irrelevant, he said, because buyers, including HighMark, are moving toward a discounted cash-flow valuation.

“I would throw out the per-acre number. We’re doing that because the play is being delineated with more results that are transparent. Companies are testing additional zones and they’re working. We think we’re going to have Permian-type metrics in the next 12 to 18 months.”

Those metrics depend on geography. He cited an example where one company put an implied per-acre valuation of $40,000 to $50,000 on the core of the Stack, and another allocated $100,000 per acre to one section showing five productive benches.

“We’re in a lot of wells and they’re delineating a lot of benches that are extremely economic at these prices. Now, instead of having five or 10 locations per section, you might have 20. That, obviously, is going to give you a bigger [valuation] number.

“People want to buy in the Delaware Basin, but the Delaware is done; maybe there are two or three deals left from what we are hearing from investment banks and others. They’re looking for the next place where they can make a good return at these [commodity] prices, and this is it. Every quarter the type curves and EURs are getting better. We’re going to see some significant buyouts in the next 12 months.”

Ahmed, who sold his previous company, Woodbine Acquisition Corp., to Meidu Energy Holdings in 2014 for $613 million, said almost 600,000 Stack/Scoop acres are in play, including his own. Private equity-backed teams coming to market include Paloma Resources LLC, Carrera Energy LLC, Council Oak Resources LLC and Red Bluff Resources Holdings LLC.

“I think the play will be dominated by about seven companies. There is a major consolidation coming.”

But new entrants shouldn’t despair. Low-cost entry opportunities do exist north and west of the core Stack play of Kingfisher and Canadian counties, he pointed out, particularly in Blaine, Dewey, Custer and Major counties. But while the footprint is expanding, delineation will take some time.

“The Stack is marching north and west. You’re going to have another Stack in the northwest extension” where operators are testing the Woodford and Osage formations, he said. “We’re participating in a lot of wells up there, and we think in the next few months we’re going to have some big IPs. We’re pretty excited about what’s happening there.”

HighMark, which has not drilled an operated well but is currently participating in 60 nonoperated wells, planned to have its first operated rig begin drilling in May, with a second anticipated in September. Ahmed expects to exit 2017 with roughly 5,000 barrels of oil equivalent per day (boe/d) of production. But, although the com­pany is early in its own acreage delineation, he also appeared excited about a potential near-term exit.

“There is so much going on around us and the well results are phenomenal,” he said, citing three wells that IP’d at about 3,300 boe/d. “With record deals that are going to be announced that are right on top of us, why would I not sell?”

Early in the Merge

Jones Energy Inc. made its reputation as an Oklahoma operator first in the western Anadarko Basin Cleveland Sands, then in the Arkoma Shale play. Now, with a $136.5-million acquisition of American Energy Partners LP’s approximately 18,000 net acres in August, Jones is planting a flag in the developing Merge play in Canadian, Grady and McClain counties right between the hotly contested Scoop and Stack regions.

“We believe 2016 will go down in hindsight as the year of the Merge discovery,” said Tanner.

Jones’ Merge entry was not accidental but years in the making, he said, as the company’s subsurface team had been building a Woodford Shale geologic framework for the basin since 2012. The team created a proprietary reservoir quality index based on porosity, mineralogy (low clay content in particular), brittleness and organic content. What they discovered was that the best landing points were not necessarily tied to the thickest parts of the basin—ie. the Scoop and Stack core areas— but to reservoir quality.

“The Jones view is that quality is much more important than quantity in identifying reservoir sweet spots and optimal landing points. Now we’re in a position to not only understand the key play parameters of the Stack and Scoop, but to quantify which part of this trend we believe is undervalued.”

Industry activity—and acreage value—has historically focused on the thickest regions of the Woodford Shale; the Stack to the north including the Meramec play, and the Scoop to the south including the Springer Shale. Results here have not disappointed.

But the Merge in the middle has positive attributes of both plays, he said.

Jones views the central Anadarko Basin as having two world-class resource plays, the late Devonian-age Woodford Shale and the overlying Mississippian Meramec, or Sycamore. These two reservoirs are long, contiguous play fairways that encompass approximately 3 million acres stretching across central Oklahoma. And the quality in this massive fairway is “truly remarkable,” he said.

“It’s this area of overlap that we call the Merge that really attracts Jones with stacked, high-quality targets in the optimal geologic setting, perhaps the best of both [reservoirs]. Remember, there are hundreds of vertical, com­mingled wells spread across the Merge that not only allow for a high-resolution stratigraphic model, but in my mind effectively de-risk this entire stratigraphic column for productivity.”

In between the Scoop and Stack drilling epicenters, Merge thickness is 50% to 75% of total Woodford thickness, but the drilling is shallower with a more simple structure.

“The critical point here is that there is not one commercial shale play today—not the Wolfcamp, Eagle Ford, Bakken or Marcellus—that is driven by overall shale thickness. Instead, we believe that specific petrophysical parameters tied to rock type drive well performance and recoveries.”

As an example, Tanner pointed to hydrocarbon-filled porosities in the Merge of 6% to 8%, contrasted with 2% to 3% in the Midland Basin Wolfcamp.

Jones characterizes the proven Woodford on its acreage as having two distinct members, the upper and lower, with the upper oil-rich target as “the key to our acreage.” It has also split the Sycamore into separate benches, with the upper flow unit directly correlating to the Meramec formation to the north, and the lower Sycamore directly related to the Osage to the south.

Jones’ Merge acreage is also differentiated by an eastern and western trend, with higher oil cuts updip to the east. “We target not only reservoir quality, but also optimal fluid mix [higher oil cuts], especially updip where we see lower D&C costs that we believe provide some of the best returns in the play.”

Tanner calls out numerous compelling recent well results with IP30s “well north” of 1,000 boe/d with 60% or higher oil cuts. Jones is presently running one rig in the Merge.

“These recent well results are incredibly economic with rates of return over 100%,” he said. “They also confirm our geologic model of quality over quantity.”

Staghorn’s double play

EnCap Investments-backed Staghorn Petroleum LLC, formed in 2015, sold a 41,000-acre package in the eastern Stack in Kingfisher and Garfield counties, but kept the more exploratory western package in Blaine, Major, Woods and Dewey counties with some 24,000 net acres.

Staghorn CEO James Royal said that while the Kingfisher County Stack features multiple, overpressured target zones, the shallower updip to the east can be just as economic as the known core.

“We looked updip for shallow, low energy, low GOR [targets] because you can drill a cheaper well. You don’t have to have as big of a well to have capital efficiency,” he said.

“If you want to pay a lot more to get into the over-pressured, deeper wells, if you’re drilling a $5- to $7-million well, you’ve got to have a substantially different IP and EUR than the wells where the 6,000 TVD [total vertical depth] is.”

To a certain point, companies weren’t capitalizing on that, he noted. “We found a lot of available acreage.”

To the west, however, is the next iteration of Stack development, he said. “You can see it coming; the results are starting to emerge. This whole area is a gift that keeps on giving.”