Private Buyers

In June 2015, Houston-based E&P Terra Energy Partners LLC announced the for­mation of the company with a $300 million equity commitment from private equity sponsor Kayne Anderson Capital Advisors. Terra is one of a host of companies funded by private equity shops since oil prices swooned at the beginning of 2015. Today, Terra is the largest producer in the Piceance Basin in northwestern Colorado, having scored WPX Energy Inc.’s legacy posi­tion in a $910 million deal.

At close to $1 billion, the deal is the sin­gle-largest acquisition by a private company since the start of the downturn, and Terra is on the hunt for more such deals in a drive to con­solidate assets in the basin.

“Having access to capital and being able to transact is critical,” said Mark Teshoian, managing director for Kayne Anderson and a director of Terra. “We’re actively pursuing additional opportunities and trying to get more deals done.”

Private equity sponsors see a rare opportu­nity in the A&D marketplace. Over the past 18 months, GSO-backed GeoSouthern Energy Corp. paid $850 million for assets in the Haynesville Shale; NGP-sponsored BlueStone Natural Resources LLC put up $245 million for Quicksilver Resources Inc.’s Barnett Shale portfolio; Lime Rock Resources paid $600 mil­lion to acquire Occidental Petroleum Corp.’s Bakken play; EnerVest Ltd. dropped $1.3 bil­lion in three deals in the Eagle Ford; and Merit Energy Co. paid $870 million for Marathon Oil Corp.’s Wyoming waterflood.

Together, private equity-sponsored E&Ps have placed some $16 billion in play since the beginning of last year.

When the bottom fell out after oil peaked above $100/bbl, private equity sponsors found themselves in a unique—and wide open—market for assets. Traditional buyers struggling to right balance sheets faced capital constraints from tighter reserve-based lending covenants and skittish public debt and equity markets until recently. Conversely, quality assets began breaking loose midway through 2015 from companies needing quick cash to survive or others refo­cusing portfolios.

New companies with cash and no debt were advantaged in this environment.

The day of the privco

The percentage of private companies trans­acting in the U.S. A&D market, as measured by deal value, nearly doubled from 2014 to mid-July 2016, from 27% to 44%, according to BMO’s calculations. “This defines the trend: clearly a steady—even dramatic—rise,” said Roberts, noting that transaction activity overall was down in 2015.

The first advantage for these private acquirers was that many of the companies that had done deals at or near $100/bbl oil were crimped going into the downturn. “There was tremendous cap­ital constraint for most companies that had been active in acquisitions. Those companies were burdened with a substantial amount of debt and were in retreat mode. If you made a large acqui­sition in 2014, you probably weren’t going to make another one for a while,” Roberts said.

The second advantage was the sheer quan­tity of private capital flowing into the oil and gas sector. Zero-percent interest rates made the type of returns available from private equity irresistible for many investors.

BMO has identified some 222 private equity funds active in North America with $270 bil­lion of assets under management. It estimates that some $146 billion of that amount could be aimed at oil and gas investments. Over the past 18 months, dozens of new E&P management teams have been funded, typically with $100 million to $500 million in equity commitments. Those with successful track records are getting as much as $1 billion.

“That’s largely a result of there being so much fresh capital available,” said Roberts.

For a while, the A&D environment opened up to such acquisition companies. Their tradi­tional competition was shut down, and they had plenty of money to grow. The competition was largely among each other.

Yet contests for assets returned to the market this spring, as public companies found they could access the equity markets for deal-mak­ing without being penalized by shareholders. Still, private companies dominate data rooms today and have a significant majority of all signed confidentiality agreements, according to Roberts.

Big Piceance

Legacy Rockies gas player WPX Energy began its portfolio shift to oil with the acquisi­tion of RKI Exploration & Production LLC in the Delaware Basin last year, and was deter­mined to pay for the $3 billion deal with gas divestitures. With 200,000 net acres, 500 mil­lion cubic feet equivalent per day (MMcfe/d) of production and an estimated 2 trillion cubic feet equivalent of proved developed producing reserves, its Piceance package was made more for an MLP than a private equity buyer. MLPs, however, were AWOL in the acquisitions mar­ket, while Terra was armed and loaded.

But reeling commodity prices during the negotiations in the early part of this year chal­lenged the deal's closing.

“What ultimately secured the deal for us was our ability to obtain the financing,” Teshoian said, “both on the equity and debt side. And it was not easy. That gave the seller confidence we could perform.”

The stage for the WPX deal was set about two years ago, when Kayne Anderson launched a new fund with a different strategy than its tra­ditional private equity model: The Kayne Pri­vate Energy Income Fund would target larger legacy, producing assets.

“We recognized a change in the market where many large public companies were focused on their core areas, so we thought there would be a flood of legacy, nonstrategic asset sales in the market. We felt those types of opportunities required a different type of capital than traditional private equity,” he said.

The new fund aims for a mid-to-high-teens internal rate of return (IRR), less than the 25% rate of return that most private equity firms target. “The advantage of this fund is that we have a lower cost of capital than traditional private equity,” he said. “With a lower return objective, that allows us to be more competitive on lower-risk, PDP [proved developed produc­ing]-heavy deals.”

Nonetheless, $910 million is a large gam­ble for private capital, and Kayne Anderson reached out to Warburg Pincus to come in as an equal partner in the investment.

“We view the Piceance as a basin ripe for consolidation, and Warburg agreed with our longer-term investment horizon. We partnered with Warburg to give Terra the firepower to be an aggressive consolidator of assets in the Piceance,” Teshoian said.

Around October 2014, Michael Land, a 20-year veteran of operations with Occiden­tal Petroleum Corp., anticipated a change in the economic environment and decided to go independent. “I was within a day of calling Kayne when they called me. The timing was right, and our mindsets were similar,” he said. He formed Terra and became CEO.

Land was familiar with big assets and the process of commanding big budgets with big operational teams. Most recently he had been president of Occidental Petroleum’s Midcon­tinent business, which included all of Oxy’s holdings in the continental U.S. except Cali­fornia and the Permian. Terra is not the first large business he’s run, “just the first outside of Oxy,” he said. Through Oxy’s position, Land was also familiar with the Piceance.

Terra closed the deal April 8 and took over operations July 1. The asset is performing “as well as or better than we initially expected,” said Land.

The company is currently running one rig in the play targeting vertical Williams Fork wells. “We are primarily driven by cash flow at this moment, so we’ll look at what rig count allows us to manage our operations, service our debt, pay our dividend to investors and grow at as fast a pace as makes sense.” Terra may add a second rig next year.

Besides Terra, Kayne has two other invest­ments in the Income Fund that are seeking larger, longer-term acquisitions: Oak Ridge Natural Resources LLC, based in Tulsa and led by Chris Jacobsen, and Sabinal Energy LLC, based in The Woodlands, Texas, and led by Bret Jameson.

Teshoian believes the market is still advan­taged to buyers, particularly those with capital for larger deals. “Having access to capital and being able to transact is critical. We don’t think there are many on the private equity side that can transact on a deal of this size. We are actively pursuing opportunities and trying to get more deals done.”

And money is no obstacle. “Terra has all the capital it needs. If we found a deal this size or larger, we would find a way to make it work.”

So what’s the exit? “If things go according to plan, which would include bolt-on opportu­nities, the company may be a candidate for a public offering down the road,” said Teshoian. “We feel that we’re going to be able to build a significant business, and an IPO is a distinct possibility.”

Haynesville homecoming

As the Permian is to oil, Ark-La-Tex is to gas, asserts Covey Park Energy LLC co-CEO John Jacobi. He believes the Haynesville Shale package the company acquired from EP Energy Corp. for $420 million in May is a field of diamonds.

“It’s one of those basins that is a gift that keeps on giving, and we’re in the core of the play. I would argue that it is as economic as any commodity play in the country—oil or gas.”

The deal involved more than 34,000 net acres in Louisiana’s DeSoto and Bossier parishes with existing production of 113 million cubic feet per day (MMcf/d) and 205 billion cubic feet (Bcf) of proved reserves. The PDP component is vital in the Dallas-based company’s acquisition crite­ria. Current economics top a 35% IRR.

“Even though the commodity was in the $2 range, we felt we could do very well here,” Jacobi said. “EPE developed it correctly and left room for somebody like us to build a com­pany around it. They had proven they could economically produce gas in any environment.”

The Ark-La-Tex region is not unfamiliar territory to Jacobi, who worked the area pre­viously while with Exco Resources Inc., and co-CEO Alan Levande, a former Goldman Sachs investment banker. As a senior manag­ing director with Tenaska Capital Management, Levande had worked with Exco on the Haynes­ville assets. The two formed Covey Park in 2013 and secured $300 million in initial back­ing from Denham Capital in June 2014.

“They liked our model of acquisition and exploitation more than lease, drill and sell. And they didn’t make us stay in just one basin,” Jacobi said.

The company’s first deal was in Amoruso Field in East Texas, which it acquired from Encana Corp. for $425 million as the Calgary E&P restructured its gas-weighted portfo­lio. Encana acquired a remaining 50% inter­est in Amoruso, one of the highest-volume gas fields in the U.S., from Leor Energy LP for $2.5 billion in 2007. Covey Park added another 35,000 acres from Penn Virginia Corp. in Panola County, Texas, for $75 million in September 2015.

Although Covey Park has shopped var­ious basins, “Ark-La-Tex seems to be more active than normal—maybe as active as it’s ever been,” he noted. “People are exiting, and we’re seeing a lot of opportunity.”

Jacobi credits the flow of assets into the market to companies needing to correct debt-heavy balance sheets, preferring asset sales over dilutive stock offerings. “They’re having to sell good assets to live another day. We’re finally seeing assets that meet our investment criteria come to market.”

Other sellers, he said, are simply taking advantage of the hunger for assets and the cash in play in the private market to monetize.

Infrastructure plays a big part in his geo­graphical bias. “We’ve got a lot of gas in this country, and a lot of it is in areas where the cost to get it to market is extremely chal­lenged. We try to look at areas where the least of our worries is getting it to market. We like where we’re at in relation to the market, and we like the ability to produce when we ask it to produce.”

Covey Park recently finished drilling its first several wells on the EP Energy assets and plans to drill five more this year with one rig. It also anticipates drilling four additional Haynesville wells in Panola and DeSoto coun­ties in East Texas with a second rig and two deep Bossier Shale wells. “We feel the Bos-sier has a lot of potential in that region. It’s been underexploited and, at the right time, it will be a big boon for us,” he said.

The company currently controls 196,000 net acres in East Texas and Louisiana and has close to $1 billion in acquisitions under man­agement since its inception.

Is it done? “We certainly don’t think so,” said Jacobi. “We’re looking at lots of opportu­nities both in the Haynesville and other basins around the country. We would also like to own an oil asset to complement our gas portfolio.”

A pearl in the Permian

“When oil prices fall, how do you make money in the oil business?” asks Forrest Wylie, Ajax Resources LLC executive chair­man. “You don’t explore for it—you buy oil in place.”

In September 2015, that’s what Houston E&P Ajax did, securing nearly 26,000 net acres in the northern Midland Basin from W&T Offshore Inc. for $376 million. That acreage, Wylie asserts, holds 7 billion barrels (bbl) of oil in place.

“This is not a guessing game,” he said. “We’ve got oil-in-place numbers based on 230 drilled wells. There’s no question; we’ve got it.”

The story of Ajax began in October 2014, when Wylie, then chairman of midstream company Buckeye Energy Partners LP, and Steve Wyatt, a career commodities trader also working at Buckeye, decided to form a company to buy distressed assets as commod­ity prices softened. Shortly thereafter, Wyatt formed Wyatt Energy; then the bottom fell out of oil prices following the November 2014 OPEC meeting.

“We didn’t see the price of oil going down as far as it did; I don’t think anybody did,” said Wyatt.

With the futures market in contango, Wyatt, with his experience in commodities trading, knew the scenario typically lasts no more than 18 to 24 months, a window of buying oppor­tunity. They aimed for the Permian, the basin with more oil in place than anywhere other than the Vaca Muerta Shale in Argentina.

Wylie joined Wyatt Energy full-time in April 2015, and the W&T Offshore package came to their attention in June. The Gulf of Mexico operator had acquired Yellow Rose Field at the confluence of Martin, Andrews, Gaines and Dawson counties in 2011 as a hedge against the shutdown of operations in the Gulf following the Macondo oil spill inci­dent. The field was north of historic activity in the Midland Basin, and W&T struggled to make new horizontal wells economic. In a lim­ited, nonmarketed offering, Wyatt Energy was invited to bid.

“We saw it and ran after it,” said Wylie. “It was exactly what we were looking for. It fit the pistol.”

But the $376 million price tag was too big for Wyatt Energy alone. Wylie had a long rela­tionship with New York-based private equity firm Kelso & Co., having partnered with it in nine deals. Wyatt and Wylie, with Kelso, formed Ajax Resources to hold the Yellow Rose asset, with Wyatt Energy as the predom­inant investor. Ajax is named after the Greek mythological warrior and Wyatt’s favorite mountain to ski in Aspen. The deal closed in October 2015.

Still, the acreage block remained unproven. “Our risk was that it was on the fringe,” Wylie said. “Our gamble was that it wasn’t. To get a low price when you’re buying oil and gas prop­erties, you’ve got to take some risks.”

The team, along with Ajax CEO Harvey Klingensmith, worked with reservoir consultant Bill Von Gonten before and after the deal. He gave them the confidence to transact.

“Bill said the rock was the same as to the south in the basin. We believed in it and got a cheap price, because people thought it was on the fringe, and it’s not.” In the year since the acquisition, operators such as Diamondback Energy Inc., QEP Resources Inc. and RSP Permian Inc. have drilled and proved multiple zones in and around Ajax’s block.

Further, Wylie noted Ajax’s acquisition met­rics were based solely on the Lower Spraberry trend, while two additional trends have already been proven—the Middle Spraberry and Wolf­camp B—with three others prospective: the Wolfcamp A, Cline and Jo Mills.

“We paid $11,000 per adjusted net acre for Lower Spraberry reserves, and people are now paying $15,000 for the Lower Spraberry—and $15,000 each for the Middle Spraberry and Wolfcamp A and B. That equates to $60,000 per acre,” Wylie said.

In June, QEP entered a deal to pay just that metric for acreage less than 10 miles south of Ajax.

Since its acquisition, Ajax has drilled five wells and completed one drilled-but-uncom­pleted well left by W&T to hold acreage. Ajax now controls 100% of the acreage. Estimated ultimate recoveries per well as estimated by W.G. Von Gonten & Associates are 840,000 barrels of oil equivalent (boe), and 720,000 bbl alone. At $50/bbl, Wylie puts half-cycle eco­nomics at 60%.

Ajax has now dropped all operated rigs, but it’s involved in three joint operating areas (JOAs) as a nonoperated partner: three with Diamondback and one with ExL Petro­leum LP. It also has a JOA with QEP, with Ajax operating.

“Our strategy has been to let everyone drill through us, and that’s what’s happening,” said Wylie.

In one JV, Diamondback plans to drill wells with 12,000-foot laterals. “If you can get the hydraulic pressure to work to release those reserves, the IRR on half-cycle returns goes from 60% to 120%. It’s phenomenal, and the majority of our acreage can be drilled with 12,000-foot laterals.”

Ajax calculated its purchase metrics using 10% as the amount of recoverable reserves, but Wylie said current technology reaches 15%, according to Von Gonten’s research. “If we can get 20% on four benches, we’re at over 1 Bbbl of recoverable oil. Times $40/bbl, that’s a big number.”

Additionally, Wylie expects to develop the Lower Spraberry with a wine-rack configura­tion on 330-acre spacing, allowing 10 wells per section versus five to eight, effectively doubling reserves.

Ajax won’t add a rig again until oil tops $50, the level at which some of its lease agreements require drilling three wells a year.

Wylie anticipates an exit to a major or large independent, which he thinks will dominate the Permian in the consolidation to come. This theory is based on the short-cycle time for cap­ital in a shale play versus the decade-long wait for return on capital for the big-ticket invest­ments majors and large independents usually develop. And they will either buy smaller independents with large acreage positions or a “string of pearls” of smaller positions in the heart of the play.

“We are part of that string of pearls.”

That’s why companies are now paying $60,000 per acre, he added.

“The reason we could get it for $11,000 per adjusted net acre was because everybody said the sweet spot was south and east of us. Now Diamondback is drilling in the heart of our property. You know why? Because it’s the sweet spot.”

Deal in a maelstrom

To say that the environment during the latter months of 2014 was not conducive to sealing a deal is an understatement. When BHP Billiton opened its data room in August of that year to market its Delaware Basin acreage in Reeves County, the price of oil hovered around $100. By the time San Antonio-based private E&P Silverback Exploration LLC closed the deal in December, the price had fallen to $59—and was going lower.

“Prices were dropping like a falling butcher knife throughout the data-room process and the negotiation for the purchase,” said Sil­verback CEO George M. Young Jr. “Without a strong, experienced sponsor like EnCap Investments, we would never have been able to pull this off in light of what commodity prices were doing.”

In fact, it was likely the depth of experience of the management team that kept the deal alive, particularly considering the leap of faith the Silverback group was asking its private equity sponsor to take in regard to well ana­logs. At the time, there weren’t any positive results within 20 miles.

Silverback was formed in late 2013 when times were good. Young and industry icon Ted Collins Jr., Silverback’s chair­man, were looking to repeat what they had done in the early days of the Barnett Shale, when they paired up as Collins and Young LLC to prove up the original shale play. Young called former EOG Resources Inc. Barnett operations manager and acquaintance Steve Lipari who, coincidentally, had formed a technical team with the same intent. Lipari had spent 22 years in operations at EOG and knew its technical model. The marriage was made.

EnCap committed to Silverback with $350 million, and “I suspect we’re one of the most experienced teams they’ve ever backed,” said Young.

Once it set its sights on the southern Del­aware Basin, the combined Silverback team began gathering data. The team procured as much 2-D and 3-D seismic as possible, joined The Core Lab Consortium and built a regional petrophysical understanding before kicking off its leasing program. Shortly thereafter, BHP put its 50,000-acre position in Reeves County up for bid.

“We were ready,” Young said. “We had already been working the area; it was perfect timing.”

But not a perfect asset. BHP had come by its southern Delaware acreage via its purchase of Petrohawk Energy Corp. some four years earlier, when the area was purely exploratory as a horizontal play. The Australian conglom­erate had focused its efforts on the Wolfcamp C horizon without stellar results.

“BHP was real early in the learning curve,” Lipari said. “We had done work in the Avalon, Bone Spring and the Wolfcamp A and B, and we quickly evaluated that that was where the asset value was. We could see value in sin­gle-well economics in just the Wolfcamp A. So we ignored some of the earlier wells that had been drilled on it. The tricky part was convincing EnCap of that.”

As part of its due diligence, Silverback ran economics on 50 wells in the area, “and the P50 really wasn’t economic,” Lipari said. So the company homed in on a data set from nine particular wells and called those results its “best-in-class” type curve. The problem with that? “We had to stretch all the way to an EOG well—a 20-mile stretch—to come up with that type curve.”

Given the Silverback team’s level of detail and rock knowledge, EnCap agreed to sup­port the deal. With prices falling, Silverback secured the asset at what Lipari considers a reasonable PDP value and low acreage costs, although the price remains undisclosed.

“We had a good understanding of the rocks. That gave us a competitive edge. The collapse in oil prices probably weeded a lot out of the data room too.”

The company quickly consolidated the block to its geologic and geophysical interpre­tation and concentrated on maintaining about 30,000 core acres, where it stands today.

A bonus: BHP had completely built out the infrastructure, anticipating a multiwell drill-out scenario across the asset. “They had a tremendous midstream system,” Young said. “A huge amount of capital had been deployed. Had they not done that, it would have been a lot more expensive on our part and slowed us by more than a year. We had a plug-and-play model by January 2015.”

The midstream system was carved out and acquired by Eagleclaw Midstream Ventures LLC—another EnCap Flatrock Midstream portfolio company—simultaneously to the upstream acquisition.

Yet Silverback didn’t drill a well for more than a year after the purchase.

“We did our homework,” Lipari said. “The true success of Silverback has to do with the geologic, geophysical and petrophysical approach to the business—we’re managing the risk by understanding the rock first before deploying capital into drilling and comple­tions. We interpreted the 3-D data down to the level we had been trained to do at our previous homes, evaluating the core data and building the petrophysical models in more granular detail.”

Silverback added its own rig in late 2015—after which prices dropped dramatically. Its first Wolfcamp A well, Folk Rolling 4-3433 1-H, with a 7,000-foot lateral, posted an initial production (IP) rate of 840 bbl/d and 6.8 MMcf/d at 1,826 psi. The second, Williams 4-53 2-H, with a 5,000-foot horizon­tal, showed similar IP results: 819 bbl/d and 7.3 MMcf/d.

“We did a tweak in the completion, and its casing pressure was about 900 pounds higher than the first well. It’s FCP [fracture closure pressure] was 2,770 psi,” said Lipari.

In addition to Silverback’s two new wells, three operators—also backed by private equity, have drilled nine additional Wolfcamp A offsets in the area: ExL Petroleum LLC, Arris Operating LLC and Manti Tarka Perm­ian LP. Two-thirds of the additional wells had IP rates between 800 and 1,000 bbl/d, similar to Silverback’s two wells.

The current type curve now includes data from 300 wells, sorted to the best-in-class 100.

“The type curve we used in the acquisition is maybe 60% of the current type curve. We have a 1.5x factor on the current type curve being employed,” Young said.

Silverback and its privately held neighbors have created their own information-sharing consortium. “Our goal is to drill the best wells we can,” he said. Silverback has a working interest in a recent Manti 10,000-foot well with an IP rate of 1,642 bbl/d.

On an equivalent basis, both of the afore­mentioned Silverback wells had IP rates of more than 2,000 boe/d, with all 11 wells in the neighborhood at an average 1,524 boe/d.

“Those are best-in-class for southern Reeves County,” said Young.

Wells with 10,000-foot laterals run $9.3 million, including the facility and exclusive-of-science work, with a target of $8.3 million when in development mode. Rates of return are economic in the current commodity environ­ment, Lipari said. “When oil was above $45, our economics were very robust.” Silverback has estimated it has more than 1,000 locations in multiple benches of the Wolfcamp A and B alone.

Lipari characterized the current completion techniques in the basin as “Generation 5,” as compared to Generation 1 completions being used at the time of the acquisition.

“In the Delaware, the front end of the learning curve has already occurred, so you can feel more comfortable with single-well economics now than you could two years ago when we bought this. Even at a relatively low strip, we’re generating economic—even highly attractive—rates of return, because ser­vice costs have dropped so low and the wells have gotten so much better. It’s been a rapid learning curve.”

While the oily opportunity lies in the Ava­lon through Wolfcamp B zones, he hopes to one day drill the Wolfcamp C again, which he expects to be gassier. “We’d love to do a Wolfcamp C well with a Generation 6 comple­tion"—incorporating more stages. "There’s a huge gas resource in the area.”

Silverback pushed the deal through a mael­strom of falling prices, but “100 million barrels per section looked pretty intriguing,” Lipari said. “We had an understanding of this spot of dirt, and it was an opportunistic deal for us. We’re doing everything we can to make it all it can be.”

Redefining Midland’s core

In November of last year, Independence Resources Management LLC brought the winning bid of $177 million for 4,657 net acres straddling the Ector/Midland counties line in the western Midland Basin. The Gardendale assets, as they are known, were being carved out of Resolute Energy Corp.’s portfolio in an effort to pare down debt.

The deal was valued at $28,000 per acre.

“The most striking thing about the Permian Basin was—even as oil prices were falling from the $80s into the $60s and then on down—the valuations stayed flat from an acreage perspective,” said Independence chief corporate officer Rod Steward. “That suggested a very competitive market in the Permian. That also suggested the play was start­ing to develop, and its value was understood.”

Houston-based Independence, a portfo­lio company of Warburg Pincus, is in effect a getting-the-band-back-together tale. CEO Mike Van Horn and Steward, along with chief geosciences officer Chuck Minero and COO John Nicholas, all cut their teeth at Enron Oil & Gas in the 1990s. When EOG peeled off from Enron in 1998, the team stayed with Enron, becoming its international E&P arm. After the crash of Enron in 2002, Van Horn and Steward returned to EOG, working on initial efforts to open the Barnett Shale as an uncon­ventional play.

Ultimately, each went their separate ways, but they banded together again in December 2014 with a $500 million equity commitment from Warburg.

“We saw a value arbitrage in developing resource play assets by taking them from very undeveloped to creating the manufacturing pro­cess; nobody else was doing that,” said Steward. “Because Warburg tends to be a creator of com­panies, rather than a flipper of ideas or deals, that fit our mold. They have a very long-term view of the industry.”

In sizing up basins, the Independence team’s driving criteria were large oil in place, with historically low recovery factors, and multiple horizons.

“We weren’t looking for a one-trick pony; we were looking at stacked plays, with multiple intervals being economic,” said Van Horn.

But as prices deteriorated, “the river dried up and there were few deep holes that could sus­tain a company,” he said. “For us, the Midland Basin became the place we wanted to settle in.”

And with Diamondback Energy, RSP Perm­ian Inc., Callon Petroleum Co. and Reliance Energy drilling on three sides of Indepen­dence’s acreage, “I’d say we’re in an outstand­ing neighborhood,” Steward said.

Since the acquisition closed in December, Independence has drilled one operated well into the Lower Spraberry, its primary target, but believes the Spraberry interval alone holds four pay zones. “We want to evaluate all of them. We think they all have economic merit,” said Van Horn.

Before selling, Resolute had drilled three horizontal wells, all into the Wolfcamp B, that produced an average 800 bbl/d on a 24-hour IP rate. Independence has no immediate plans to prioritize the Wolfcamp B, although it is “on the list.” Other prospec­tive zones include the Wolfcamp A, the Cline and Clearfork.

“We think there’s a lot of potential in the Spraberry at multiple levels,” said Steward. “We’re in a commodity price and service cost environment that makes them very economic. We don’t feel like there’s an enormous amount of risk on well performance.

“We’re trying to understand the rock better in our specific area and understand the effi­ciencies of development. We feel like we’re above breakeven at this point, and we’re willing to drill at these commodity price and service costs.”

The company is geared up to drill as many as 12 wells during the remainder of this year.

“Our strength is that we have a good techni­cal grasp of the plays; we can execute as well as anybody out there,” Van Horn said. “We’re in a good time to be putting dollars into the drillbit.”

Gulf Coast bright spots

Privately held conventional explorers are not missing out on the acquisition window. Pintail Oil & Gas LLC bought some 13,000 net acres in southern Louisiana’s Beauregard and Calcasieu parishes in March 2015 from Midstates Petroleum Co. for $44 million, adding to its Gulf Coast conventional portfo­lio. The deal, according to Pintail CEO Jim Ivey, represents a plan to capture conventional assets being dumped by larger public and private independents.

“A lot of these companies are shedding assets that are a drag on their core business strategy,” he said. “That’s where we’ve seen the most opportunity.”

Such was the case with Midstates, which was trying to raise liquidity and focus on its Midcontinent assets. Pintail stepped in fol­lowing a failed sale that resulted from falling oil prices in the spring of 2015. Having been a bidder in the original offering, it was able to secure the Louisiana Dequincy assets for about half the original price.

The opportunity in the marketplace for con­ventional assets represents a unique moment in time for private equity E&Ps to grow, he said.

“If you’re public, it’s tough to chase these kinds of properties. Most publics or large pri­vates simply don’t have an interest in developing these assets. Those companies tend to be sellers of the types of assets we like to acquire.”

Pintail partnered with Ridgemont Equity Part­ners under a $50 million commitment in early 2014, but as oil prices crashed later in the year the Houston E&P decided to grow via A&D. “We used our dry powder for acquisitions as opposed to developing properties,” he said.

At year-end 2014, the Dequincy assets produced some 1,300 boe per day, and they house several stacked pays along with multiple producing horizons with substantial upside, Ivey said. However, Pin­tail has no immediate plans to drill, instead preferring to hold production flat through workovers and recompletions, tapping uphole opportunities first.

“We viewed the Louisiana properties as being able to live within their means for quite some time while we worked to develop the upside opportunities,” said Ivey, “so it will cash-flow nicely even in a lower price environment. We can aggressively grow it when we get an upward tilt to the commodity price.”

Deep Wilcox wells here cost $2.5 million to drill, he said, while shallower Cockfield wells cost around $1 million.

“For the most part, the Cockfield wells look very economic in today’s price environment, but we don’t have any plans to drill it any time soon. We continue to find enough behind-pipe oppor­tunities to bring online production that is much cheaper than drilling a new well.”

At what price point would he look to acceler­ate development of the field?

“It’s closer to $60 than $40,” he said. “Then we will put an aggressive development program in place before putting a nice, big red bow on it and selling it at some point in time.”

Vying for deals

While these and other private E&Ps were able to transact during the commodity down­draft, future acquirers might face a head­wind. Since spring, public companies have gained confidence—and investor support—for growing through A&D. Some examples: Devon Energy Corp. in the Scoop/Stack plays; Parsley Energy Inc. in the Permian; Synergy Resources Corp. in the D-J Basin; New­field Exploration Co. in the Stack; Range Resources Corp. in Terryville Field; Antero Resources Corp. in the Marcellus; QEP in the Midland; and Marathon Oil Corp. in the Mid­con, to name a few.

Silverback’s Young believes that private companies still have opportunity in the marketplace, but agrees that the deal environment has become more competitive.

“There is a tremendous amount of private equity still on the sidelines that needs to be deployed. You’re going to see a mixture of publics and privates still active on the acqui­sitions front.”

But Independence Resource’s Steward pos­tulates the tide has turned.

“In the current equity market, the publics are probably advantaged,” particularly in the pricey Midland Basin where Independence operates. “If you look at all the equity deals that have been done to finance acquisitions, they’ve got a pretty good financial advantage over private dollars, based on the last six months of deals.”

The tale of the tape was evident in July: Public E&Ps almost completely replaced private E&Ps on the list of significant trans­actions. With $146 billion in private equity powder in play, just how aggressive will the private players be in competing with their traditional rivals?

“That is a lot of money, but we’re at an interesting point,” said BMO’s Roberts. Gas prices are firming, but oil prices remain volatile, making a big downward move in July following a five-month rally—and price volatility is a leading indicator of a lull in transactions.

“A lot of private companies are still pursu­ing deals aggressively, but we may see a pause for acquirers of oil if prices keep trending down,” he said. Once oil stabilizes, he expects private and public companies to resume vying with each other in the deal market.

In early August, BMO advised Newfield Exploration Co. in a $390-million sale of Eagle Ford assets to privately held Protégé Energy LLC and another undisclosed buyer, indicating the run for private buyers is far from over.

“There is way too much money out there to be constrained by historical metrics,” he said. “Prices are going to go up with commodity prices, and you’re going to see a lot of activ­ity—unless oil goes down any further, and stays there.”