Bill Marko is usually bullish about U.S. M&A market conditions. In mid-July, though, he was “considering being bearish and down in the mouth” for the first time. “I don’t see an easy way out of this,” the Jefferies LLC managing director said.

The WTI prompt-month contract took hold below $50 again in the second quarter. In late July, a contract didn’t begin with a “5” until December 2019.

Public E&Ps bought assets during the past year on a premise, he said, that “‘I’m going to add six rigs or three rigs or 10 rigs,’ and all of the analysts said, ‘Okay, go do that.’ They’ve got to grow and add rigs. They have to demonstrate the type curves they had when they went to the public markets six or nine months ago.”

Thus supply, particularly from the Permian Basin, is growing. Lower 48 production was 9.005 million barrels a day (MMbbl/d) on July 21, approaching the modern high that was set in mid-June 2015 at 9.19 million, according to U.S. Energy Information Administration (EIA) data.

The post-2014 low was found at 7.969 million last October. In nine months since, Lower 48 producers added more than 1 MMbbl to daily supply—nearly as much as OPEC members’ targeted cut.

Randy King, a managing partner for Anderson King Energy Consultants LLC, said, “We have three deals that are just sitting on hold ready to go when prices get to a sustainable level.

“It feels like this oil-price debacle is a little bit self-inflicted. I understand the nature of entrepreneurial companies: Everyone wants to get their fair share and grow. But the collective nature sort of works in cross-purposes. It’s frustrating.”

Producers are near-term frustrated too, “but they’re not frustrated enough to slow down in terms of their operational development. They work from a perspective that it’s a tough resource to get. It’s generally in short supply. And, at some point, prices will recover and they will be well-positioned with a volume story and a growth story.”

Producers’ optimism is driven only to the extent that capital markets will continue to fund them—“certainly on the public side,” said Randy King, managing partner, Anderson King Energy Consultants LLC.

Help us help us

In late July, the EIA forecast that total U.S. production—including Alaska—will average 9.9 million a day in 2018 with 515,000 of the extra barrels coming from the Permian. (The all-time, all-U.S. high was 10 million a day in the fourth quarter of 1970.)

Al Walker, chairman, president and CEO of Anadarko Petroleum Corp., told investors in June in a keynote speech at a Wells Fargo conference, “The biggest problem our industry faces today is you guys. You don’t reward capital efficiency; you reward growth.

“ … As long as investors continue to invest in companies with growth with marginal wellhead economics, you’ll get more growth. So you guys can help us help ourselves.” Joseph Triepke, founder of and principal research analyst with Infill Thinking LLC, first shared the transcript, which was widely circulated on Twitter.

King said, “Yeah, he sort of chided us.” Producers may state, for example, that follow-on funding will be for 50% ROR wells, and analysts agree. Yet “we never see the actual data behind it,” King said.

Greg Armstrong, chairman and CEO of Plains All American Pipeline LP, said something similar at an investment conference in 2003 when discussing acquisitions: “If you’re going to use the word ‘strategic,’ you had better have the word ‘accretive’ in there somewhere; otherwise, it’s just not worth doing,” Oil and Gas Investor quoted him at the time.

In a study this spring, Michael Hanson, a founding member of Parkman Whaling LLC, looked at the top 40 Permian operators’ guidance on production growth. If hitting those targets, they would double daily output from the basin to 4.5 MMbbl by 2020.

But they can’t, Hanson concluded: Oil prices would fall, oilfield service costs would rise, infrastructure would be insufficient and $150 billion of additional capital would be needed.

“In their quest for growth for growth’s sake, operators seem to be missing the forest for the trees,” Hanson said. “They’re so focused on their own growth that they miss how the collective growth goals of their peers are affecting the economics of the industry.”

He wrote in the firm’s newsletter in late June: “[Capital] market sentiment is about as bad as it’s been in quite some time.” Among indicators, “even the invincible” Permian stocks were down 20% year to date.

Within A&D, “we are aware of multiple failed sale transactions over the past month. We’ve noted not only bids not meeting seller expectations but also fewer bids. Buyers are saturated with existing projects, it appears, as investors’ appetite for new acquisitions seems to be waning.”

Regarding Walker’s remarks, he wrote, “Perhaps some [investors] are beginning to heed his message.” In late July, Walker announced that Anadarko would pare its 2017 capex budget by $300 million.

‘Off a cliff’

King noted that producers’ optimism is driven only to the extent that capital markets will continue to fund them—“certainly on the public side.”

Marko said public markets won’t fund equity issuances right now. “What you had were circumstances where you had a firming oil price, a good gas price, really good public markets and a lot of private owners thinking, ‘Hey, it’s time to rotate out of these assets.’

“All of that came together. In the Permian, Scoop/Stack and a few other areas, it caused a lot of deals to get done. It was a really buoyant market.”

Currency included stock that was strongly valued. For example, shares of RSP Permian Inc. were trading at an all-time high in January at more than $45 when WTI was about $54; the E&P had IPOed in January 2014 at $19.50, when WTI was $94.

In two parts—in November and in March—RSP bought Silver Hill Energy Partners LLC and a Silver Hill II entity for 31 million shares and $1.25 billion of cash. It sold 25.3 million shares and $450 million of notes to fund the cash portion.

Marko said producers prior to this summer “were drawing nice equity valuations, and the market was wide open for them.” In the past three months, however, a lower WTI has dampened public-investor interest in more buying.

“We started increasing the rig count and started growing production. So oil prices have gotten weak. Conditions are crummy today.”

Until May of this year, deal flow was on pace to reach $75 billion. Since then, “it really has fallen off a cliff to a pace of less than $50 billion. It will be a choppy deal flow in front of us.”

In the past 12 months, roughly three dozen Permian packages have changed hands, he added.

“We initially thought a year ago that there would be a half-dozen to a dozen big deals out of the Permian. The higher-quality assets got sold earlier and the harder stuff—generally earlier in the life cycle—is getting sold later. And, with the market conditions where they are now, they are harder and harder to sell.”

The rush to block up a sizable position in the basin drove a lot of transactions heading into 2017 and during the first quarter. “The public guys made a lot of progress in getting positions for longer-term propositions to exploit. It’s not totally over with, but almost every public company with a desire to get a Permian or Scoop/Stack position has pretty much done that.”

Laser-focused

Chris Atherton, president of EnergyNet Inc., noted that private equity (PE) entities continue to fund E&Ps. The firm facilitates both auction and negotiated transactions—thus seeing a gamut of deal sizes from less than $100,000 to about $100 million. The firm closed more than 650 sales in the first half of this year, totaling some $500 million; when including the second half of 2016, its negotiated deal volume was 12, ranging from $25- to $100 million.

Atherton said both public and private producers are settling in. “The A&D market, in general, is less opportunistic than it once was. Teams with a laser-focused strategy are trying to execute on that.

“People only want to see assets in the Eagle Ford oil window. They only want to see assets in the Delaware Basin or only in California—whatever. They’re laser-focused.”

Directors are holding the line. “Boards of public companies and the private equity sponsors are saying, ‘There are only certain basins or plays that will meet our return-on-investment threshold.’

“It’s a difficult decision to ever sell any assets because, at one time, they were very important to the company,” he said, but many are selling, nevertheless, to fund their tack. “The food chain in our industry is extremely long and nuanced. Not everyone chooses to focus on the Delaware, Midland or western Anadarko basins.”

Sales of noncore assets include Halcon Resources Corp.’s planned divestment of its Bakken holdings, Noble Energy Inc.’s divestment in the Marcellus, Anadarko’s Eagle Ford exit and Encana Corp.’s Piceance Basin sale. In each case, the sales are to fund acquisitions and/or capex in the Permian and/or de-levering from having borrowed to fund the purchases.

“Privately held E&Ps are buying,” Atherton said. “These are really good assets; they just don’t meet the current [owner’s] criteria.”

Some PE-backed operators are simply leasing, such as in the Eagle Ford and the Arkoma Basin. “Yeah, we have seen quite a bit of that,” Atherton said, “where they’ve gone out and, instead of trying to acquire [PUDs and PDP], they’re organically leasing to build their positions.”

King noted that privately funded start-ups have a constraint, however: “They have a fixed set of capital. They can’t raise incrementally. These drilling programs challenge their capital abilities.”

Section-trading

Public buyers have pent-up demand for private company portfolios, but private sellers “don’t want to do that with the bids in a $40s oil environment.”

He added, “It will be interesting to see the capital availability from the PE guys over the next several years—how well-funded they are for growth.”

For several years, industry cited PE chests as brimming with more than $100 billion. King said, “It doesn’t feel like there’s that kind of capacity out there. These organic drilling programs can chew up a lot of capital pretty quickly.”

Marko said, though, that the bright spot “is still the private capital.” How much is available is unclear, “but there is a lot of money on the private capital side. They think it’s a great time to buy. They have a macro-view that, down the road, it will get better.”

Meanwhile, the biggest prospective buyers are “kind of on the sidelines, trying to digest what they already bought,” he said.

They’re also actively section-trading. “You have a section and an offset operator has a section. You may trade something similar in a different area, so you can drill 10,000-foot laterals rather than 5,000-foot laterals for not much more money but for two times the barrels. There is a lot of that going on and I think there will continue to be a lot of that.”

The next round of deal-making may be “all in the name of efficiency. I think we’re in the second or third inning of how we improve efficiencies of the whole business.”

One of these—the EQT Corp.-Rice Energy Inc. merger—is financial in nature. “I think all of these plays will continue to consolidate. You will have a handful of companies owning most of a play. Maybe not the Delaware—it’s too much drilling and too much capital—but something like the Marcellus and the Haynesville.”

“The A&D market, in general, is less opportunistic than it once was. Teams with a laser-focused strategy are trying to execute on that,” said Chris Atherton, president of EnergyNet Inc.

Field service costs declined dramatically after 2014 but can’t decline to zero, he noted, and some costs will inevitably rise. “It’s not sustainable.” So efficiencies are being sought by drilling better wells—and faster—and buyers are looking at less-efficient operators as targets.

Noncore assets

Filling the deal-flow gap are noncore asset divestments, such as by Encana, Halcon, Anadarko and Noble. Jeff Sieler, managing director for Citi, is also interested in EOG Resources Inc.’s plans to hold onto a noncore property—noncore relative to EOG’s vast Permian and other holdings.

It signed a DrillCo-type deal with The Carlyle Group LP this spring to develop acreage in western Oklahoma. Carlyle will provide $400 million. Most of its working interest will revert back to EOG after well performance targets are met.

For EOG to do a DrillCo deal is unusual, but not as unusual as if it had entered an operated joint venture (JV), which would have meant doing all of the work while paying for half to own half for the lifetime of the well. In 2010, EOG chairman Mark Papa, who has since retired and is now chairman and CEO of Delaware Basin-focused Centennial Resource Development Inc., told investors in an earnings call that EOG would sell its Marcellus leasehold rather than do a JV.

“ … Do we want to devote some of our scarce staffing level to, basically, educating someone else on a shale play and we do 100% of the technical work for perhaps a 50% net interest in the production or so? And we would just prefer to do 100% of the technical work. …,” he said, according to a SeekingAlpha.com transcript.

Sieler said the interest in a DrillCo “pertains to that these companies have a very deep inventory of highly economic locations. What they realize is that they have interesting drilling opportunities that simply will not prioritize in their capital budgets.

Jefferies LLC managing director Bill Marko said selling an oily IPO in the near term would be “super hard. They will be few and far between.”

“So, this is a way that they can get those opportunities drilled—and maintain operatorship. That is important for companies like EOG that pride themselves on good operatorship.”

Other operators may pursue the same tack. “I think those sorts of opportunities will be studied, and the only reason for bringing up EOG is because it is something that was announced,” Sieler said.

Yet Anadarko fully exited the Eagle Ford. “When companies look at these opportunities,” he said, “part of the analyses focuses on the strategic direction of the company.” In Anadarko fully exiting, “clearly there is a statement being made and it is that ‘The Eagle Ford is not our strategic direction.’ It’s a complete exit.

“They had obviously compared and contrasted that with other opportunities and saw more growth, more depth—whatever their metrics were.”

In the case of an E&P holding onto a noncore asset via a JV, it shows that “super-large independents in the unconventional space are starting to think of ways to monetize or bring that forward.

“There will be many other creative ways these companies that have decades of drilling inventory sitting out there are going to find ways to bring that forward.”

Minding the premium

Derek Detring, president of Detring Energy Advisors, has conducted several basin studies, analyzing deal metrics. Prices being paid in the Permian and the Scoop/Stack are warranted, he said. “Easily so.”

In terms of metrics, an exceptional one was ExxonMobil Corp.’s purchase of the Bass family’s holdings, which are primarily in the Delaware. “Ever since the oil price collapsed, people expected the super-majors, such as Exxon and Chevron Corp., to snatch up Diamondback Energy Inc. and Parsley Energy Inc, for example.

“What you see is public independents in the Permian were trading at $50,000 to $60,000 an acre on Wall Street—a substantial premium to the $30,000 or $40,000 an acre being paid in the A&D market.”

A public company purchase is even more expensive. If Diamondback’s public market valuation is $50,000 an acre, for example, and a buyer like ExxonMobil has to offer a 30% premium, “That takes them to $65,000 an acre.

“It’s hard to justify that in a board meeting, after running the assets through reserve models at strip pricing. But [the Bass’ operating entity] Bopco wasn’t public, so it doesn’t have that $65,000 [price tag]. It’s an excellent way to get a huge chunk in the Delaware without going after a public company.”

ExxonMobil paid with shares worth $5.6 billion at the time (mid-January) and is to pay up to $1 billion in cash between 2020 and 2032.

EOG also paid with stock (26 million shares) and cash ($37 million) for Yates Petroleum Corp., plus $114 million of net debt assumption. Matador Resources Co. paid for Heyco Energy Group Inc. with stock (3.14 million common; 150,000 preferred convertible into 1.5 million common) and $37.4 million of cash net of debt.

For the Bass family, “the Exxon deal is a pretty unique answer for them,” Detring said.

In another acquisition of a family company, but a public-for-public deal in this case, Noble paid for Clayton Williams Energy Inc. with 55 million shares and $655 million of cash. The deal was also in mid-January.

Parkman Whaling founding member Michael Hanson said the Noble-Clayton Williams deal is an example of “how, today, public company buyers have an advantage in the transaction marketplace.

Based on Noble’s share price at the time, it was $139 per Clayton Williams share. Citi’s Sieler noted that Noble’s share price improved 7% upon the announcement—an unusual bump for a buyer.

“A great deal of value was created by the acquisition of an under-capitalized company by a well-capitalized, highly seasoned unconventional operator. The market recognized that,” he said.

Parkman Whaling’s Hanson said the Noble-Clayton Williams deal is an example of “how, today, public company buyers have an advantage in the transaction marketplace.

“Nobody wants to sell at the bottom, so buyers who have the ability to provide additional consideration beyond cash, such as stock in a strong, well-managed public company, are more likely to compel sellers to transact.”

King also liked the ExxonMobil-Bopco deal. “The Bass family had such a big position. They elected to get out with some liquidity at some point. A deal you can do with a public company—where you get a currency so you can stay in or liquidate as you need it—is pretty good.”

Chevron and ConocoPhillips could buy as well, although “both have pretty big positions to exploit,” King added. “I could see them taking advantage of a private situation that has scope to it.

“It’s part of the culture to always be looking at things. But they probably will continue to explore what they already have—except for some tactical things.”

Upstream MLPs

Sieler said the Linn Energy Inc.-Citizen Energy II LLC deal this summer was interesting from a rock perspective. “Here were two companies that clearly took the risk of not having clearly delineated geology and, yet, acquired the acreage in an untested zone and reached the conclusion that it was profitable with a lot of drilling and development opportunities,” he said.

The deal created Roan Resources LLC, which Sieler said is “arguably the premier company in the Merge [play in Oklahoma]. The current production of 20,000 bbl/d can grow to over 40,000 by year-end. It’s something to keep an eye on.”

The basin itself is fascinating, he added. “The Anadarko is a very robust, stratigraphically stacked petroleum system that has been proven over the decades. I still think it has some growth to it.” With the Scoop, Stack, Merge and a northwest extension of Stack, “let’s get ready for some bigger deals to start popping up there.”

Marko noted that the MLPs’ divestments—Linn was an MLP—in the current deal flow are largely conventional assets. “Assets out of restructurings are hitting the market,” he said. “These will be $300- to $400 million at a time—not monster kinds of things.”

Detring said that, post-divestments, post-bankruptcy operators are “going to be very different companies.” Already, Halcon is transforming from holding assets in the Eagle Ford and Bakken to holding only a position in a new operating area: the Delaware. And there will be more to come, he said, most notably from former upstream MLPs.

Hanson said there will be more E&P bankruptcies at a continued sub-$50 WTI. “There are still some companies that have been struggling to repair their balance sheets and may finally file for bankruptcy.”

In addition, he said, with margins expected to be low, capital providers need to get creative to lower the cost of capital to profitably fund development activities.

“Private equity may be too expensive for some situations,” he said, “either due to the inherent risk or economics of the project, and commercial banks may be restricted in how much they can advance due to regulations.

“So, development funding will be left to creative capital providers to fill the gap. You’re seeing that with DrillCo and joint ventures. The industry is going to have to continue to go down that route.”

The IPO path

Meanwhile, several small producers, such as Gastar Exploration Inc., which has leasehold in the Stack, have enlisted the JV structure to help fund drilling. Meanwhile, Alta Mesa Holdings LP is using a DrillCo to fund its Stack development. It is planning to IPO, announcing in May that its S-1 was in draft. (At press time, myriad sources said Alta Mesa will be bought, instead.)

With the formation of Roan, Linn announced that it and Citizen plan to IPO the company in early 2018 subject to market conditions.

On the natural gas side, Vine Resources Inc. has filed its S-1, and Covey Park Energy Holdings LLC announced that its S-1 is in draft. Both operate in the dry gas Haynesville shale. Additional Haynesville operators are in draft, according to news reports.

But both oily and gassy IPO plans were in a holding pattern this summer. Atherton said the IPO market for oily E&P names is not receptive right now. “Permian companies have raised $18 billion in IPOs and follow-on offerings and, since, have traded downward, losing nearly $6 billion in value.

“It’s a big swing. They’ve lost a bunch of value on the potential for oversupply. The public markets may be more open to gas ideas.”

Marko said selling an oily IPO in the near term would be “super hard. They will be few and far between.”

Since Thanksgiving Day 2014, three E&Ps have gone public: D-J Basin-focused Extraction Oil & Gas Inc., Delaware Basin-focused Jagged Peak Energy Inc. and Eagle Ford- and Cotton Valley-focused WildHorse Resource Development Corp.

In addition to Vine, Anadarko Basin-focused Tapstone Energy Inc. has filed to IPO.

Otherwise in the upstream only special purpose acquisition companies (SPACs) have IPOed. Two priced in early 2016 and have already deployed their funds. Silver Run Acquisition Corp. and KLR Energy Acquisition Corp. both bought in the Delaware. The former acquired Centennial, which had an S-1 outstanding at the time; the latter purchased Tema Oil and Gas Co. and is now trading as Rosehill Resources Inc.

Five others have IPOed this year but not yet purchased: Silver Run Acquisition Corp. II, Kayne Anderson Acquisition Corp., Vantage Energy Acquisition Corp., TPG Pace Energy Holdings Corp. and Osprey Energy Acquisition Corp.

That the IPO market is closed to oily E&Ps right now may give the SPACs some negotiating advantage in winning what they want. “You have less conviction that [an IPO] is doable if oil prices are low,” King said.

Selling to an existing E&P that is off its share-price high can give an interesting additional upside, since “there is a chance for a kind of double bump as you ride up the value in the stock price with the addition of your assets.

“I always like that idea because it’s hard to get companies to use their equity when they think it is at a lower valuation.”

Marko said, “I think most people will sit tight unless they’re under duress or in the middle of a restructuring where selling isn’t an option. Sellers don’t want to sell at the bottom of the market. Is $45 the bottom of the market?

“[OPEC members] and Russia don’t want to cut anymore. It could get really ugly. If we’re grumpy at $45 and it goes to $35, all of a sudden $45 didn’t look so bad. I just don’t think it’s a great environment for equity issuance right now.”

Citi managing director Jeff Sieler believes EQT-Rice is “the first pitch in a nine-inning game.”

In-basin consolidation

As for gas, prices have stabilized at about $3 throughout the year, despite departing the winter-demand season. Yet, rigs being added in the Permian—particularly the Delaware—are expected to bring on increasing volumes of associated gas.

Atherton said, “If you can get it at a reasonable price, there are definitely people trying to buy gas assets because they think there is some upside there.”

A gas-on-gas example is the EQT-Rice deal, but that is more of an example of in-basin consolidation, he said. “EQT is scaling up to be the dominant operator.”

Sieler believes EQT-Rice is “the first pitch in a nine-inning game.” What stands out is $2.5 billion in operating-cost savings that are accretive on Day 1 to EQT. “I see that opportunity starting to become clearer in other basins. The industry had been waiting for something like that to occur. I think that is the first we see of many to come.”

Another in-basin consolidation is Sanchez Energy Corp.’s acquisition with Blackstone Energy Partners LP of Anadarko’s Eagle Ford holding. “To jointly acquire an asset of that size was remarkable,” Sieler said. “They’ve become a basin consolidator by being a low-cost operator.”

Investors may be shifting from funding returns more than growth. “What we see is the market is starting to recalibrate its view and starting to give value to companies that are well-capitalized with good execution metrics, large inventories and don’t necessarily have the growth story but have a clearly sustainable business in a core basin that can sustain commodity fluctuation.”

Decoupling gas

Gas at $3 isn’t $6, but it isn’t $1.64, which was the Christmas Eve 2015 price. Will capital markets decouple their view of gas from that of oil? Marko said, “There are some people thinking about that.

“I agree that $3 gas forever doesn’t sound awful. It sounds okay. I think some people, though, are asking ‘What’s the upside?’”

It could be interesting to a buyer that believes in more than $3.50 gas in the long term combined with deploying next-generation completion technology from oil fields to gas fields, he said. The shift is being made in the Haynesville, for example, and some “people are talking about Eagle Ford gas now.”

“What you see is public independents in the Permian were trading at $50,000 to $60,000 an acre on Wall Street—a substantial premium to the $30,000 or $40,000 an acre being paid in the A&D market,” said Derek Detring, president of Detring Energy Advisors.

But 20-plus MMcf/d wells could rapidly accumulate to 20-plus Bcf/d of additional volume, bursting the acquisition metrics. “It’s pretty easy to add volume.”

Demand buildout is continuing, and pipelines are receiving federal permits again. Marko noted that the U.S. shale revolution began with gas “and we found so much gas we ruined the price.” Producers shifted to oil “and now we’ve been so successful on the oil side” producers have done the same to the oil price.

But “the good side of the downturn in the last three years is it’s made the industry more and more efficient.”

Hanson said he has also seen increased interest in gas as new-generation recipes are being applied in gas basins. “Some of these gas assets are economic now. They weren’t a year ago, but the application of new technology has increased interest.”

Atherton said the Caerus Oil and Gas LLC acquisition in the Piceance Basin from Encana was an interesting deal. “The Piceance has been a somewhat neglected basin with lower gas prices, but Caerus has an incredible asset to work with and they have become the dominant operator in the basin, which will give them significant cost efficiencies.

“New technologies will evolve, and Caerus will be positioned well to take advantage of them with such a large acreage position.”

Sieler said that, with the demand buildout, more “deal flow will eventually happen.”

On both oil and gas fundamentals, King said the upcoming drop in Gulf of Mexico output as a result of reduced investment should offset growth from the Lower 48. A $50 to $60 WTI will bring private companies back into the market.

“The Gulf is set up for a succinct decline in the next few years. It will be a positive for prices.”

Shale drop-downs

Some unconventional-resource properties may begin making their way to income buyers. The horizontal Bakken play began in 2000; the horizontal Barnett, shortly thereafter.

King said, “We’ve created an inventory of tens of thousands of horizontal producers. They’re not stripper wells, but they’re certainly lower-rate. That whole inventory is going to be looking for lower-end income buyers.”

Buyers will be adept at artificial lift, restimulation, clean-outs—“all the things you do later in life.” The operators will be “producers we really haven’t seen in the horizontal world.”

Meanwhile, the divestments “will be a source of liquidity for companies to keep funding drilling,” while shedding the operating expense.

Buyers of large, mature, PDP properties this century had primarily been upstream MLPs. But, Detring said, this model likely won’t be reintroduced to prospective public investors in the near future. “People will need to have forgotten what happened in 2014.”

However, he added, “there is certainly a home for yield vehicles. While MLPs sometimes struggle as public entities—where they are incentivized to grow distributions at all costs—we anticipate seeing more private yield buyers pop up for income-oriented assets.”

Devon Energy Corp., for example, estimates a Delaware Basin section may host as many as 84 wells, so it may be a while before acreage there is ready for drop-down. But, King said, the Bakken may be appropriate. “It has less stacked pay and less inventory to explore over a longer period of time.”

Atherton agreed, adding that the Barnett and Fayetteville are also good candidates for a PDP-type buyer—an investment buyer.

“There are companies that don’t want to operate 1,000 wellbores that make 10 barrels a day each,” Atherton said. “If someone else does and can do it more efficiently, an operator can divest the assets to them and continue on to find and develop the next biggest, baddest play that meets their return on investment.”

Buyers could be firms like Merit Energy Co., EnerVest Ltd. and Sheridan Production Co. LLC—“privately held but operate at a low cost. They’re not going for the big bang, but, if they can operate all those wells economically and keep their capex low, it makes a lot of sense for them.”

Sieler said the Lower 48 unconventional business “is about to make a paradigm shift.” Actually, “I think it’s underway.”

In time, “there are an enormous number of unconventional wells making the fraction of the IP they were when they were completed. This is going to be consolidated into a highly profitable cash-flow business.”

The conversation will shift from spectacular IP headlines to focus, instead, on scale, operational efficiency, reservoir management, workovers, cleanouts, refracks. “Companies that excel at this will start blocking up acreage. It will be low-cost, high-margin production. I look forward to this trend.”

The Bakken play isn’t finished, though, Atherton said. It retains potential due because drilling hasn’t fully rebounded, while completion technology in other tight oil plays has evolved. Some operators are deploying the latest recipes, but work today is restricted to the core of the basin.

“When the oil price is higher, Bakken operators can apply those new techniques and technologies across the basin. Those companies are really going to increase in value and make a lot of bigger wells.”