Nonop E&P Strategies: In Search Of Superior Wells

[Editor's note: A version of this story appears in the March 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]

If running a nonop business sounds like you’re just along for the ride—a so-called “armchair operator”—then you haven’t met the professionals. True, it is the operator that makes major drilling decisions. But nonops exercise control in key areas: choice of basin, selection of E&P partners, opting in or out of wells and, in today’s data-rich environment, constantly searching for the best wells in the best basins.

In addition, nonop strategies have fulfilled a variety of goals in the past. Want to pursue a play ahead of forming a new E&P team? Then entrust the task to a nonop that is able to swiftly sift through well data and acquire nonop interests in the requisite play. Or, want an inventory of opportunities to develop over an extended period? A nonop can identify Tier 1 acreage and build key inventory in specific areas.

Another economic edge enjoyed by some nonops relates to extended billing cycles. Authorizations for expenditure (AFEs) are typically sent out by operators only as wells are spudded and call for payment in a further 60 days. This means that early well costs may be in large part paid from nonop funds, but a significant portion of the well costs may later be paid from revenues generated by the well.

“Everybody’s got a different strategy,” observed Mark Clemans, CEO of Carrier Energy Partners, a Houston-based nonop. “Do you want to have 2.5% or 3% working interests in hundreds or thousands of wells, so you can be diversified? That’s one way to do it. Another is to be concentrated in good areas, with good operators, with greater exposure, like we are.”

Nonop companies face a variety of challenges in the normal course of business, according to Clemans.

“Of course, we’re trying to make good decisions all the time,” he said. “We have to make an election on an AFE, just like the operator does. You can take that lightly or not, and we take it seriously. We look at every AFE, which means you have to have good data. Some of that is available publicly, but some depends on having a good relationship with the operator.”

For example, Carrier offers to share its type curves for wells with the operator whenever practical.

“We do a lot of work, and we just want to make sure we’re not missing something, to make sure that we’re aligned,” explained Clemans. “We’re willing to share our type curves with the operators and tell them what we think; they don’t have to share their type curves with us. What we expect in return is good data and good communications. You have to find that person who’s willing to help you.”

Clemans formed Carrier in 2009, bringing with him 20 years of industry experience from positions at Exxon Mobil Corp., Netherland Sewell & Associates, Sproule and Goldman Sachs E&P Capital.

With initial backing from a Houston-based Fortune 200 waste disposal firm, Carrier completed a series of nonop, working interest (WI) acquisitions with combined production of over 5,000 barrels of oil equivalent per day (boe/d). The acquisitions were aimed at providing a stream of cash flow that would serve as a natural hedge against rising diesel costs. The investor held onto the nonop holdings until last year.

‘Pivot’ To New Plays

As interest built in U.S. shale plays in 2013, Carrier Energy Partners LP (Carrier I) was formed with funding from Riverstone Holdings LLC.

“We convinced Riverstone we could ‘pivot,’” recalled Clemans. “There was a lot of money to put to work in the industry, and it was tough to form new teams quickly for all the different plays. If Riverstone needed time to evaluate the Utica and Marcellus, for example, we could still move forward in the play with the task of finding a good operator and doing our due diligence in the interim.”

Relationships with multiple operators were already in place, explained the Carrier CEO. “Then it’s just a matter of finding an opportunity to buy a working interest and make sure they’re aligned with us.”

Carrier I was able to attract funding of up to $300 million from Riverstone based in large part on work that Clemans had led at Goldman Sachs. This included “rigorous analysis” covering elements of geology, reservoir engineering, a financial analysis of the structure of the deal and the quality of the assets being acquired, according to Clemans. “That’s what my team brought to the table that they liked.”

Working with Riverstone partner Robert Tichio, Carrier Energy Partners II LLC (Carrier II) secured a second tranche of funding of $100 million in 2015. This was subsequently expanded to $400 million.

Initial Permian investments

The first investment by Carrier I was a joint venture agreement with Panther Energy II LLC. The agreement called for the two companies to develop 15,000 acres, mainly in Culberson and Reeves counties, in the Delaware Basin. Terms of the agreement provided Carrier I the right to participate through a 49% WI in wells drilled by Panther.

In early 2017, Carrier I closed the sale of its 49% WI in Culberson County to a private buyer. In addition, it sold its 49% WI in Reeves County as part of a previously disclosed $775 acquisition by WPX Energy Inc., which also included acreage and production in Loving, Ward and Winkler counties.

Prior to the Panther asset sales, Carrier I and Carrier II had engaged in a number of key acquisitions. For example, Carrier II purchased an approximate 30% WI in a joint venture with PT Petroleum LLC, based in Plano, Texas, and Midland-based Henry Resources in the Midland Basin. It also acquired an approximate 13% WI in the Sugar Loaf area of mutual interest (AMI) operated by Marathon Oil Corp.

Operated by PT Petroleum, the former project involves roughly 65,000 acres in Reagan, Upton and Crockett counties. Carrier II was brought into the project in light of a significant drilling commitment on what are largely university lands. Drilling and delineation operations have been “active” over the last couple of years, with primary targets in Wolfcamp A, B and C horizons.

80% Output In Eagle Ford

Investments alongside Marathon Oil in the Eagle Ford make up by far the largest part of Carrier’s current production, accounting for over 80% of total output of about 7,700 boe/d. Carrier II entered the play by buying assets in the Eagle Ford held by two Australian E&Ps, Empyrean Energy Plc and AWE Ltd. Of the two transactions, the latter was much larger, carrying a $190 million price tag.

“Riverstone didn’t have an operating team in the Eagle Ford, so this was a good way for them to get into the play,” recalled Clemans. “Plus, they liked having Marathon as the operator.”

With a staff of just seven people—and general and administrative (G&A) costs spread over 7,700 boe/d of production—Carrier is not carrying a lot of overhead on a per-barrel basis. Its staff includes a core group of engineers and financial analysts, noted Clemans, while accounting and land are largely outsourced. Consultants are used for some geology and reserve-based work for reports to the banks.

However, Clemans downplayed the likelihood of light G&A expenses providing a meaningful advantage for a nonop vs. an operating strategy. “If you’re in good rock and you have good performance from your drilling, the G&A component should not be a ‘make or break’ factor, unless you’ve built an empire,” he observed. “And you need to pay good people well whether they’re operating or nonoperating.”

As of mid-January, Carrier II still had dry powder to fund future investments. Carrier continues to see more attractive opportunities in oil than natural gas—even with oil pulling back into the $50s—and leans toward further investments in the Permian and Eagle Ford. However, Tier 1 acreage is tougher to secure, especially in the Permian, where much of the acreage is locked up.

Potential Emerging Plays

Clemans pointed to the Louisiana Austin Chalk as a potential emerging play, where entry costs would be lower.

“We’ve looked at a couple of projects in the Louisiana Austin Chalk,” he said. “We’re just risk-averse enough to wait for a few more wells to be drilled there—by anybody—before we can probably latch onto the play. It may cost us more to get in then, if it’s de-risked a little further, but we look to get exposure to plays like that. It’s certainly intriguing.”

While acknowledging the severe slowdown in the acquisition and divestiture market may have dampened expectations for near-term growth by nonops, Clemans was optimistic about the track record compiled by Carrier with Riverstone.

“Riverstone has been a really good investment partner, and we’ve made efficient decisions together,” commented Clemans. “Our role is to do a good job in evaluating the data and putting our conclusions in front of them.

“We can get on the phone and make good, quick decisions,” he continued. “And we’ve sent a whole lot of money back to Riverstone.”

As with Carrier, Vitesse Energy LLC’s partners, Bob Gerrity, CEO, and Brian Cree, CFO, dispel the notion that nonop “is easy, because it’s like ‘mailbox money’ with minerals.” Far from it, their business has been woven together from a mix of deep industry knowledge of the Bakken play, long-standing relationships with key basin operators, and a painstaking study of massive data on wells in the basin.

The results have been in many ways remarkable. At a West Texas Intermediate (WTI) price of $45 per barrel (bbl), and without hedging, Vitesse is able to generate earnings on a GAAP (generally accepted accounting principles) basis. This might imply a very mature asset with a heavily depreciated cost basis, but only about 10% of Vitesse’s reserves are in fact producing, with the remaining 90% of reserves yet to be developed.

Interests In Bakken Wells

Another eye-opener is the degree of Vitesse’s participation in recent drilling activity. While Vitesse has held only about 1% of the acreage in the Bakken in North Dakota, it has participated in between one-quarter and one-third of all wells drilled in the Bakken over the last several years, according to CEO Gerrity. “We picked our acreage well,” he commented.

Gerrity and Cree worked together earlier at Denver-Julesburg (D-J) E&P Gerrity Oil and Gas Corp. They have run 15 rigs at a time, drilled some 2,000 wells and operated 5,000 wells in their careers.

“Our competitive advantage is that we understand the operating side of the business,” said Gerrity. “We understand what operators have to go through. Most consider it a real hassle having to deal with their nonops. But we develop relationships, work with them hand-in-hand and try to make their jobs easier.”

Internally, Vitesse views itself as a “financial company,” with eight current or past CPAs in a total staff of 30, according to Cree. The CPAs work with the land department to do “forensic work,” which entails calculating what the Vitesse WI should be in a well and what Vitesse should get paid. “We do the work along with the operator, and then we let the operator have the benefit of our work,” he said.

Vitesse has interests in 5,000 wells in the Bakken, with an average 3% to 4% WI in each well, and keeps a decline curve “on every well in the Bakken—not just ours, but every well,” according to Gerrity. “We have an advantage in that we can see what every operator is doing. We can see which operators have better costs and more effective fracks. We have to know the Bakken as well as anybody.”

The history of Vitesse began in 2013, when Jefferies Capital Partners funded Vitesse Oil LLC with roughly $50 million. Shortly thereafter, Leucadia National Corp. (now named Jefferies Financial Group) acquired Jefferies. Vitesse Energy LLC was formed with a commitment of $300 million from Leucadia. An additional $150 million from Leucadia was committed in 2018 to help finance an acquisition.

Starting a nonop business focused on the Bakken was not an overnight idea, but rather an outgrowth of a multiyear, meticulous analysis of well data in the Bakken undertaken by Gerrity and his wife. This was in turn supplemented by learnings from developing acreage in the D-J Basin at Gerrity Oil and Gas.

“At the time, no one did nonop. Everyone thought that ‘nonop sucks, you can’t control anything.’ But what you can control is what you invest in,” said Gerrity.

‘Deeper, Denser, Cheaper, Better’

“The thesis Gerrity had going into the Bakken was that the play would get deeper, denser, cheaper, better,” recalled Cree. “When we originally got into the basin, the spacing was only four to six wells per DSU [drilling spacing unit]. This assumed just the Bakken and the first bench of the Three Forks.

“But based on what we learned from the D-J, we believed that over time there would be more wells per DSU, that there would be additional benches, that the EURs [estimated ultimate recoveries] would increase, and the operations would get cheaper as drilling and frack technology improved,” he continued. “The play got better, and that’s really why we did so well.”

As an example of improving technology over time, Gerrity cited the parent-child well relationship in the play. The typical parent well would have had a EUR of 600,000 boe in 2013 to 2014, he noted. By comparison, child wells today are likely to come in at an EUR of more than 1 MMboe, even though the spacing has become tighter in the interim, he said.

Vitesse has an estimated inventory of some 15,000 gross locations left to be drilled in the Bakken. This very substantial inventory is part of a “vision” the company implemented in deliberately focusing its investments on undeveloped acreage and, ideally, undeveloped core, Tier 1 acreage.

“This is the vision Gerrity brought to the Bakken,” said Cree. “When we talk about being undeveloped, we didn’t just fall into that; that was part of that vision. The vision was that it was better to be in an undeveloped play than in a developed play. If you think things are going to get better, with new wells drilled in the future, then focus your acquisition opportunities on undeveloped acreage.”

‘Vision’ Set On Undeveloped Acreage

The emphasis on undeveloped acreage—now standing at more than 47,000 net acres—actually helped protect Vitesse when WTI went sub-$30/bbl in early 2016, according to Cree.

“The beauty of Vitesse is that almost all the money we invested went into undeveloped acreage,” he said. “Yes, some of our PDP [proved developed producing] properties lost value. But our undeveloped assets really didn’t lose value, because during the timeframe that oil prices dropped, all the operators figured out how to get their EURs up and how to get their costs down.

“By the time they started drilling again, our undeveloped acreage was more valuable at $40/bbl than it had been at $100/bbl because of all the advances in operations. That’s how we survived,” he said. “Now, we can replace production and, at $45 to $55/bbl, still generate free cash flow because our wells are getting better and better.”

As little as roughly 10% of the Vitesse reserves are categorized as PDP, that is, producing, and even without the benefits of its hedge book, it generates net income at $45/bbl. The company estimates that at an average $50/bbl for 2019, it will generate about $40 million of free cash flow that can be either redeployed or distributed to Jefferies.

Vitesse is also attentive to G&A, although low G&A “is not what makes a winning company,” according to Cree. “Having lower G&A is a byproduct of having a well-run, nonop company. But not every nonop is going to have low G&A. You have to have that critical mass, too.”

Importance Of Scale

As it has sought to attain greater scale in operations, Vitesse has on occasion turned to parent Jefferies.

During the course of two years, Vitesse engaged in arduous, on-and-off negotiations that eventually led to the purchase of a package of nonop Bakken assets from an institutional seller in April of 2018. The purchase price was $190 million, of which $145 million was funded by Jefferies, with the balance being drawn under Vitesse’s credit line.

The assets being acquired were well-known to the Vitesse team and involved 4,200 boe/d of flowing production and 23,000 net acres. The purchase essentially doubled the size of assets owned by Vitesse in the core of the Bakken, in many cases simply raising existing WIs already owned in the play. More than 85% of the assets in the acquisition were undeveloped.

With an asset that clearly has long-term growth prospects, does the Vitesse team have a next milestone in mind?

“We have a wonderful long-term investor, who has allowed us to build a company for the long-term,” said Gerrity. “Scale is important; you do need scale. If we weren’t producing over 9,000 boe/d, we wouldn’t have the kind of net income that we have. We have a great company now, but we’re going to look to double our company again in 2019.”

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