At press time, the Brigham Resources LLC team was closing on its Southern Delaware Basin assets' sale to Diamondback Energy Inc. for $2.43 billion of cash and stock. The 76,000 largely contiguous acres had been amassed beginning in 2013 when leasehold in the area was going for less than $10,000 an acre. By a Tudor, Pickering, Holt & Co. estimate, the sale price is some $25,000 an acre, after deducting for flowing barrels, infrastructure and royalty value.
The first Brigham start-up, which was founded in 1990, was sold 21 years later for $4.7 billion in cash and debt assumption for its Williston Basin property. The second Brigham was being flipped in three years. Where to next for this and other start-ups and re-start-ups?
“Obviously, the cost to go back into the Permian would be greater today than was the case when we got in in 2013,” said Gene Shepherd, CEO, Brigham Resources LLC. “When I say this, I’m talking in terms of going back into the Tier 1 of the Delaware and Midland basins.”
When started, Brigham leased in what was considered fringe areas—primarily in northern and western Pecos County and in eastern Reeves, with Pecos largely unproven yet for economic horizontal Wolfcamp and Bone Spring wells. “We took on frontier risk,” Shepherd said. “There had been very little horizontal drilling in Pecos County at the time.” Mapping it, the team saw similar rock attributes as in northern Reeves and gained confidence that the odds of success were reasonable.
“You could argue that our willingness to take on some frontier risk allowed us to build the size of the position we built,” Shepherd said.
But a lower oil price today than in 2013 has “more eyeballs focused on fewer basins. Those frontier opportunities are going to be harder to find.”
Dick Stoneburner, an operator for more than 30 years and now a managing partner for private equity investor Pine Brook Partners LP, said, “There is a very, very nominal amount of what I call ‘leasing on the ground,’ meaning you’re getting it directly from the mineral-owner, in the Midland and Delaware basins. That is almost impossible to do today with any scalable fashion and with any contiguous aspect to it.”
A private equity (PE) investor would be looking for 10,000 acres or more or what can be grown to that level and all in the same geological zip code. “The only way to get that is to, typically, work with the existing owner of the leasehold,” Stoneburner said, “be it a small mom-and-pop operator out of Midland or someone who isn’t the legacy owner but doesn’t have the capital to develop it and, therefore, needs some help.”
Publicly held E&P buyers look at these as well, “but I think the big publics are more into the marketed-transaction process, just for efficiency of time. An aggressive, creative, newly started company would probably have a leg up on uncovering an opportunity like this,” Stoneburner said.
The existing holder would retain some remnant ownership to experience some upside and is usually required to pay for a portion of well costs. “That’s nothing novel, but the publics are more hesitant to have a small mom-and-pop as a partner with the uncertainty of its ability to maintain the capital exposure of a working or even a carried interest. Eventually, they have to pay. A start-up is more comfortable with doing that.”
Still, there are fewer of these today than a few years ago, he added, “certainly in the Delaware and Midland basins. People have been doing that right and left. Silver Hill [Energy Partners LLC], Luxe [Energy LLC], whoever you want to name: How do they get that initial start-up asset? They do something like what was described.”
Other basins
In contrast with the Permian Basin, the Stack area of the Anadarko Basin has more opportunities today, he added. “It’s still evolving, and it’s fraught with local independents that are undercapitalized and have legacy positions.”
Pine Brook has a couple of arrangements in the Midcontinent, most notably with Oklahoma City-based Red Bluff Resources LLC. “You have to be aggressive and lucky.”
In the Eagle Ford, Sanchez Energy Corp. was able in the past few months to lease 110,000 net acres: 65,000 in the western side of the oil window and 45,000 net in the western dry-gas window. The western oil window had been considered frontier by the industry. The dry-gas window had been fallow as natural gas prices began to plummet after 2008, but has become more interesting as new gas pipelines are being built to and within Mexico.
Bill Marko, a managing director for M&A advisor Jefferies LLC, said that, in terms of transaction activity, the
“Eagle Ford will be hot this year. One can already see an increasing build-up in deal flow there.” Economics have changed because of lower oilfield-service costs since 2014, he added—“which may not be sustainable; 2017 will be interesting to watch on the cost side.” Greater well EURs as drillbit targets and completion technology have improved also have changed the economics.
“The latter is really a big deal. It takes plays like the Haynesville from $5-per-MMBtu [million British thermal units] breakevens a few years ago to less than $2 today. There are also companies interested in everything from traditional Cotton Valley, the emerging Merge play (that is between the Scoop and Stack plays in Oklahoma), the conventional Midcontinent/Anadarko Basin, the Powder River Basin, the Marcellus. There is something for everyone.”
Chris Carter, a managing partner of NGP Energy Capital Management LP, said start-ups “are still likely to focus on the core basins that have the highest rate-of-return profile.” These would be the Permian, Scoop, Stack, D-J Basin and parts of the Haynesville, Marcellus and the Eagle Ford.
“Each play is at different points in its life cycle. The opportunities for leasehold and building a blocked-up position are greater in some areas than others.”
Another note is that, in the Permian, while there is a finite amount of surface, the subsurface is deep. “In the Delaware, we see a huge expansion in what people would define as the core, and there is a constant evolution of each of the distinct zones and what is the core for each of those zones,” Carter said. “There is enough rate of change in a big enough area. There is a lot to do there.”
Chris Atherton, president of asset-marketer EnergyNet.com Inc., said that, in the sub-$50-million A&D market, activity remains robust in the Midland and Delaware basins and in the Scoop/Stack areas. “It is not uncommon to see 10-plus bidders vying to purchase relatively small acreage positions. The plays are expanding as well, and new companies are trying to make wells work on the fringes of the core areas. And it seems to be working.”
Meanwhile, Atherton added, “the dominant players have a great deal of acreage, and they won’t be able to get to it all, so you see them selling off some tracts, and the PE-sponsored start-ups are eagerly buying it up.” Some start-ups are also building positions in the Eagle Ford, Utica, Bakken and elsewhere that public E&Ps are selling while building in other plays, he said.
Murphy Markham, a managing partner of EnCap Investments LP, said the Permian and Scoop/Stack continue to be targets of PE-backed operators, “albeit more expensive, so a more focused approach.” Lower drilling costs derived from lower service costs and, “more importantly, greater drilling efficiencies and continued enhanced-completion techniques are generating higher production rates and EURs, which are expanding the opportunity set for PE-backed companies.”
As oil prices improve, “other, more mature basins, such as the Eagle Ford, provide opportunities,” he said.
The next teams
While publicly held Sanchez has organically picked up more Eagle Ford acres via internally funded leasing, it is also adding leasehold via a PE joint venture. It and Blackstone Energy Partners are buying 155,000 net western Eagle Ford acres from Anadarko Petroleum Corp. for $2.3 billion. And other PE firms are buying in proven basins as well, NGP’s Carter said.
The point is that PE money is not investing only in start-ups. “If you look at the A&D activity in the Permian in the past 12 months, private equity has been the winning bid in several of those processes. It’s not just building leasehold positions and selling them to public companies.”
Carter doesn’t see a departure—even temporarily—in PE firms’ primary weighting to backing start-ups, however. “I think start-ups will still be the predominant way private equity invests in oil and gas.”
That is acquiring assets alongside a start-up management team and/or building a leasehold position and developing it with horizontal drilling. “I don’t see any kind of imminent end to that business model.”
Will PE investments in start-ups in this and coming years focus primarily on management teams that have done this before? Carter said, “Repeat teams will still be common, but I think you will continue to see that trend of teams being backed for the first time, especially among the younger generation of energy entrepreneurs.”
And investment will continue to be robust. “If anything, this downturn has shown the resilience of North American oil and gas companies and their ability to use technology to improve returns in a more challenged commodity-price environment.”
Stoneburner said the 2.0, if going back into the same basin it just exited, “probably needs to have a story. If $30,000 an acre is the market, how are you going to buy into the market? It is interesting to see who goes right back into the same basin and who decides to go somewhere else. I think there will be a little bit of both.”
In general, less PE capital will be committed to start-ups without a bird already in hand. Stoneburner said, “We, in particular, and I think the industry of private equity investing in general, are reticent to fund G&A for an extended amount of time without bringing a cash-flowing asset in the door.
“Even for a 2.0, that can be a little bit challenging. It’s a tough market to trade assets, other than, maybe, exploratory drilling acres and that’s not exactly what everyone is terribly interested in doing today.”
Estimates are that there is more than $100 billion of PE capital waiting to be deployed. Stoneburner said he is not sure what the number is. Whatever it is, “it’s a big number. We can all agree it’s a big number.”
EnergyNet’s Atherton noted that Kayne Anderson Capital Advisors LP and Post Oak Energy Capital LP have recently raised new, large funds. “They will need to fund teams— new or old—to put the money to work. New teams will have to present creative, specific, compelling strategies to the PE sponsor to get funding commitments these days. A strategy of ‘we’re going to buy in the Permian’ probably won’t cut it.”
Shepherd and the Brigham team may be one of the exceptions, but Shepherd said that “where to next” hasn’t been determined yet. “Obviously, our team has learned a lot—from our Williston and now, our Permian experiences—and we’d like to find an opportunity to benefit from the skill set that we have developed in being an early mover in early-stage shale plays.
At $100 per barrel, there was a much larger universe of opportunities to chase. At $50, “the heightened competition and resulting elevated acreage costs are going to create more of a challenge for private equity-backed companies with a higher cost of capital to build meaningful positions.
“With less of an economic ‘cushion’ to work with, we will have to be more discriminating with our early-stage leasing and drilling and completion capital,” Shepherd said.
A declining oil price in the latter half of 2014 had kept some competition out of Pecos County when Brigham was drilling its leasehold. “As we think about a restart of our business, our goal would be to find some new opportunity outside the fairway that others aren’t focused on—where there is some heightened level of risk relative to areas that have experienced horizontal drilling validation.
“We would rely on our people, our experiences and best practices to mitigate these risks.”
But with an improved oil price and “more eyeballs focused on fewer basins” than in 2013, “those frontier opportunities are going to be harder to find,” Shepherd said. “Because of the level of competition, I think we are going to look not only at the Permian, but outside the Permian as well.”
The greatest potential may lie in a team’s understanding of the rocks, in its drilling and completion expertise and in its leasehold’s stacked pay. “Attempting to move Tier 2 acreage into the Tier 1 category by using cutting-edge completion techniques is one obvious opportunity. However, the real opportunity will be the potential to test new drilling objectives and devise new drilling and completion techniques to make these new benches economic.”
The rock and the pay aren’t the same throughout basins. “Across a large geographic area, you may need to modify your drilling and completion formulas to generate comparable outcomes.”
Shepherd and Bud Brigham, chairman, did this in the Bakken, entering the Williston Basin in the mid-2000s and selling in 2011 for $4.7 billion. “We’ve been willing to take on frontier risk and do the heavy lifting, evaluating the resource attributes of the rocks and then turning drilling and completion ‘knobs’ to attempt to arrive at economic outcomes.
“This is a very systematic and deliberate process that can require a lot of time and capital. There are operators who are willing to take on this risk and come up with solutions for that variability. These operators are best positioned to source the next great shale plays.”
He concluded, “Three years from now, after starting our next venture, we hope that we will still be considered among this group of operators.”
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