Private Equity Raises $250 million for Houston Upstream Company

Hibernia Energy III, LLC (“Hibernia III”) is pleased to announce it has raised $250 million of new equity commitments from NGP through NGP Natural Resources XII, L.P., the most recent NGP private equity fund focused on natural resources.

 

In addition to the commitment from NGP, Hibernia management and members will be committing in excess of $21 million in equity. Hibernia III’s strategy is to acquire and prudently develop unconventional oil and gas assets in Texas, leveraging its proprietary relationships and operational expertise. The Houston, Texas based Hibernia team previously acquired, operated and developed assets in Martin County, Texas within the Midland Basin, divesting assets to both Athlon Energy and Eagle Energy Trust.
Hibernia III is led by P. Embry Canterbury, Sean Keenan and John Blevins. Embry previously co-founded Hibernia Energy, LLC (“Hibernia I”) and Hibernia Energy II, LLC (“Hibernia II”), which originally partnered with NGP in July 2010 and May 2013. Embry will be joined by Sean Keenan and John Blevins who will act as CFO and COO, respectively. Additional management team members have served in various roles at Permian-focused companies as reservoir engineers, operations engineers, geologists and land and business development managers. Carl Carter III, who co-founded Hibernia I and II, will act as a Strategic Advisor to the Hibernia III team. The senior management team has developed a strong track record in the Permian and other unconventional basins throughout the United States and brings 60+ years of industry experience to Hibernia III.
P. Embry Canterbury, CEO of Hibernia III, commented, “After two successful partnerships in the Midland Basin, we are excited to again be working with NGP on building another oil and gas company focused on creating significant value for our partners and team members. We believe there are tremendous opportunities in today’s market to acquire, develop, and realize value in multiple, unconventional resources and we have assembled a best-in-class team to execute this strategy.”
“NGP is excited and grateful to partner with the Hibernia III team,” Patrick McWilliams, Partner at NGP, said. “We are thrilled to get to work again with such an energetic, disciplined and skilled company and could not be happier to continue the partnership. We have known Embry and the Hibernia III team for years, and respect the dynamic culture, top-tier operating capabilities, and deep local relationships that will make Hibernia III truly successful.”

Private Equity Scooping Up Billions In North Sea Assets

There is confirmation it’s “money on” right now in the global petroleum sector — with one of the biggest single deals in years coming down in an unexpected place. From a virtually unknown acquirer — which has instantly become the largest independent producer in the neighborhood. That’s a London-based firm called Chrysaor Holdings. Which yesterday unveiled a $3.8 billion purchase of North Sea assets from Shell.  

Under the deal, Chrysaor is buying Shell’s working interest in seven North Sea projects. Coming with a current 115,000 b/d of oil equivalent production — plus another 13,000 b/d production in the Shetland Islands, which is expected to be onstream soon.
 

In total, Chrysaor will acquire 350 million barrels of proven and probable reserves — making the firm the largest U.K. independent producer focused on the North Sea. In fact, one of the largest producers overall in this area. Here’s the most interesting part: the deal appears to have been orchestrated by private equity backers.

With Chrysaor paying for the assets partly through a $1 billion investment from PE outfit EIG Global Energy Partners. That’s a very telling move, given that EIG is a Washington, D.C.-based fund that has to-date focused on U.S. oil and gas projects — with some stepouts to Australia and South America. But now this big buyer want to take a run at the North Sea. Suggesting management sees potential in this mature basin, even as majors like Shell exit in favor of higher-impact plays. This is much like what happened in the U.S. Gulf of Mexico shelf the last few years. Where majors like Chevron sold big asset packages to private equity-backed E&Ps. It will be critical to see what happens next. If new kids like Chrysaor can indeed grow production and reserves, it could encourage further PE purchases of mature assets. Watch for operational updates from the North Sea’s new leading producer.

U.S. Shale Sees Rebound In 2017 Mostly From The Permian

The oil industry invested more than $28 billion in buying up land in the Permian Basin in 2016, three times the amount spent in 2015, according to Reuters. That accounted for about 39 percent of all money spent on land acquisitions in the U.S. oil industry last year. Other shale basins do not even come close to that level of investment. By way of comparison, the Marcellus Shale attracted 10 percent of total land investment in 2016, while the once-hot Bakken only captured 3 percent.

Money has flooded into West Texas because the Permian has both below-ground and aboveground advantages over other shale basins. To start with, the Permian has a vast volume of oil waiting to be tapped. But more importantly, it is geologically favorable for drillers – multiple shale formations are stacked on top of each other, which means that a driller can sink a vertical well through several shale plays at once, and then drill horizontally through even more liquid-rich shale. More oil per given well means lower breakeven costs and larger profits. All else equal, that alone is enough for shale companies to concentrate their efforts on the Permian at the expense of other shale basins in the U.S.

But then there are above-ground factors. Texas is a friendly place for oil companies. West Texas has seen drilling for decades, which means that pipeline networks are established and well connected. Reuters notes that Texas also enjoys abundant labor and equipment suppliers, also a legacy of a long oil history. Plus warm temperatures mean that drilling can take place 365 days of the year.

It is no surprise then that over the past two years the Permian has emerged as the favorite for shale drillers. Since the U.S. rig count bottomed out in May 2016, the industry has added 250 oil rigs back into action through the end of January – the Permian accounted for 154 of those, or more than 60 percent. No other shale basin comes even remotely close to those gains.

“We could easily see an extra 100 rigs out here in the Permian by June,” Josh Clawson of Gesco, an electrical contractor for oil drilling rigs, told Reuters.

The surge in interest in the Permian continues to push up land prices. Companies are paying more than $60,000 per acre, double the average paid back in 2014, and even twice as high as some deals signed in 2016. High land prices are not scaring away companies; interest in the Permian continues to rise.

This is the reason that ExxonMobil just paid $5.6 billion in January to double its acreage in the Permian Basin, which was the largest oil deal in the U.S. since prices started to spiral out of control in November 2014. Exxon just reported fourth quarter earnings this week, which showed that overall production declined by 3 percent from a year earlier. The oil major is stepping up capex this year, unlike many of its peers, in order to reverse that decline in output. The Permian could be key for the company, where it hopes to add more than 200,000 bpd in production, taking its Permian output up to 350,000 bpd. As the FT notes, that would mean that the Permian makes up almost a quarter of Exxon’s total production, sharply up from 12 percent today. For a company that has a long track record of taking on hulking, complex offshore drilling projects, the pivot to smaller shale wells in Texas speaks volumes about how enticing the Permian has become.

The big question is how the rush for land in the Permian changes as oil prices rise (assuming that they do). The Permian has benefited from the severe cuts to spending and drilling activity in rival shale basins, as companies concentrate their efforts in the West Texas shale basin. But if oil prices rise to, say, $60 per barrel, places like the Bakken and the Eagle Ford could come surging back. Of course, rising oil prices will only improve the economics of the Permian, but it could lose its status as the only game in town.

On the other hand, there is no guarantee that oil prices do rebound. There are plenty of reasons to think that they won’t, and could in fact decline. For now, the EIA is forecasting flat oil prices for the next two years, which would be high enough to allow for an impressive uptick in production by 400,000 bpd, jumping to 9.3 million barrels per day in 2017. However, with annual average production rising from 2.0 to 2.3 mb/d this year, most of the gains in U.S. output will come from the Permian Basin.