Private Outlook

Bill Hall would have flipped his 30-well position in 60,000 South Texas acres by now, but buyers want packages with more proved reserves today than a couple of years ago. Meanwhile, Jack Vaughn isn’t surprised by the new oil pay the Powder River Basin is making, since the basin has been producing longer than the legendary Permian.

Paul Favret, who is making successful Mississippi Lime wells in Kansas, is also drilling for huge reserves in Colombia. Steve Antry, another Midcontinent driller, is working to hand off the reins to a new generation of oil and gas producers.

Recently, Oil and Gas Investor caught up with each of these private operators for an in- sider look at their plans, challenges and outlook.

Hall and colleagues formed Houston-based San Pedro Development LLC in the fall of 2010 after studying Fitzsimmons Field in Maverick and Dimmit counties in South Texas and seeing potential for a resource play there. Having al- ready drilled 30 wells in the San Miguel formation with San Antonio-based, privately held BlackBrush Oil & Gas LP, San Pedro received an additional round of funding in October from GSO Capital Partners LP, which is the lending entity of The Blackstone Group LP.

Hall, chief executive officer, had previously led driller NRM Energy Co. LP and then formed several small E&Ps focused on Texas reservoirs using 3-D seismic. “As time went on, there came the resource play,” he says. He and the San Pedro team hit the maps.

Investor Bill, how did you come to zero in on the San Miguel?

Hall It took about a year and a half to find something we thought fit our goals. We were looking for an area that had been under-drilled or technology-poor—where the owner didn’t have the time to work it and was spending its money on other areas, where we could bring money and technology and get something done with a good return.

Investor What is the nature of the formation?

Hall The San Miguel in our area is a big delta that covers about 70,000 to 80,000 acres. It’s fairly homogeneous. It has no water. It’s at about 4,000 feet and between 35 and 55 feet thick. When we looked at it, the field had 300 or so vertical wells drilled by a hodgepodge of promoters in the past 30 or 40 years. All oil wells. The average well produced about 10,000 barrels and about a quarter-Bcf [billion cubic feet] of gas.

We found one that someone had tried to do as a horizontal in the early ’80s and it produced almost five times as much oil with a single- stage frac as a nearby vertical well. A lot of people thought it was an Austin Chalk well; they didn’t realize it was a San Miguel well. We studied the cores and data and thought we had an excellent candidate to drill horizontally. We made a proposal to BlackBrush to, essentially, drill to earn an interest in the acreage and prove this concept.

Investor How is the arrangement working out?

Hall BlackBrush owns 50% of the project and is the operator. We each propose wells and work together to plan future drilling locations. We meet monthly and talk daily; it’s been a terrific relationship.

Investor Where does the San Miguel sit in the strat column?

Hall It’s just above the Eagle Ford. We have rights just to the base of San Miguel. In our area, Anadarko [Petroleum Corp.] owns [rights to] the Eagle Ford. Newfield [Exploration Co.] is north of us. Chesapeake [Energy Corp.] has been drilling east of us. This is not as prolific an area for Eagle Ford. It’s a little shallower; there’s lower pressure. But the wells are cheaper. I think they find the economics attractive.

Investor Where in the San Miguel are you landing the horizontals?

Hall We try to stay in the middle where there is the best porosity streak. We have 30 wells drilled now. We had to slow down during the winter; the area is one of the best deer hunting areas in South Texas.

But we’ve gone from drilling wells in 20 to 25 days to about 12 days. We’re also fracing the wells with oil and NGLs [natural gas liquids], using a Canadian company, GasFrac. In our area, water is scarce and expensive—both to bring it onto the lease and to get it off the lease. Also, using hydro- carbons to frac, you remove a lot of the issue of water and clay content. We’ve gone through 20 wells of fine-tuning our frac fluid. The beauty of it is we recover all of the fluid and sell it as oil.

Investor What lateral length are you using?

Hall They’re roughly 3,000 feet. Our goal is 10 to 12 stages per well. With pad drilling, we’ll have three wells [trending] northwest and three southeast. We’re at about 100-acre spacing right now. It’s a good, tight, regular-pressure sandstone that fracs very easily.

Investor What does reserve life appear to be?

Hall Twenty or 25 years, mostly oil. The [horizontals] have initial rates eight- to 10-fold over the vertical wells. The old verticals in the field started out at about 30 barrels a day; 30 or 40 years later, a third are producing a couple barrels a day, so there is a lot of oil in place.

Investor You’re entering your fourth year of drilling. What is the exit plan?

Hall The world has changed a lot since we started this. In those days, you could get a par- cel, drill a couple of wells and sell it for $10,000 to $20,000 an acre. In early 2012, we had four to six wells eight miles apart. That’s when the A&D environment started to change. The buyers shifted from paying the same price for all of the acreage to wanting to see you prove it throughout and set up the infrastructure. The buyers aren’t out there for a project that is only 10% developed.

We hired Rivington Capital [Advisors LLC] to bring in a $50-million, senior, secured credit facility in May 2012 to further fund infield development. I see more of a private-equity partner helping develop these projects in the future.

[Start-ups are] probably going to have to PDP 20-, 30-, 40% of their acreage to [sell it today] and the MLPs require up to 50%.

We’re looking at a later exit strategy. We’re shifting to the manufacturing mode now. Drilling costs will come down more than 20% on a six-well pad from our current two-well- pad configuration.

We think we can generate returns in the 50% range with six-well, pad drilling.

Every project is dynamic; you have to re-evaluate where you are every day and be able to react to a changing market to do what is necessary to optimize the value of your asset. I think that is a constraint of a good company and asset team to know when to say “no,” when to get in and when to get out. We had the market change on us; if we didn’t have partners who understand that, it would have changed how we operate our business.

Investor Do PE investors appear to be exercising good discipline?

Hall There is a lot of equity out there—a lot of new players and a lot of old players. They’re still picky. I haven’t seen or heard of deals where I’m thinking “How did they get that money?” And that’s good. When there is overzealous financing, it just hurts us operators the next time around because everyone is more wary—even when it’s a good deal.

Jack Vaughn, who co-founded Peak Energy Resources Inc. in 2002 with a $55-million initial commitment from Yorktown Energy Part- ners LLC, launched his fourth version, Peak Exploration & Production Co. LLC, in 2011 after $989 million of divestments in the Texas Panhandle, Barnett, Bakken and San Juan Basin. For a new asset, the team looked at the Permian Basin’s Wolfcamp and the Anadarko Basin but settled on the stacked-oil pay of the Powder River Basin.

Their horizontal Iberlin 1-10 TH in Campbell County, Wyoming, came on this past summer with 2,607 barrels of oil and 4.3 million cubic feet of wet gas a day. Vaughn, chairman and chief executive officer of the Durango, Colorado-based company, adds, “And we’ve had other wells, including one we brought in this week, that are about as good.”

Investor Jack, you looked at the Panhandle and the Permian. How did you come to focus on the Powder River Basin?

Vaughn We made some small wells in both areas but they fell short of our expectations. We were in the fringe of the Wolfcamp. We took a step back. [Peak president] Glen [Christiansen] and I both had experience in the Powder. It’s a long-known, hydrocarbon-productive basin. We got in there early enough and our early re- sults were quite good. We decided we’re better served by focusing there.

Investor Prior to the past couple of years, it had been unusual for formal private equity to invest in exploration models.

Vaughn The acquire-and-exploit model works for some companies. We’re pretty en- trepreneurial and we have an outstanding technical team for exploration and exploitation. Our investors have been happy with the outcomes we created for them in the past and are willing to take on higher-risk, higher-return projects.

Christiansen But I would be reluctant to call what we’re doing in the Powder exploratory. We’re using new technology in a basin that is fairly well understood. There’s a huge database of wells there. What we’re doing in the Powder is taking unconventional technology and apply- ing it to more conventional reservoirs. Does that constitute a type of exploration? Maybe, but it also is a type of exploitation.

Investor Peak’s journey began in 2002. What’s different today?

Vaughn Acreage prices are pretty high, com- pared with their historical cost. We look at the overall economics of projects—the cost of land, the reserves, the revenues. The cost of land is not as big a component as you might think. When you’re drilling $7-, $8-, $9-million wells, that’s what you’re thinking about. The allocated cost of land isn’t a big mover. But it does cost to play these days. It really does.

Investor Yorktown has backed all four Peaks.

Vaughn Yes. They’ve stuck with us. In November 2002, there really weren’t as many private-equity firms providing capital. Access is probably better today. You need to be a very experienced management team with a good track record, so I think it is better today for Peak because of our track record. In 2002, we weren’t well known. It took us about a year to get the money.

Also, The Hillman Co. in Pittsburgh co-invested in Peak along with Murchison Capital [Partners LP] and Tecovas [Partners LP]. We’ve had a long relationship with them. They’ve been very solid backers like Yorktown has as well.

Investor The price of poker has gone up.

Christiansen It has. You have to look at the type of wells that we’re drilling today. We were drilling vertical wells [during Peak I] in the Granite Wash for $1.5 million and they were very good wells. We were drilling horizontal wells in the Barnett for $1.4 million [during Peak II]. Now it isn’t uncommon to go out and drill $7-, $8-, $9-million wells in the Powder River Basin.

Investor Can you compete with larger companies for services?

Vaughn We do. We take advantage of the relationships we’ve built over the years. And we make sure we pay like a slot machine. We pay our bills very promptly and that helps us not only with the small companies—the water haulers and the welders—but it also helps us with the larger companies. We’ve built a reputation of being very good to work with; that really helps us.

Some contractors over the years have preferred to work for us; we make decisions quickly and always do what we say we’re going to do. And we try to have a predictable program—not drilling two or three wells and shutting down for six months.

Investor Jack, you had the courage to leave a major oil company in the 1970s when a job like that was viewed by many as a retirement plan.

Vaughn That so-called “security blanket” was one of the big attractions of working for a major. But at the end of the day, individual security is drawn from one’s own intellect, ambition, entrepreneurial spirit and integrity. I wanted the opportunity to do more. In the majors, you tend to get slotted in particular disciplines and I wanted to learn it all. I wanted the opportunity to fly and not walk.

Investor Are you surprised that U.S. independents have led the production renaissance?

Vaughn I didn’t have to be clairvoyant. As a consultant after 1973, I was working for independents and was able to observe their ability to make plays work. I saw something in the in- dependents. Back then, probably 85% of U.S. production was by independents. There was a reason for that: They’re risk-takers and willing to put their money where their mouth is.

Investor And you’ve stayed with the private model.

Vaughn What we found in the private world was more suited for our culture and personality. We focus on execution. I thought we could be successful and we never looked back.

Investor Peak IV is entering Year 3. Are you readying for another exit?

Vaughn It’s an ongoing process from the beginning. The market tells you when it’s time to go. You just need to be ready when that time comes. We have a lot of excitement and confi- dence in the assets we’re developing in the Powder River Basin. The results have exceeded all of our modeling.

Investor You were early in the Barnett, early in the Bakken, early in the Powder. Lucky?

Vaughn Luck is a result of design. When we move into an area, we do everything we can to evaluate the risk and come up with ways to mitigate it. We study it very hard. I’m very proud of our technical team. It doesn’t always work— like where we were in the Permian—but we look very hard at the risk going in and we don’t mind being early in a play.

Christiansen We also pick states that embrace and understand oil and gas development— Wyoming, North Dakota, Texas. That helps us achieve our plans. We work very hard to be compliant. We don’t need to rewrite the rules; we just need to follow them.

Paul Favret formed Source Energy Partners LLC in 2010 to develop resource plays in the U.S. and abroad after working these with his Aspect Abundant Shale LP. Today, Source operates in the Mississippi Lime in Kansas and in the Middle Magdalena oil basin of Colombia, “which you will hear a lot about during the next 10 years,” the chief executive officer says.

As for shale-play attempts in Europe, the Highlands Ranch, Colorado-based E&P exited these, profitably selling a 380,000-acre concession in Poland and an 80,000-acre concession in Germany. In the former, economics were poor; in the latter, government sentiment was poorer. “We were looking at a decade-long battle to be allowed to stimulate the rock.”

Investor Paul, did you move directly from Poland to the Mississippi Lime?

Favret We had the project in Germany— 80,000 acres. Although the economics were highly favorable for an oil-resource play, we ran into a political headwind that would prevent us from fracing. A public company wanted it on their books to advance a hope and a prayer; they bought it at a profit to us.

Investor Wells had been fraced in Germany in the past.

Favret Yes. I have a pet peeve about the word “frac.” We don’t crack anything; we dilate and prop it. An offsetting hydrothermal company’s fracing operation caused community concerns, leading to the moratorium.

Investor You’re invested in Colombia now. Any hysteria there?

Favret In Europe, the concerns and encumbrances are unbelievably over the top. In Colombia, we are dealing with what appears to be a very rational group. They seem to be moving in the right direction but are very cautious after the BP [Plc] Macondo incident.

Investor Is that pushback abroad because surface owners are not mineral owners in most other countries?

Favret Yes. The landowner is highly incen- tivized to prevent development since all of the royalties and tax revenues go to the host gov- ernment. Here [in the U.S.], citizens are able to speak to common sense because they can par- ticipate in wealth creation.

Investor Who is your private-equity partner these days?

Favret Pine Brook [Partners LLC] and Soros [Strategic Partners LP], which is affiliated with Pine Brook on energy investing. We also have some smaller[-percentage] investors—Stanford University, the University of California and GE Asset Management—through Pine Brook.

Investor You’ve been a private operator for 20 years now. Is it enormously easier to get funding today?

Favret There is more private equity available in the upstream-energy space, specifically on- shore, than has ever been available in history. Capital for good projects is not lacking. It could be that we’re starting a path that feels like a bubble of private equity for onshore, upstream- energy themes. It seems there is an overabundance of capital compared with high-probability and -profitability projects. I’m concerned that a lot of money will go to work on noncommercial projects and it’s going to give private equity a bad name.

I am concerned that returns that have historically been greater than 25% will become more elusive unless there is a major oil-price increase, which we are not likely to see. The first day of 1999, oil was about $12; it’s $100 now. We can’t expect an eightfold increase going forward; it will likely stay flat to declining.

Investor What about the PE firms that have been at it longer?

Favret The days of the land grab, riding the development wave and flipping the acreage at multiples of 10:1 or better are materially over. A lot of opportunity still exists, though, for the [E&P] teams that are developers with a specific focus area that can not only secure acreage but drill and convert it into a producing, revenue- generating asset.

And, then, there is this new regime of financial engineering due to low interest rates, creating the ability to sell to an MLP or royalty trust willing to pay PV-7 rather than PV-12 for those producing assets. We’ll see more and more of that in the future.

Investor What does it cost to get a Bakken-size frac spread into Colombia?

Favret The Bakken and the others require 38,000-plus horsepower and 15,000-pressure iron. The price tag on that spread is roughly $45 million. We’ve built rigs and brought them into other countries—Hungary, Belize. We never moved a frac crew in. You need enough activity to justify bringing it in. Generally, one frac fleet can service four rigs; somebody has to pay for when it’s idle and, ultimately, the customer does. Some of the early, high-intensity frac jobs can cost $1 million a stage, such as in the emerging Vaca Muerta oil play in Argentina.

Investor You picked Colombia over Argentina.

Favret We find Argentina unfavorable due to that they have a long track record of changing the law and they will do it with a moment’s notice. They also have a ceiling on prices and the service industry is dominated by unions that are prone to strike and, at times, destroy equipment. It’s a very unfavorable place to do business.

Investor What are you working on right now in Colombia?

Favret We’re in a farm-in in 100,000 gross acres in the Magdalena Basin. We’re surrounded by Exxon[Mobil Corp.], [Royal Dutch] Shell and ConocoPhillips. We hope to drill two new resource wells this year. It’s the Cretaceous-age La Luna and Rosa Blanca formations in a roughly 3,500-foot section of oil-rich rock dominated by shale and carbonate sequences.

Harken [Energy Corp.] drilled two horizontal wells in ’97 and ’98 that were very successful. Each of them produced approximately 700,000 barrels of oil—unstimulated. One lateral was about 1,250 feet; the other one was approximately 4,000 feet. It’s slightly overpressured and the depth is between 6,000 and 15,000 feet. Our first well will drill to approximately 14,000 feet, testing seven resource zones.

Investor And in the Lime?

Favret We have approximately 340,000 net acres in the oil window in Sumner, Sedgwick and Butler counties [in Kansas]. This play is re- ally being struck down by bad news, with Shell exiting. They have invested substantial capital in the play, mostly in land; they’re probably facing a write-off of well over $1 billion. These majors struggle to compete in this onshore-re- source arena. The only way for a Shell or an Exxon to have a chance is to buy an independent that already has the processes and cost controls, etc., in place.

Shell’s first wells in the Lime cost over $10 million each, on average, fully equipped—drilling, completion, facilities and saltwater disposal. We’re in the same area, averaging $3.2 million. We’re seeing the same thing in Colombia. The first vertical wells in the La Luna resource play are costing majors more than $25 million; our similarly equipped wells should be roughly half that price.

Investor What else is a concern?

Favret We created an oversupply of gas and drove prices from $9 to $4 and there is a risk that we are going to over supply oil. Just a perception of that has reduced oil futures. That’s one of my fears. And, because of the abundance of capital creating that supply, it could get a lot worse, especially if Asian demand weakens.

Steve Antry took his Midcontinent-focused Beta Oil & Gas Inc. public in 1999 and sold it in a reverse merger in 2004 to Floyd Wilson’s start-up Petrohawk Energy Corp., which was sold to BHP Billiton Ltd. in 2011 for $15.1 billion. Currently, Antry is building a third Midconti- nent-focused E&P with his Tulsa-based Eagle Energy Exploration LLC. His second, Eagle I, was sold to Midstates Petroleum Co. Inc. for $325 million in cash and $325 million of preferred shares in 2012.

Investor Steve, after selling Beta to Floyd, what were you working on?

Antry From 2004 to 2008, I was involved in the well-service side. I consolidated several mom-and-pop companies, automating the office side and reducing the average G&A per area. I handed off management to another local industry player when I started Eagle I at the beginning of 2009. The resource plays were coming into full stride; I felt that I might have missed this paradigm shift but it motivated me to get back into the E&P side.

Initally, I was attempting to consolidate the horizontal Hunton Lime play. It turned out that one of our key acquisitions had a substantial undeveloped position right in the heart of the emerging, horizontal, Lime play. The Hunton quickly turned into our secondary objective.

Now you have the “Scoop” and “Stack” plays. We’re looking across Oklahoma, having started with a shotgun approach and now more with a rifle. We know where we want to be. It’s been interesting to watch new areas heat up. We like the Midcontinent because the numbers are strong. It’s not quite as sexy as plays like the Bakken and the Eagle Ford so it’s somewhat less competitive.

Investor You have to invent a neat name for it.

Antry I know! I really like [Continental Resources Inc.’s] Scoop. What a great acronym [for South-Central Oklahoma oil province]. Stack is an acronym as well; some people may have thought it simply meant “stacked pay.” Our senior geologist, Bob Gaddis, named it while he was at Newfield. It is “Sooner-Trend, Anadarko, Canadian, Kingfisher.”

Investor Do you have acreage yet?

Antry We do and we should be drilling in the Scoop by the time this goes to print. It’s somewhat challenging to get leasehold now from scratch.

Our current strategy is to supplement boots- on-the-ground acreage accumulation with aggregating smaller operators who are deciding whether they want to raise the larger capital required to drill $7- to $9-million wells. We plan to make a series of $10- to $50-million acquisitions and aggregate those operators who have been successful vertical drillers but want to pass on the high-dollar, horizontal wells.

What we promise and deliver is that their assets will get our full attention and capital commitment. We aren’t in the business of just building an inventory of leases that we might never drill; we’re in the business of drilling wells and building production. That commitment is getting us some quick traction. We would like to have 10 rigs working before we exit 2014.

We’re also working on several more-sizeable deals. There is no reason we can’t pull up a chair at any table for those, thanks to our financial partner, Riverstone [Holdings LLC]. These deals are very competitive. There is just so much capital out there that still needs to be deployed. The large-deal task is more challenging in that the big acreage grab has already taken place in these large resource plays.

Investor You used private equity to finance Eagle I.

Antry It was the first time I had really worked with private-equity money. I found it to be a very pleasant experience. Riverstone is an excellent financial partner with a general principal of only backing one management team in each geographic area. We are their sole upstream, Midcontinent team and we like the strategic edge that gives us.

In Eagle I, most of our growth was through the drillbit so we didn’t have to draw as much equity as Riverstone made available to us. It was a $150-million commitment but we didn’t need to deploy all of that because we could fuel our growth with producing reserves, cash flow and our bank facility [led by Société Général]. The commitment to Eagle II is $300 million. Riverstone has confidence in their legacy management teams; if you perform extremely well in the first deal, the confidence is, obviously, much higher. If we have a viable project be- yond that number, I’m sure Riverstone would accommodate.

Investor Are you interested in IPOing again?

Antry Beta was one of only two oil and gas IPOs in 1999. That was the year of the dot- coms; we were told repeatedly, “Too bad you aren’t Beta.com.” Oil was $12 a barrel. It is mind-boggling how the business has changed. In the 1990s, you were running expensive seismic, looking for complicated traps, drilling salt domes; it was heavy on the “E” and challenging to create the “P.” It was tough to build a company that way; you were having to take astro- nomical risks on what would often be low-yield projects.

The resource play requires a lot of capital commitment but the lower-risk component has changed the game for everybody.

Sourcing capital is still my real forté. Going to the public market is always expensive initially, but there is no doubt that the “public premium” is often worth it despite the hassle, and we are always looking for a good liquidity event. My preference is always to move onto the next project, so I would never shy away from a public exit if it made sense.

Also, the folks I hired for Eagle II, most were part of Eagle I but there are some new faces. I think we have created a great roadmap for success and the framework for Eagle III to be a hand-off to an extremely talented, younger, hungry team. There had come to be a real gap in talent in the industry.

This new group [in Eagle II], they're averaging 32-ish [in age] and already have 10 years of intense, resource-play training. Each would be more than credible in a public-company environment. They’re already having a positive influence on this industry.