Tom Armistead of The Energy Report
John White has initiated coverage on several small-cap exploration and production companies in the Permian Basin, the latest of the major basins to turn in a big way from vertical oil and gas wells to horizontal fractured wells. In this interview with The Energy Report, the ROTH Capital Partners senior research analyst names five Permian players on his list of favorites.
The Energy Report: John, what are the main influences on oil prices today?
John White: We don’t believe what we are seeing with the oil price drop is a case of decreasing demand; what we have here is oversupply.
To give you some historical context, for the first hundred years of the oil and gas business, the industry drilled vertical well bores into what we call conventional reservoirs. Around 2000, advancements in horizontal drilling technology and fracture completion technology allowed the industry to complete strong wells in the shale formations, called unconventional formations.
The improvements in efficiency and productivity have led to an increase of about 3 million barrels a day (3 MMbbl/d) of U.S. oil production, off a base of about 6 MMbbl/d. In the last three years it’s been about 1 MMbbl/d each year. That’s 3 MMbbl/d the U.S. does not need to import from overseas oil producers, so you have more oil on the market. The market realized there was this surplus midway through 2014, and prices reacted to the downside.
TER: How are international developments, like a new king in Saudi Arabia and conflicts in Libya and the Middle East, affecting the West Texas Intermediate (WTI) price?
JW: The international oil price is what we call the Brent oil price, and the U.S. domestic price is the WTI price. International geopolitical events affect both oil prices, but tend to affect Brent more.
We are focused on the fundamentals of supply and demand, so we don’t have any extraordinary insights into the political dynamics within the Organization of the Petroleum Exporting Countries (OPEC). We try to stick with the numbers, although we do keep a close eye on Libya. Libya has been offline, online, offline at various times since the Arab spring of 2011. It’s certainly an influence. Libya has capacity of 1 MMbbl/d, but right now it is offline, and I don’t believe it is exporting very much oil.
TER: Resistance to hydraulic fracturing has been stiffening in Colorado, New York and even in Pennsylvania. How will that affect shale oil production?
JW: From the press releases and the news reports I’ve read of this resistance movement, it’s mainly municipalities that are reacting negatively to hydraulic fracturing. From an industry standpoint, the development of oil and gas mineral rights has, since the inception of the industry, been governed by the state authority. If there is a legal battle, the municipalities do not have, in my opinion, precedent on their side.
TER: As you know, Governor Cuomo in New York has said there’s not going to be any shale development at all in New York. Is that a major blow to the industry?
JW: I think it’s more of a blow to the residents and the workforce of southern New York, because they are on the border with Pennsylvania. Industry people tell me if you’re on the Pennsylvania side of the shale play, you see an awful lot of New York license plates because people are finding work in Pennsylvania and not in New York. Because state law governs development of oil and gas, the governor is within his authority to ban fracking. The Colorado and Texas state governments are much more pro oil and gas. They are enjoying such a tax revenue benefit from increased oil and gas production. I don’t think you’re going to get much pushback at the state level.
TER: The recent oil price rally has been a surprise. What causes do you see for this upswing?
JW: In the last week of January, you had the expiration of the current month oil futures contract, and that caused some people to cover their short interests in crude oil futures. The buying for the short covering moved up the price of oil. That, in turn, moved up the prices of the equities, which resulted in more short covering. On Jan. 30 we saw the rig count numbers, which reflected one of the bigger decreases in the land rig count that we’ve seen. The industry idled 86 rigs in one week. I think a lot of people took notice. The rig count seems to be falling a little faster and a little harder than originally anticipated. That optimism carried over with higher oil and gas prices and equity prices, at least for the first few days of February.
TER: What are the main influences on natural gas prices today?
JW: Again, that’s a supply-driven situation. Because the North American natural gas market is not a global market, it’s a little easier to wrap your arms around. Quite simply, we’ve had a large increase in natural gas production, primarily from the Utica and Marcellus shales. It was much greater than the increase in demand. As a result, you’ve had prices go from around $4 per thousand cubic feet ($4/Mcf) to the more recent $2.80–2.90/Mcf.
TER: What’s your forecast for oil and gas prices for 2015?
JW: For oil, our average price is $56.25/barrel ($56.25/bbl) for WTI, and for Henry Hub natural gas, $3/Mcf.
TER: Has that changed in the last month as a result of the price builds?
JW: We actually took our forecast down. We had a $75/bbl WTI forecast and a $3.50/Mcf natural gas forecast. That forecast was issued on Dec. 2. At the time, it actually looked a little conservative. Certainly, we didn’t get a lot of pushback. Since then the market has moved fast, to the downside. Since Dec. 2, you’ve also had weekly increases in U.S. oil production as a result of drilling in late 2014—wells were drilled in late 2014 but not completed until January. You had increases in U.S. oil production and U.S. natural gas production such that we needed to revise our model to reflect the realities in the marketplace.
TER: Are there any new developments on the horizon that might have a substantial impact on oil and gas prices?
JW: For oil, I would point toward the OPEC meeting scheduled for June 20. For natural gas, we continue to watch the Energy Information Administration production figures released every month.
TER: If natural gas exports to non-free trade companies were approved, would that materially affect Henry Hub prices?
JW: No, not in the short or intermediate term. Any liquefied natural gas plants that would be built as a result of a change in legislation or regulation wouldn’t be seen in the market until 2018, 2019, maybe even 2020. It’s a very long time frame.
TER: Would you say current export capacity is full?
JW: Yes. My understanding is that’s all contracted out and governed by long-term supply contracts that are already in place.
TER: Is the refinery strike going to have an impact on prices?
JW: With our focus on exploration and production, I’m not really qualified to answer that question. But I would note that most of the information on the strike has indicated it’s not going to have an impact. That is, the indications I’ve gotten from news are that most of the refineries have replacement workers and are able to function.
TER: In the current market, John, is debt or equity a safer bet for oil and gas investors?
JW: That’s a very good question. In the high-yield market right now, you see the bonds of some oil and gas companies trading for $0.50–0.70 on the dollar, and yet the equity market is still putting some equity value on the stocks. One of those markets is right, and one of them is wrong. We’ll find out as the year develops.
TER: Recently, you initiated coverage on several exploration and production (E&P) companies in the Permian Basin. Why are you focused on the Permian?
JW: It was the latest of the major basins to transition from drilling vertical wells to drilling horizontal wells with fracture completion technology. You had the Bakken in North Dakota leading the way five to six years ago. Then came the Eagle Ford play in south Texas. As those plays have refined the drilling and completion techniques, the Permian has begun transitioning from vertical wells to horizontal wells.
Because of that transition, we wanted to do an in-depth study of the Permian Basin. We focused on companies that have the type of metrics that we like to look for: Callon Petroleum (CPE:NYSE), Clayton Williams Energy Inc. (CWEI:NASDAQ), Diamondback Energy Inc. (FANG:NASDAQ), Ring Energy Inc. (REI:NYSE) and RSP Permian Inc.They’re all heavily focused in the Permian Basin.
TER: As oil and gas prices fall, are any E&P companies in your coverage approaching breakeven levels on their wells?
JW: Breakeven is certainly a topic getting a lot of attention in the press. The breakeven numbers for various shale plays that are thrown around or published are in the $70–75/bbl range. Those breakeven prices were calculated, by and large, using drilling and completion costs experienced in 2014. Now, as we see the rig count decrease, we’re going to reset these breakeven prices. It’s a little early to say just where the breakeven prices will settle, but I think they’re going to be quite lower than the often-quoted $70–75/bbl.
I’d also like to point out you can’t broad-brush breakeven prices across the various shale plays. The Bakken is different from the Eagle Ford, and the Eagle Ford is different from the Permian. Within each basin, there’s a large variation in the quality of the shale formations. You can have excellent results in the western part of one county, and then go over to the eastern part, say 10–20 miles away, and not experience the same results. The quality of the shale formations is very localized.
TER: Both Callon Petroleum and Ring Energy have played to mixed reviews from analysts in the last year. Why did you give them a Buy rating when you initiated coverage on Dec. 2?
JW: I think Callon is in transition in terms of how it’s perceived by the market. Several years ago, Callon was a 100% Gulf of Mexico company. It had some poor results. It was financially leveraged. It worked its way out of that and has transitioned into a 100% Midland Basin company. I think a lot of people don’t understand the transition and transformation that’s happened at Callon.
Ring Energy is a smaller company in terms of market cap and enterprise value, but we really like the company properties, and we really like the management. Both of those aspects are true with Callon Petroleum as well.
TER: You also initiated coverage on Clayton Williams Energy. What prompted that?
JW: I’ve known and respected the management team for a long time. They’ve been through numerous up-and-down cycles in the business, and they’ve done well. The company is about 50% Permian/50% Eagle Ford, so it has more diversification than some of my other coverage. It also has a group of legacy properties from conventional reservoirs in the Permian Basin, so it’s not a 100% shale company. That diversification gives the company more options in terms of the kinds of wells it will drill in 2015. Clayton Williams also has a very successful finding and development cost record.
TER: RSP Permian has a strong hedge at $87/bbl oil. Does that hedge make the company an interesting takeout target?
JW: It has a very well-hedged position. RSP is the most hedged company within my coverage, and I applaud management for that. Takeover or acquisition activity is typically not prompted by your hedge position. Acquisition activity is driven by specifics of your properties, your proved reserves and the finding and development cost record of those properties.
TER: What you like about Diamondback? What are its strengths and weaknesses?
JW: We talked about how localized the properties of these shale formations are. Diamondback enjoys an excellent property position in the western part of Midland and Martin counties. It’s interesting because a lot of its qualities overlap with those of RSP Permian. Diamondback has an excellent management team. It has some of the lowest drilling and completion costs in the basin. It is an excellent operator, and we’re glad we initiated coverage on it. The company has exceeded our expectations so far. Diamondback and RSP Permian have been generating really strong well results from the Wolfcamp A Formation and the Spraberry Formation.
TER: Do you see likely takeout targets in any of the five companies you cover right now?
JW: The dynamics of mergers and acquisitions activity are never dull in the E&P business, but just as with crude oil and natural gas markets, our research on individual companies is really focused from a bottom-up, individual company approach. If someone gets bought out at a much higher price than we have targeted, then we’ll be pleased. But that’s not what drives our recommendations.
TER: Thank you very much for your time.
John White is a senior research analyst with ROTH Capital Partners providing equity research coverage of the oil and gas sector. Prior to joining ROTH, White was a portfolio manager and analyst with Triple Double Advisors LLC, covering publicly traded equities in all subsectors of the energy complex. Prior to Triple Double, he was an exploration and production equity analyst with Natixis Bleichroeder and Next Generation Equity Research, covering small and mid-size exploration and production companies, and he has served as an energy, high-yield, fixed income analyst for BMO Capital and John S. Herold, Inc. White’s experience also includes banking and credit analysis responsibilities with Scotia Capital. His industry background includes working in acquisitions and divestitures, and exploration and production, primarily with BP. He received a bachelor’s degree in business administration from the University of Oklahoma and a master’s degree in business administration from the University of St. Thomas (Houston). He also serves on the editorial advisory board of the Oil & Gas Financial Journal.
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