Stepping away from the pack, Andrew Coleman of Raymond James Equity Research is making a contrarian forecast for an oil glut in 2014. Shale oil production is on the ascent, with the United States joining Saudi Arabia on the supply side, while China's hunger for oil may be sliding and demand in developed countries remains in decline. In this interview with The Energy Report, Coleman explains his thinking and names the producers best positioned to capitalize on the turbulence ahead.
The Energy Report: Why are you expecting an oil glut in 2014?
Andrew Coleman: Because of the evolution of North American shale oil plays, we are on track to add about 3 million barrels (3 MMbbl) of new supply over the next five years. Yet we know oil demand has been falling across the developed nations and is still weak coming out of the global financial crisis. Those developments point toward a glut.
TER: Saudi Arabia surprised you last year by cutting production when oil was more than $110 per barrel ($110/bbl). Why would Saudi or other suppliers not do that again?
AC: What hurt production outside the U.S. last year—and helped keep the demand side a little more in balance—was that Saudi cut 800,000 barrels a day (800 Mbbl/d) in Q4/12, sanctions in Iran reduced exports by about 800 Mbbl/d as well, conflict in Sudan took 300 Mbbl/d offline and the North Sea average was lower by about 130 Mbbl/d. These reductions kept last year's supply more balanced than we thought it would be. Going forward, Saudi's ability or willingness to cut is certainly going to be tested, because by our model the country may need to cut 1.5 million barrels a day (1.5 MMbbl/d), about double what it cut last year. It would have to do that for a longer period of time, given the amount of excess storage that could show up on the global markets.
TER: But, as you just pointed out, Saudi Arabia's cut came in the context of actions by other players. The other players are going to be as unpredictable as they were last year, aren't they?
AC: Certainly. That's a big risk to our call. The other players are very unpredictable as well. I think Saudi has two years of foreign currency reserves at its current spending level. The country doesn't have a deficit right now, so the question is, would it be willing to tolerate a deficit? Most other countries have deficits, but that doesn't mean Saudi will. It is hard to predict because we're dealing with personalities and governments, as opposed to hard numbers. We're going to keep watching, and we'll adjust our forecast if some of those scenarios play out.
TER: Was Saudi Arabia's production cut driven by a policy change?
AC: Saudi Arabia cited internal demand issues in its production cut. The cut may also reflect an adjustment to offset the start-up of Manifa, which occurred last month.
TER: If the glut does occur, which benchmark crudes will be most affected, whether by going up or going down?
AC: In the U.S., production of light oil will dramatically increase due to the shales. Without the ability to export, we are already seeing prices of West Texas Intermediate (WTI) reflecting that "stranded" lighter barrel. We see light imports being backed out of the U.S. as early as this summer as well. Finally, as infrastructure bottlenecks are removed onshore, we see risk to Gulf Coast prices (e.g., Light Louisiana Sweet). With much of the U.S. refinery infrastructure having been geared to process heavier barrels, the large growth in light barrels has already driven WTI prices to a discount with Brent. Risks to Brent could come down the road if European and Chinese demand remains tepid.
TER: Will Venezuela's production decline continue?
AC: With Nicolas Maduro running things down there now, we see Venezuelan production remaining flat for the next couple of years. Volumes declined each of the past four years.
TER: What role will other players in the oil space have in either creating or preventing the glut?
AC: Prior to about 2009, we were in a world where there was one marginal producer of oil (Saudi), and one marginal buyer of oil (China). Now we're in a world that has two marginal suppliers of oil, those being the U.S. and Saudi. We have not added any new marginal buyers of oil. The question remains, is that marginal buyer of oil—China—as hungry for oil as it has been in the past? We also know that as economies develop, they become less energy-intensive. And, factoring in the potential growth of natural gas consumption, that drives our caution.
TER: Denbury Resources Inc. (DNR:NYSE) depends heavily on CO2 flood for its production. Will that be economically feasible if a glut occurs?
AC: Yes. Denbury is profitable in the $50 per barrel ($50/bbl) range. Most of its current production comes from older oilfields that it owns on the Gulf Coast. The company's CO2 is also on the Gulf Coast—in fact, the company has the only naturally occurring CO2 source outside the Rocky Mountains. And it has the advantage of a pipeline that ties those CO2 assets to its producing fields on the coast. Because the oil is produced next to the infrastructure used to refine it, Denbury doesn't have to spend a lot of money on transportation, which helps the economics.
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I'm not worried about Denbury being able to economically produce oil because it is cycling CO2, an injection process by which the company puts CO2 in the ground, displacing (and producing) oil as it goes. The company doesn't have to drill hundreds of wells every year to increase production. All it has to do is get the facilities working and then maintain them, versus continually deploying a lot of new capital in the ground each year.
TER: CO2 flooding is not necessarily more expensive than drilling brand new wells, is that correct?
AC: Correct. The two processes present different sets of challenges. If you are going to drill new wells, you need to come up with the drilling rig, well tubulars, hydraulic fracturing fluids and frack sand, and you must build roads and pipelines to connect those wells. If you are going to do a CO2 project, you've got to get the CO2, which costs a little bit of money, and you need injection pumps. Much of the initial infrastructure (roads, wells, etc.) is already in place.
It is a slightly different business model but is still based on extracting additional barrels from historically large accumulations. Finding risk is very low, leaving the bulk of the costs as development in nature only. It's a business model that you don't see a lot in the exploration and production (E&P) space. Most players with CO2 assets — the ExxonMobils (XOM:NYSE), the Chevrons (CVX:NYSE), the ConocoPhillips (COP:NYSE) of the world—have those assets embedded in much larger organizations, as part of their core businesses. Most of the E&Ps that we focus on, because of their growth nature, are drilling wells on a continual basis to replenish and add to production.
TER: With rare exceptions, Denbury has been stalled below $20/share for more than four years. You bumped your target price from $23 to $24 based on your pricing model. If the model says Denbury can reach that level, why hasn't it done so before?
AC: A few years ago, the company was bringing on one of its biggest fields, Tinsley. It was the largest project the company had undertaken up to that point and some operational hiccups caused it to miss some production targets. As a result, management initiated a stock buyback program, and added to the technical team by bringing in Craig McPherson from ConocoPhillips.
Over the last couple of years the company has put more process in place and structured its operations and technical teams to manage its multiple large-scale CO2 floods (aptly titled "Operations Excellence"). Over the last 18 months, management has slowly inched up its tertiary production outlook and now is saying it's going to come in at the high end of guidance. The guidance has slowly trended up as the company has been able to get more control on the operational side. That is why the stock has risen from where it was a couple of years ago, from $11–12/share to where it is now ($18). To get into the twenties, it would be helpful to have a little bit of oil price support. It would also be helpful to see production growth expectations pick up as the company brings on more of its large-scale fields.
Management has also been discussing ways of accelerating cash flows from the build-out of its tertiary oil business. The creation of a master limited partnership (MLP) is one way, though management hasn't decided yet. If you look at how some E&P MLPs are structured, you could make a case in which Denbury would trade from the mid-twenties to the low thirties. My price target reflects continued execution as well as the potential of a little more color on how an MLP might work for the company.
TER: Do you think converting to an MLP would increase the value of the stock?
AC: Potentially. Assets with low maintenance capital do well in an MLP. Maintenance capital is the money needed to keep production flat. If you think about the CO2 floods, they might fit nicely because drilling capex is low. Once you get those facilities up and running, then incremental costs involve getting more CO2, as opposed to getting rigs and steel and frack sand, etc.
While Denbury may not, at this point, grow 40–50% like some of the premier shale players, growing in the 10–15% or maybe 15–20% range could be attractive for an E&P MLP. Investors would have long-term visibility on production growth and the company would be relatively stable, so it could then project the cash flow stream that could be dividended out to investors.
TER: Energy XXI (EXXI:NASDAQ) has posted disappointing results recently and management has announced a $250 million ($250M) buyback program. What does management hope to accomplish?
AC: Management is trying to draw attention to the fact that it expects to have free cash from the asset that it produces from, which is not something we've seen a lot of companies focus on historically in the E&P business. Most E&P companies are growth companies, with historically high levels of reinvestment of cash flows to fund future growth.
With Energy XXI recently taking production guidance down to 10% for the next 12 months, it's going to have a little more capital available to buy back shares. By my model, assuming the oil price is around $95/bbl net, the value of the company's proved reserves alone is somewhere in the $30/share range. If the company buys back shares for $25/share, that is 15–20% cheaper than what the assets are worth. That gives the company no credit for any future drilling potential, too. Gulf Coast players tend to trade at some of the most conservative multiples in the E&P peer group, but that doesn't reflect the fact that they generate a lot of cash flow.
TER: What's behind the disappointing results?
AC: The company had some exploration wells that didn't pan out. That happens when you drill wells with chances of success that are 30% or lower. The offset is when a high-potential well of that magnitude works; it covers the cost of the past unsuccessful tries and then some! If you look at Energy XXI's capital budget, it has roughly $500–600M of base capital for its base assets. It is going to spend $100–200M on higher-risk, higher-potential exploration stuff. So 15% of its annual program is directed at these high-risk/high-potential wells.
Over the last two or three years, management spent a lot of money on the Ultra-Deep Shelf (UDS),and it has recently started to balance that by adding exploration drilling around its existing fields. It signed joint ventures with Apache Corp. (APA:NYSE) and ExxonMobil and will test some play concepts that were generated in-house, as well as working with its partners, McMoRan (MMR:NYSE) and Plains Exploration & Production (PXP:NYSE) on the UDS. Freeport McMoRan Copper and Gold Inc. (FCX:NYSE) recently completed its acquisitions of McMoRan Exploration and Plains Exploration.
The reason Energy XXI missed production numbers was also partly due to lingering weather impacts from last fall's storm season.
TER: Energy XXI's initial strategy was to grow through acquisition, and it did have five large acquisitions, the last one completed in 2010. How well has it performed with the acquired assets?
AC: The acquired assets are probably 60–70% of the inventory the company can drill now. Getting assets from Exxon, and a couple of years before that from Mit Energy Upstream, Energy XXI was able to high-grade and increase its inventory. Hopefully the company is done integrating the assets, but it's a continuous process to high-grade a portfolio, drill your best projects and optimize those projects as you go. I look to see that continue. In fact, Energy XXI recently brought its reserve engineering in-house.
Over the last few years, partly because the company was smaller, it let third party engineers handle 100% of its reserves for year-end reporting. Most larger companies do that in-house, and then use reserve engineers to audit the process for consistency. By bringing the engineering in-house, Energy XXI is trying to show the market that it has a bigger organization—that it has the bigger skill set—and it wants to be more in tune with taking prospect sizes and prospect targets that match its capital program with expectations.
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TER: What is the company's strategy now? Is it still planning acquisitions or it is going in new directions?
AC: The strategy continues essentially unchanged. First, it wants to invest in as many high IRR capital projects as it can. The CEO has said that for every dollar invested in the current year, he expects to get $1.50–2.00 in cash flow out of the ground. From that standpoint, the company can continue to spend money to get more returns, but it must balance that with trying to find the next company makers—those bigger projects that support multiple well developments and new platforms.
For the organic portfolio, the company also has to manage whether it can buy assets that would consolidate parts of its fields in the Gulf of Mexico—and do that at an attractive price. Energy XXI is always looking at acquisitions. It's always looking at optimizing the drilling program. With the share buyback, the company has tried to put a little more emphasis on the fact that it recognizes the value of cash flow to investors beyond the growth side of the E&P business.
TER: Bonanza Creek Energy Inc. (BCEI:NYSE) has been a strong performer for you, but its recent earnings report was a miss right across the board. You've cut its target price from $41 to $40. What caused that miss?
AC: Coming out of last year and into Q1/13, Bonanza Creek had a slowdown in activity due to its rig schedule and winter weather. The company is in the right play in the Niobrara oil shale formation, where it is a small-cap player surrounded by Noble Energy Inc. (NBL:NYSE) and Anadarko Petroleum Corp. (APC:NYSE). It was getting its program ramped up in earnest, but the slowdown caused it to come in below expectations for the quarter. In all fairness, at Bonanza's analyst meeting in April, management discussed the slower start to the year.
Fundamentally, Bonanza stock still is underleveraged. Its debt is less than current cash flow; it's going to grow north of 60% this year; it continues to have access to inventory; and it is testing multiple zones to increase its inventory potential. From that standpoint, the stock still looks compelling and still has lots of growth in front of it. That is why I only took the target down by a dollar.
TER: You make it sound like growth is simply built into the company's current direction. Does Bonanza not need to improve something in operations to get results?
AC: Not really. Bonanza Creek's going to drill 70+ wells this year in the Niobrara. It is testing 5-acre downspacing in the Cotton Valley, it is testing long laterals in the Niobrara B bench and it is testing the Codell zone for the Niobrara as well as the C bench in the Niobrara.
It doesn't need to do anything more than continue drilling and hit its targets in terms of ramping the rig count. With four operated rigs presently, the company is doing everything that management said it would do and that allows Bonanza, based on my bottom-up activity model, to hit my $40/share target.
Additionally, across the play you've got the LaSalle Plant, which DCP Midstream Partners, L.P. (DPM:NYSE) is building. The plant should come on line at the end of the summer. That provides additional capacity to enhance volume growth for players in the basin. The Niobrara is a play that works. You've got sufficiently large companies in the play to keep capital and facilities growing. Bonanza Creek is falling right in line there, and keeping up with its peers.
TER: What other companies are you excited about right now?
AC: My favorite stock is Anadarko. The biggest story for Anadarko will be the resolution of the Tronox Inc. bankruptcy case. After that, the company has numerous operational catalysts on the horizon, including 1) an ongoing process to partially monetize some of its Mozambique gas assets; 2) its Yucatan exploration well (operated by Royal Dutch Shell Plc (RDS.A:NYSE; RDS.B:NYSE) in the deepwater Gulf of Mexico; 3) the sale of its Brazilian assets; and 4) ongoing drilling/testing of its extensive onshore shale inventory (e.g. Niobrara, Eagle Ford, Marcellus and Utica).
The company has established itself as a premier explorer, and with the Tronox case resolved, Anadarko is also an attractive takeout candidate. In our net asset value (NAV) model, I see its shares as worth up to $130 each, but have assigned a $105 price target given visibility on near-term cash flows.
TER: Do you have any parting thoughts on the oil and/or gas markets that you'd like to share?
AC: Yes. From our macro view, we're cautious about the oil outlook. We've got a lot of production, and we're unclear about the strength of demand on the oil side in the next 6–18 months, going through 2014. On the gas side, after bottoming last year, gas looks like it is poised to be higher down the road, which makes us more constructive there. We have to see more evolution on the demand side, be it in the short term with power plant construction or in the longer term with the quest for use of compressed natural gas as a transportation fuel.
If the price spread between oil and natural gas remains wide, we'll see continued evolution toward natural gas use across our economy. That will be good for everybody. It should help unlock value for the manufacturing space. It should also unlock value for consumers, who won't have to spend quite so much to heat their homes and fuel their cars. It would ultimately kick-start the next big wave of economic expansion on the back of affordable natural gas in the U.S.
TER: Andrew, thank you for your time.
AC: My pleasure.
Andrew Coleman joined Raymond James Equity Research in July 2011 and co-heads the exploration and production team. Since 2004, he has covered the E&P sector for Madison Williams, UBS and FBR Capital Markets. Coleman has also worked for BP Exploration and Unocal in a variety of global roles in petroleum and reservoir engineering, operations, business development and strategy. Coleman holds a bachelor's degree in petroleum engineering from Texas A&M University and a master's degree in business administration (finance and accounting) with a specialization in energy finance from the University of Texas at Austin. He is a director for the National Association of Petroleum Investment Analysts and a member of the Texas A&M Petroleum Engineering Industry Board, the Independent Petroleum Association of America's (IPAA) Capital Markets committee and the Society of Petroleum Engineers (SPE).
By. Tom Amistead of the Energy Report