INTERVIEW WITH DAVID S. HAVENS, MANAGING DIRECTOR, Crédit Agricole

OIL & GAS FINANCIAL JOURNAL: How did you get into the business of being a research analyst? Would you tell our readers a little about your background?

DAVID S. HAVENS: I started in the business in 1999 at Morgan Stanley in their equity research group down in Houston. I was with them a little more than eight years. While there, I spent five years on the sell side covering oilfield services as an associate analyst, and then I went over to the proprietary trading desk for three years, and I traded the energy book there until we all got clobbered [in the recession]. More recently, I was over at Citadel on the buy side covering oilfield services and equipment. And I came to Crédit Agricole in July of 2012 covering the sell side.

OGFJ: What about your education?

HAVENS: I went to Vanderbilt and graduated from their engineering school. At that time, going into finance with an engineering background was pretty simple. There were a lot of opportunities. Today, I think it's a different landscape if you're straight out of college. You might want to consider getting a master's or MBA to improve your chances [of landing a job].

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Drilling operations in PCD's Wattenberg FieldPhoto courtesy of PCD Energy

OGFJ: Are you from Tennessee? You don't have a Southern accent.

HAVENS: No, I'm from Philly [laughs]. It was a bit of a cultural shock going down to Nashville for four years, but I thoroughly enjoyed it. Vandy is a wonderful school, a great institution.

OGFJ: Would you tell our readers what an analyst does? Can you describe a typical day for us?

HAVENS: That will differ greatly among analysts. To me, what I spend a great deal of time on, particularly in the morning, is just trying to figure how where the market's head is at. What's the set-up for the stocks? What is the consensus? What are the key catalysts that should either disprove the consensus or support it? And then we spend a great deal of time talking about management teams to make sure we keep our pulse on the company. Each week we try to touch at least two management teams, whether we cover them or not, just to make sure we have a consistent overview of what's being said out there. The afternoon will get a little bit quieter, and we run through the models a lot. To me, if you don't have a very good pulse of what's in your models and understand really what the financials and the sensitivities are – the sensitivities being more from a cash-flow perspective and a balance sheet perspective – it's very tough to be an effective analyst. I think that's generally where people tend to fall short on the sell side versus the buy side. On the sell side, your models can get very stale very quickly. No fault to the analysts themselves because their schedules generally have a lot more marketing and things of that nature. On the buy side, you don't have the same issues, and I think that's a big difference between the two.

So, to sum it up, I spend a lot of my day figuring out where the market's head is at, what's the consensus, what are the key variables, making sure I'm in touch with the management teams, and fine-tuning the models to keep them current.

OGFJ: You specialize in the oilfield services sector, right?

HAVENS: Yes, since 1999.

OGFJ: Don't you have to keep up with trends and what's happening on the E&P side, too, in order to make forecasts about companies that serve that sector?

HAVENS: I find that to be an effective oil services analyst, you really have to have an almost equal if not greater pulse on the E&P companies because that's our bread and butter. We need to know about things such as shifts in capital expenditures. We have to be in tune so we know about any major strategic shifts or capital outlay changes among the E&Ps because that will move our stocks significantly. So you almost need to cover two sectors in order to do your job effectively.

OGFJ: Let's move on to the impact that shale development has had on North America. I know people who say that you cannot overestimate the impact that this dramatic increase in production has had on the energy sector. First in gas and now in oil and liquids. It has truly been a game-changer. How long do you think we can sustain this level of production? Is this a long-term trend?

HAVENS: Oil or gas?

OGFJ: Oil.

HAVENS: The way I look at the group, I tend to rank the major global markets around the world by the opportunities present. If you look at the US and the opportunities in crude production, I think it is going to be longer term. I think it's probably one of the better opportunities because of its size of the reserve and because of the pace of the cash conversion among E&Ps. That is, the pace at which they spend money, recollect cash, and reinvest it in capital expenditures to my guys. So, to answer your question, I think this is going to be a long-term phenomenon. It has the appeal, first, of being in the US, second, of having the highest rate of return on invested capital, three, one of the fastest cash-conversion cycles, and, four, one of the biggest reserves in the world. Ultimately, that generates a higher degree of certainty and a higher degree of probability of success, which attracts capital. So, yes, I think we are going to spend a great deal of money in this country for the next decade-plus. And I think it will prove ultimately to be one of the highest return markets within the entire energy complex worldwide.

OGFJ: Are investors eager to invest in the United States because it is less risky than other countries?

HAVENS: In part, but let's not forget the [drilling] moratorium in the Gulf of Mexico in 2010. That was unexpected and was a blow to many companies operating there, especially the smaller ones. We may think that geopolitical risk is the only concern, but in the US we have to take into account regulatory risk, whether it's new regulations for hydraulic fracturing or constraints on offshore drilling and production. Still there is more consistency or transparency of law in the US. To answer your question from an engineering perspective, which is where I come from, what's the biggest pivot in the US for the last 10 years? It's the fact that the inertia of supply has dramatically reversed. It's re-set how non-OPEC production can be viewed.

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Enerplus operations in the Marcellus shale.Photo courtesy of Enerplus.

OGFJ: Another thing that has changed is drilling efficiency. The US has achieved this record production using fewer rigs. How has that impacted the service industry?

HAVENS: Oilfield services has become a polynomial, meaning that there used to be a very tight correlation of revenue versus rig count. Now there are several other data points that influence revenue. So as opposed to a linear relationship with the rig count, you have rig count plus how many horizontal wells you're drilling plus the length of the lateral, which all comes down to the intensity of the well. A higher intensity well means higher revenue intensity.

Efficiencies are going up. We increased rig efficiency by more than 15% last year, and we'll probably see a similar increase this year. So we're drilling more wells with the same number of rigs, which creates more opportunities for service companies. We have more wellbores being drilled, plus you have a higher revenue content per well. Margins can be a bit of a different story. Given the returns we were earning back in the 2010-2011 time frame, we attracted a lot of capital for land rigs and frack equipment, so profitability will probably be a little more measured. But the revenue opportunities will be continually increasing.

OGFJ: Crude oil prices are sufficiently high right now to sustain development. What happens if we create an oversupply and prices fall, say, to below $80 a barrel? What is the breakeven point for crude prices in some of the major shale plays, like the Bakken and the Eagle Ford?

HAVENS: I don't have a great breakeven for the Bakken or some of the other shale plays. The consensus among operators I've talked to is that prices breaking below $80 won't crush the opportunities. However, once you get down to that $65 level, then we have to remember what happened to gas. A lot of these shales wouldn't have been drilled if it weren't for higher oil prices. Frankly, the technology that had to be deployed demands a much higher return.

OGFJ: Sustained low gas prices seem to have caught the industry by surprise. Even the CEO of ExxonMobil said recently that he didn't expect gas prices to stay this low this long. That's quite an admission coming from someone of his stature. How likely is it that crude prices will plummet due to oversupply and stay down for some time?

HAVENS: I think the difference between gas and oil is that when you clip the pace of drilling in gas – the key word there being the "pace" of drilling because it has become more of a manufacturing process – it was augmented by oil. When you cut the pace of drilling in oil, it's not augmented by anything. It'll drop like a brick. Obviously there will be a lag time because there are wells that haven't been completed and that are being brought online, but that's the biggest difference between oil and natural gas. Natural gas got the double-whammy, if you will.

OGFJ: Several people have told me that the cost of completing a well today equals or exceeds the drilling cost. Is that an accurate statement?

HAVENS: Ten years ago, the average cost of a well was about $2 million, although this varied somewhat from region to region. The actual drilling rig and mobilization would have been between 40% and 50% of the total cost of the well. Today it's about 10% to 13% of the cost of the well. Total well costs have gone up to about $6 million to $8 million, and the primary delta in that number is largely frack related. If you look at a Bakken well, the drilling cost has come down from about $8 million to close to $6 million, but the frack cost of drilling that well can be upwards of $2 million to $3 million. You're looking at 30- to 36-stages and even up to about 40.

Back in the day, about 10 years ago, we were drilling mostly vertical wells. If you fracked, you fracked it once, maybe twice. The multi-stage fracking that is widely used today is mainly what has driven up costs. I'd say that the completions component of drilling a well has increased to a par with the drilling costs, if not above. The major cost of drilling a well today is not the drilling rig. So if you're going to cut a drilling program, you're going to go out there and just slash the rig. You don't care because the penalty is fairly insignificant relative to the overall cost of drilling that well.

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"I tend to rank the major global markets around the world by the opportunities present. If you look at the US and the opportunities in crude production, I think it is going to be longer term. It's one of the better opportunities because of the size of the reserve and because of the pace of the cash conversion among E&Ps - the pace at which they spend money, recollect cash, and reinvest it in capital expanditures."

OGFJ: What is happening in the oil services sector today? Are we seeing much M&A activity, industry consolidation, or new companies being created?

HAVENS: One of the trends is public offerings from private equity firms. Private equity is investing in oil services for one major reason – the amount of capital needed is generally smaller than what is needed by E&P companies. For E&Ps, you're buying a lot of acreage and it has to occur over a long period of time. So the fund's investors are going to be out a lot of money for a considerable time. With oilfield services, you're basically investing in fracking, which has a payback period of less than a year in many cases. You're tying up significantly less capital. And you're able to get into and out of the investment much faster. I believe you're going to see a lot more private oil service companies go public. I don't think M&A will be as big as public offerings from PE firms over the next year or two. Any M&A will involve relatively small companies getting acquired. I don't expect to see any major $10 billion-type transactions.

OGFJ: Water is a major factor in hydraulic fracturing. Talk a little about how this oil services sector has grown in recent years.

HAVENS: It has turned into a pretty major business segment. It's really ballooned in the past five years. Whether it's transportation or disposal or filtering, the opportunities are quite big. Frankly, I'm a little surprised we haven't seen even more participants in that business. Water management is one of the larger growth opportunities, but it has yet to reach its full potential. It looks to me as if a lot of potential market participants are still looking to see exactly what the right market opportunity is for them.

OGFJ: It looks as if the current administration in Washington is starting to approve LNG export facilities on a case-by-case basis. These are capital-intensive projects, but they may finally give US gas producers access to foreign markets and help revitalize a struggling industry segment. Given that our gas reserves in North America are huge, is this another game-changer for the energy industry?

HAVENS: It is certainly incrementally important because if you look at the US natural gas market, the inertia of supply was quickly reversed with the development of shale. We have come to the position where we can add significant capacity that's behind pipe within about a six- to eight-month time frame. However, the demand for natural gas in the US really hasn't changed. Low prices do impact demand, but it takes a while. Industrial users of gas don't go out and build $500 million plants based on one or two years of low gas prices. And increased usage of natural gas for electric power generation is so slow, it's glacial. I believe the first LNG export facility is scheduled to start up in 2016-2017. That may actually occur simultaneously with additional industrial demand and transportation demand. I wouldn't call it a game-changer, but every incremental source of demand for US natural gas is extremely important.

OGFJ: We've talked a lot about shale development, but how important is offshore to America's energy future? Companies are spending billions to develop the deepwater Gulf of Mexico, and there has been a revival of sorts in the shallow waters of the shelf as well.

HAVENS: It's hugely important. I think we're going to see multiple trends that were all born from one simple fact – that is, the probability of success in the deepwater has increased by over 1,000 basis points in the last 10 years. If you looked at any ultra-deepwater well in the Gulf of Mexico 10 years ago, those engineers would have applied somewhere between a 27% and 30% probability of success. Now you are talking about upwards of a $1 billion project. Look at the advancements we've made in seismic, largely 3D; directional drilling, which significantly improved the placement of wells for better production efficiency; completion technology; production technology, which also includes seismic with 4D – all in the last 10 years. If you look at all of these in aggregate, it has increased the probability of success by about 10 percentage points. So when that same engineer comes forward with a $1 billion project with a 40% chance of success rather than 30%, it tends to get a little more traction. This has translated into a mushrooming of deepwater opportunities, which are now playing out. Obviously this has been a boon for the oil services sector as well, including the rig construction business.

OGFJ: How do these trends apply outside the US and the Gulf of Mexico?

HAVENS: Given that we've had sustained high oil prices and broad geopolitical support, meaning that we actually have access to these reserves, I think we're going to see significant growth outside the traditional "Golden Triangle," which is the Gulf of Mexico, West Africa, and Brazil. We're going to see lots more activity from East Africa, the Red Sea, more intensity in Norway, more intensity in Southeast Asia. These areas are going to become an integral part of the energy complex over the next 20 years, and it is all a result of the improved probability of success, which has in turn attracted more capital.

OGFJ: Most of the areas you just named are offshore opportunities. Since three-quarters of the earth's surface is water, it seems obvious that there would be more hydrocarbons beneath the sea than on the 25% of the globe that is land. On the other hand, it's a lot more expensive to drill in the ocean.

HAVENS: Let's look at the Gulf of Mexico back in 2001. There were 155 jackups in the Gulf of Mexico, 80% of which were directed towards natural gas. Look at the Gulf of Mexico today – it's less than 15%. It's largely a function of low gas prices, but also the opportunities on onshore land. The risk and cost that you bear to drill offshore relative to the opportunities onshore, which has a much higher probability of success with a lower capital commitment, it's far more appealing to go for the onshore. But if you look at the international markets, you don't have the same choices. Security is also a problem in some areas, such as the Middle East, West Africa, and even Mexico. However, given the new technology and the increased probability of success, the risk is tolerable even in places that are less secure than the US or Canada. And the industry responds to this. We've built 200 new deepwater rigs in the last decade. That's a major expansion.

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Statoil Carkuff drilling operations in the Bakken preparing to run surface casing.

OGFJ: We've run several stories in OGFJ in recent months about the capital flow from outside the US into the US. It's coming from Europe, from China, from Japan, from India, from all over. Why do you think this is happening?

HAVENS: Same answer as before – probability of success. The shale plays in North America offer as much as a 90% degree of success, so this is a fairly safe investment with a healthy return on capital. Capital tends to flow to lower risk, higher return assets, and the US has been de-risked a lot more than most international markets.

Look at the biggest incremental investors – ExxonMobil, for example. We can all debate their timing [in acquiring XTO Energy in a $41 billion deal back in late 2009] and entrance into the domestic natural gas market, but at the end of the day they did it because it was a lower risk, higher return opportunity. If you look at the crude oil side of the business, where else but the US are you going to get (1) this type of access; (2) service infrastructure, which is the best in the world; (3) capital conversion at the pace in which it is done; and (4) the returns. We knew the reserves were there all along, it was just a matter of developing the technology to recover them. Bottom line: we're going to continue to see outside oil and gas companies coming to the US because the best opportunities are here.

OGFJ: Final question: Is there anything in particular we should watch for to indicate there is trouble ahead for the oil and gas industry in North America?

HAVENS: One of the things I look at pretty intensely is reinvestment. If you see reinvestment increase, it tells you there is a high degree of conviction among the operators. Good, right? But on the flip side in the US, there is the possibility of overbuilding. Right now, incremental investment in the US may provide some near-term confidence, but we have to be concerned about longer-term profitability. We also need to keep an eye on oil prices and the pace of production in the US, although I think for the next few years we're still going to be hampered by lack of takeaway capacity for pipelines. To my way of thinking, reinvestment is the main indicator, particularly if companies are trying to grab market share. Generally that tends to bring growth, but I'm not convinced the US market is going to take another leg up in the absence of gas price recovery.

OGFJ: Thanks very much for your time.

Crédit Agricole analyst discusses oil markets, investment indicators

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