Strong Rig-build Cycle & Shift Toward Higher Specs
Edward C. Muztafago
TWST: Some news outlets have reported that the unusually warm weather has not been kind to the drilling industry. Is that true?
Mr. Muztafago: The reality is, it hasn't been kind to the stocks, but the actual industry itself has fared relatively well. I think there is really a bit of a misperception on the part of buy-side community right now that the weak natural gas prices are going to cause some precipitous collapse in drilling activity. Unlike the past cycles, this cycle is very much driven by oil and liquids, or oil, natural gas liquids, NGLs, and oil condensate. The economics of that clearly are much better than natural gas prices would indicate. If you look at Baker Hughes' (BHI) rig count, what it says is that 40% of the rigs in the U.S. are still drilling for gas, but in reality we think probably anywhere between 40% to maybe on the outside 50% of those rigs are really drilling very heavy liquids-rich targets. So it's a little bit of a loose correlation to say that the economics of those rigs are driven by the weak gas prices. They're really driven by liquids, and whether condensate or NGL, it's priced off of oil. And so that can materially alter the economics of drilling new wells.
TWST: We've seen this big dichotomy between oil prices and gas prices. What's the impact?
Mr. Muztafago: In past cycles in North America, it wouldn't have been that big of a deal, but we finally cracked the oil shale code. While we don't have as many oil basins or oil shale plays in North America as natural gas ones, we clearly have enough to perpetuate drilling activity for some time. I think that will really insulate North American drilling from the weak gas prices for a while, and that 2012 outlook for drilling activity in North America is actually quite positive. Clearly, the natural gas prices are going to curtail some activity at the margins, but what we've seen so far over the last, let's call it two to 2.5 months is, every time there has been a decline in the natural gas rig count, that's been effectively supplanted by an increase in oil-directed rig count.
TWST: Is that kind of a balancing act?
Mr. Muztafago: Yes. Part of it may simply be a reclassification of rigs since there is no cut off as to what mix of gas or liquids defines a rig being gas or oil. If you've got a rig that's drilling in an area that's predominantly dry natural gas, say 70%, but the geological formation has got a fair amount of liquids content, there's nothing stop an operator from simply saying, "OK, well, people don't like the fact that we're reporting that we're drilling gas, so we can just simply classify a rig that's producing a lot of liquids content as an oil rig."
TWST: So it's about definitions?
Mr. Muztafago: Yes. There is clearly some definitional, let's call it "wrangling," that I think is going on, and there is just some simple reallocation of rigs from areas that are very heavy dry gas in places like the dry gas window in the Eagle Ford, to more heavy liquids or oil Eagle Ford. That's a good example of a basin that has a very wide spread of the hydrocarbon that you can produce out of it.
TWST: Where do we go from here? What's rig count look like now, and what's it going to look like the balance of this year?
Mr. Muztafago: We probably have, I would say, some optimistic 2012 growth outlook for rig count, between 10% to 15%. Now, that's year over year. What we've heard from most of the service companies is that their expectation is something of flattish to slightly positive growth in rig count from the fourth-quarter levels, but that sort of does imply something that's in the high-single digits to possibly low-double digits - so the caveat being that natural gas prices tend to stay somewhere in the $2.50 range, possibly get higher as we move into the later part of the year. But if natural gas prices dip below $2 and stay there for an appreciable amount of time, that does present a little bit of risk to our outlook.
TWST: What's going to move natural gas prices one way or the other? Is it just pure supply and demand at this point?
Mr. Muztafago: Clearly, supply and demand is the major factor. Right now, it's hard for us to envision with the somewhat sluggish economic growth outlook for the U.S. that you're going to see some huge recovery in demand. The supply side of the equation I think will probably correct quicker than people expect. If you look at the dynamics of shale wells, they decline hyperbolically. So by that, they decline 75% in the first year, 45% to 50% in the second year, and about 25% to 30% in the third year. And that's pretty much regardless of which shale play you drill. So when you look at the history of what we've done in terms of horizontal drilling, which has really been the driver of this big increase in natural gas production, somewhere around 70% of all the wells that we've drilled since unconventional shale boom took hold in 2005 and 2006 have been drilled in the last three years. Ultimately what that means is that the decline rates are extremely high, probably north of 40% to 45% in these unconventional production portfolios - and that compares to what was probably 25% to 30% in the conventional gas era. So with a lot of gas rigs coming off as they clearly have - and particularly the unconventional gas rig count, which is down about 25% to 27% year over year - we think that will ultimately result in some resetting of the production profile in North America.
If you go back and look at the conventional eras, it typically took four to six months to show material production response when rig count rolled over. But with unconventional production and high hyperbolic decline rates, that should certainly accelerate that time frame. If you look particularly, let's say, at Texas Railroad Commission data, you'll see that actually gas production out of Texas has been on a material decline for the last five or six months. So we've had places like Marcellus in North America that have kind of replaced some of that, but now with some of the operators really pulling back hard on the dry gas activity there, we think that it's relatively soon that you've got to see some type of production response to the downside.
TWST: What's going on from a rate point of view at this juncture?
Mr. Muztafago: When you're talking about rates, are we talking about U.S. land drilling rigs or . . . ?
TWST: Let's start there.
Mr. Muztafago: OK. Rates for U.S. land rigs continue to move up. We don't actually cover any of the land drillers currently, but we do obviously follow the broader market. What you really have is the most capable rigs for drilling shale, which are your AC electric rigs, are in very short supply. Utilization rates for those rigs are effectively 100%, let's say. When you have that kind of tightness in the market, anytime a rig rolls off contract, you do tend to get a little bit of upward movement in rates. So there is about another 175 rigs set to come into the North America in 2012, all likely to be on term contracts, and predominantly all going to drill oil and liquids. So really even the new incoming supply will be allocated for. I think for those drilling contractors that have higher spec, the newer fleets, the outlook is very positive for them. For the drillers that have sort of the midtier and the lower-spec rig, they'll do fine, and they will benefit from the general upward movement in overall day rates, but it won't be to the same extent as the high-spec providers will see.
TWST: Where are these rigs coming from? Are they coming from outside the country?
Mr. Muztafago: No. A good portion of those rigs are manufactured by people like NOV, or National Oilwell Varco (NOV). And some of the land rig contractors themselves assemble them, but parts still come from people like Cameron International (CAM) and NOV. So a good portion of those rigs are going to be domestically made rigs.
TWST: I was going to say, what's going on in that space, are you seeing good demand or are cancellations taking place?
Mr. Muztafago: The demand is still very strong. You've got a number of things going on. The rig-build cycle offshore has been extremely strong. In the North America land market only about 25% of the fleet is actually this very efficient, highly mobile AC top-drive rig. So there is plenty of room for retooling the North American land rig fleet, and I think that's going to continue on for some years. We see shale development in North America is a secular trend, and so certainly as time goes on, you're going to see operators retire some of the old mechanical and SCR rigs and everything that they bring into the fleet is going to be effectively these AC-driven top-drive rigs. You'll have natural attrition out of the market that will be replaced by these newer rigs. For the most part, nobody wants an older, big, bulky SCR rig anymore that takes a lot of time to move. They want something small and efficient when they are drilling in a shale formation. When you're doing 100 wells in a program and moving from well site to well site to well site, you need to rig up and rig down as the industry calls it in a matter of days, not weeks. Demand on the equipment side, it remains very strong.
Companies CAM and NOV not only supply the land rig market in North America and abroad, but they supply the offshore rig markets as well. When you look offshore, you've got a couple of dynamics going on there. Obviously, you had the Macondo well disaster in 2009, and that really ushered in a heightened standard for equipment safety. So you're seeing a lot of the offshore rigs refurbishing their blowout preventers, BOPs, a lot of the control equipment. In some case, it's total replacements. In other cases, you'll see existing new state-of-the-art rigs order a replacement BOP, and that's going to go on for sometime. You have very tight shipyard capacity and so it's not like operators can service or repair and refurb every rig, let's say over the course of 12 months. It's probably looking well into the latter part of next year for people to revamp their existing fleets.
Post-Macondo what you've also seen is an increased preference for your highest-spec drilling rigs. So on the jackup side, that's going to be 350-foot plus ILCs - independent leg cantilevers - with high-pressure, high-temperature capabilities. On the floating rig side, it's going to be your fifth- and sixth-generation drillships and semisubmersibles with dynamic-positioning equipment, and six- and seven-cavity BOP stacks. Operators no longer want the third- and marginal fourth-generation rig that that really can't be upgraded to the newer safety standards. And so we think offshore, you're also going to see a rather long retooling cycle of the rig fleet as well.
TWST: What's going on from a regulatory point of view? Do we have clarity or is it still uncertain?
Mr. Muztafago: Yes. It's still a little unclear as to what the exact requirements are going to be. Obviously, the rig contractors have been in lots of discussions with the regulators and do have some feel as to sort of what may or may not be the requirements when everything is finally hammered out. But I think what you're seeing is that operators are opting for upgrades that may go to some level above what they think ultimately might be the final decisions on equipment standards for offshore rigs. Most of these rigs are mobile and can be taken to another region, so ultimately in the U.S., if a rig can't meet the regulatory standard, those rigs and they'll be supplanted by something newer and higher spec. That's happened to some extent already.
TWST: So rigs may shift around?
Mr. Muztafago: Yes. To an extent, you can shift stuff around. Now that said, even outside of the U.S., if you look at, let's call it the Golden Triangle or the three major regions that really drive deepwater activity - that's West Africa, Brazil and the Gulf of Mexico - all three of those regions have really seen an increased preference for the higher-spec equipment, so the marginal rigs may find themselves moving over to places like Asia, Latin America and possibly Mexico that may be a little bit more suited to the regulatory environment there.
TWST: You mentioned shipyard capacity. Is the industry capable of meeting this kind of demand?
Mr. Muztafago: Longer term, it is. You obviously have different types of shipyards. So if you think about the shipyards in Korea, the big yards like Hyundai (009540.KS) and Samsung (010140.KS), they build the new rigs. There is some available capacity there. But by and large those yards aren't the ones that really engage in a lot of upgrading; it's the smaller regional yards. So it's not that they can't handle the capacity; it's just they can't handle it all in a very short time frame. You already have ongoing work related to all kinds of routine maintenance already - your standard inspections and whatnot that have to be done to rigs. It's an issue of really fitting things in. One of the problems that you encounter when you take a rig in, let's say to perhaps to upgrade the BOP, it's kind of like taking a 20-year old car to the garage. When you lift the hood to replace a simple thing, you end up replacing five other things in the process. And so, if you have a shipyard stay that's slated to be 30 days for example, that might extend to 60 or 90 days when you realize that, "oh, heck, not only do I have to replace a couple of parts of the BOP stack, but now I have to change some lines in the control systems because the old lines don't hook up the same way and there is a seal broken here and there." So it tends to really delay the process. You've seen CAM and NOV trying to work a lot more closely now with the rig contractors to go out and do some physical on-site inspections of the rigs that are coming in at some point in the future to have work done. They're doing this to try to determine what else "may need" to be replaced, so that they can have that equipment/parts in place at the right time, but that only mitigates it so far.
TWST: Does the industry have the capital they need to go ahead at this point?
Mr. Muztafago: When you're talking about capital to go ahead, are we talking about capital to drill, are we talking about capital to upgrade?
TWST: Let's do both. Let's start with the drilling.
Mr. Muztafago: Obviously on the drilling side, capital is a yearly requirement. So with oil prices at $100 WTI and Brent another $10, $15 north of that, I think the capital to meet drilling programs for most of the IOCs, or international oil companies, and NOCs, the national oil companies, is not really an issue. As far as the upgrading capital goes, for most rig contractors that clearly I think is there, but it will certainly take a chunk out of cash flows.
It's very apparent that there was lot of underinvestment in the offshore rig fleet during the good years of 2005 through 2008 when day rates were running up. It makes a lot of sense, because when you look at contracts on a lot of these deepwater rigs, they had bonus revenues associated with them. Basically what it means is that, if you can get a rig to work, 93% of the time you'll get an extra so many percent on top of the day rate that rig earns. And those bonus revenues can range anywhere between 5% to 15%, and a little above that in some rare cases. So it's very material to the bottom line for a driller, and obviously you don't want to shut rigs down anymore than you have to when they're earning that kind incentive revenue. Now the industry has really got to do catch up for what it didn't do in the good years back in the early and mid-2000s, so the prospects for the higher-spec rigs coming into work is good, and those rigs do generally tend to drive a lot of the cash flow and earnings generation for the big drillers.
TWST: Even given their cost?
Mr. Muztafago: Sure. If you take a typical, let's say sixth-generation, dynamically positioned drill ship, the cost to operate that drill ship even in a region like Australia, which tends to be the one of the higher-cost areas, might only be a $150,000 a day on a rig that's earnings a day rate of $500,000 or $600,000 a day. So the cash flow that those rigs generate is very substantial.
TWST: Is it a worthwhile investment?
Mr. Muztafago: Yes. Most of these rigs can pay themselves out in a reasonably short time frame for all intents and purposes. It could be a three to five year span depending upon the rate that that rigs earns, obviously the stuff that was signed at the peak of the cycle will have much quicker paybacks than the stuff that was signed earlier on. Rig capacity is still critically short offshore, particularly on the high-spec floating rig and jackup side.
TWST: What's going on from a technology point of view? Is there anything game-changing coming along?
Mr. Muztafago: The "game-changing" technologies in the industry, I think, are very few and far between - one of the technologies that's seen as potentially game-changing in the industry is subsea separation technology. FMC Technologies (FTI), which is one that we cover, is really the only one with a full-scale commercial subsea separation offering at this point. And I think they've deployed something on the order of seven or eight systems over five projects. Those are physically out there and working now. The industry is becoming more comfortable with the viability of the technology, and it will be a technology that will become more and more in demand. Effectively what the technology does is, it separates the oil and gas from the water and the sand at the sea floor, and then reinjects that water back into the formation. The future benefit to that is a lot of the remote regions that are going developed deepwater - West Africa, Brazil, even some areas that of deepwater Gulf of Mexico - will required FPSOs - or floating production, storage and offloading vessels - to produce from new fields because they lie way too far from infrastructure. The advantage of having a subsea separation unit is it frees up lot of space topside. That equipment is big and the FPSOs can only handle so much weight. When you go into places like West Africa and Brazil, those reservoirs are going to be depletion-drive, and basically what that means is that there is no water pressure in the formation forcing out the oil and gas, so in order to maintain the pressure in the formation, you will have to reinject water in to keep pressures up.
TWST: Is that the type of technology change that's coming along?
Mr. Muztafago: Yes. FTI's competitors - Cameron, Aker Kvaerner (AKSO.OL) - they are all working on the technology. As near as I've been able to assess, we think it's probably three to five years before any of the competitors are really going to be ready with a competitive commercial offering to compete, so FTI clearly has the first mover advantage. The system is very proprietary. There is some established track record with the technology now, so time will tell how big it becomes. Currently, you're only seeing a handful of projects every year that are really, let's say, viable candidates for subsea separation, but as you start to develop more and more in West Africa and Brazil, your potential offering will increase.
TWST: As you mentioned early on, the stock market has not been nearly as kind to the group as the reality of the business. Is that going to result in some M&A activity here?
Mr. Muztafago: I think there is a bit of a misperception in terms of M&A. If you take a look - and obviously this depends upon sort of which subsector that you look at - but if take a look at the M&A history, say, for the major multiservice companies that we cover - that's Halliburton (HAL), Schlumberger (SLB), Baker Hughes and Weatherford (WFT); and even the capital equipment companies, Cameron, FTI, National Oilwell Varco and Oceaneering (OII) - the number of large public transactions that these companies have engaged in has actually been relatively small. I would say, and I'm just throwing out rough numbers here, because I haven't tabulated it, but there's probably been three to four hundred small acquisitions done amongst this group of eight companies over the last 20 years. Of that, probably only 10% of them have been large public M&A deals. We see perhaps a little bit more potential in the capital equipment space for bigger M&A deals, but a lot of times those will be sort of technologies that come from the outside of the oil patch fairway that can be adopted to the oil patch. An example in the AMN or Ameron acquisition that National Oilwell Varco did later last year.
When you look at the multiservice companies, I think what you've seen there is that those companies have largely filled the gaps in their product-line portfolios as they did many, many acquisitions over the past 20 years, so we really don't see these companies stepping outside of their fairway. There has been some articles in The Wall Street Journal talking about some of these companies doing potential acquisitions of, let's say, land drilling companies. We don't think that's very likely. I think a lot of people on the Street tend to forget that most of the big multiservice companies have operated land rigs in the past, and have opted to get out of the business because they found that that's where most of the cost overruns came in. In fact, Schlumberger divested a bunch of rigs to Saxon Drilling and Eurasia Drilling just last year, I think it was. So for these guys, I think, it just doesn't make that much sense to focus on sort of the lower-spec iron when their real focus is on pushing high-end technology. When you get into the downside of the cycle, you have a lot of just idle overhead iron that I think these companies don't really need or want to have.
TWST: So it's somewhat what you see is what you're going to get.
Mr. Muztafago: I don't want to say what you see is what you going to get, because these companies will always engage in M&A, and it will be a lot of small nonpublic companies that you don't really a hear a lot about. The occasional one-off acquisition is always possible, but if you take a look at when most of these companies have done their big acquisition - take Schlumberger's acquisition of Smith International, take Baker Hughes' acquisition of BJ Services - these things are generally done at the low points in the cycle when times are bad and somebody is generally struggling to maintain a foothold in their market. And even at that, those acquisitions, if you look at the structure of them, had a very good strategic purpose. Baker Hughes lacked the pressure pumping component that BJ Services gave them. Smith International obviously gave Schlumberger the entire fluids business from M-I SWACO, the bits business, so there were very clear rational purposes behind those acquisitions as well. Now that we're at kind of a higher point in cycle at least in North America, it seems a lot less likely to us that you're going to see those types of large acquisition done.
TWST: As you mentioned, the group has not been treated kindly, what's the general investor attitude at this point?
Mr. Muztafago: I think it really depends whether it's a North American-levered company or an international-levered company. But I think, just in general, when you sort of think about the investor bias, it's really more on shorter-term trading right now. You've still got a lot of uncertainty with the European crisis. It's a little unclear yet as to what the pace of growth in the U.S. is going to turn out to be like. So I think people are trying to figure out whether or not we're going to have some type of pullback in the cycle before things reaccelerate, or whether we'll kind of be able to just trudge through this. The international markets are still a little bit sluggish. North America has definitely had a good run, and so I think people are trying to sort of figure out whether the demand to really drive things materially higher is going to come in the near term or whether it's a little bit longer-term off, and if we're going to see some slowing before we regrow.
TWST: What's your view on that at this point?
Mr. Muztafago: I think as long as crude prices continue to stay where they are, I think international is in reasonably good shape. What you've had is some of the large national oil companies sort of hold off on picking up investment simply because of the whole uncertain macroeconomic environment. North America I think will weather the gas prices, as I said, reasonably well in 2012 and will actually turn out to be better than people expect. So absent some derailing of the global economy from the European crisis or something else, I think we're at a little bit of a pause before we begin to move higher. Again, the caveat being that Europe sort of remains intact and that natural gas prices don't try to go down and touch the $1.50 mark and stick around there for a while.
TWST: What are you telling investors to do?
Mr. Muztafago: Obviously, you want to be exposed to the larger service companies that have the better-quality customers because those customers have a lot more line-of-sight ability. If you take the offshore NOCs and the IOCs, for example, who do big offshore projects, the lead times there are in some case seven to 10 years. So when you have projects of that scale, you don't just simply turn down overnight, and it takes a material alteration in the assumption of where crude prices will be three years from now and five years from now to slow that stuff down. A lot of the stuff is already in the pipeline; the equipment has been ordered. So that is something I think is reasonably well insulated. In North America again I think you need to stay exposed to the bigger service companies like Halliburton, Baker Hughes and Schlumberger. These companies cater to the higher-quality operators, large independent E&Ps, and the name and gain for those companies is growing volumes, growing production. Large independents have the ability to hedge somewhat, and have a lot of line of sight visibility on their shale-development programs. So they can certainly weather downturns a little bit better than some of your smaller operators can. I think it's the smaller service companies, if North America turns down, are going to feel that the greatest brunt of that turndown, so those ones are the ones that we think investors probably should stay clear from.
TWST: What names do you like at this point?
Mr. Muztafago: Halliburton is still our favorite name in the multiservice space. We think, as I said, that North America will turn out to be a lot better in 2012 than people expect. The fracturing market or the pressure-pumping market in North America is still critically undersupplied, and we think as long as you see 5% to 10% growth in rig count in North America this year, the pricing dynamic will actually hold up reasonably well.
When you look at the offshore markets, we like CAM and NOV both, and Cameron is exposed to North America as well as to offshore. The offshore market in particular as we've talked about is in a very heavy upgrading and retooling phase of offshore rigs. What I think people sometimes don't understand is a lot of that stuff is custom built, it's not just off the shelf. So when look at the high-spec providers like Cameron and National Oilwell, they are sort of the go-to companies when somebody wants to upgrade one of these rigs. Also, there is still probably somewhere on the order of 20 to 30 rigs worth of project shortage in the offshore markets yet, so we think that more newbuild rig orders are likely, and we just think the outlook for that space is extremely good and these companies are sort of the Tier-I providers to give you leverage to it.
TWST: Any names to avoid at this point?
Mr. Muztafago: I don't know that there is particularly names that we would say to avoid in our coverage, but we think that the valuations for some like FMC Technologies and Oceaneering have just gotten very rich. We really like the secular growth story around subsea demand at both of those companies, but we just like it at a lot lower valuations than they are currently at. Again, I think Weatherford is one who clearly will benefit from a recovery in international activity and pricing, but with international activity and pricing still being a little bit sluggish right now, we're sort of on the sidelines with them for the time being.
TWST: Anything else we should touch on?
Mr. Muztafago: No. I think we've covered the water pretty well.
TWST: Thank you. (TJM)
Note: Opinions and recommendations are as of 02/13/12.
Edward C. Muztafago
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