Helmerich & Payne, Inc. (HP) Q4 2011 Earnings Report, Transcript and Summary

Good day, everyone, and welcome to today's program, the Fourth Quarter and Fiscal 2011 Year-End Earnings Conference Call. [Operator Instructions] Please note, this call is being recorded. It is now my pleasure to turn the call over to Juan Pablo Tardio, Vice President and CFO of Helmerich & Payne Inc. You may begin.

Thank you, and welcome, everyone. With us today are Hans Helmerich, President and CEO; and John Lindsay, Executive Vice President and COO. As usual, and as defined by the U.S. Private Securities Litigation Reform Act of 1995, all forward-looking statements made during this call are based on current expectations and assumptions that are subject to risks and uncertainties as discussed in the company's annual report on Form 10-K and quarterly reports on Form 10-Q. The company's actual results may differ materially from those indicated or implied by such forward-looking statements. We will also be making reference to certain non-GAAP financial measures such as segment operating income and operating statistics. You may find the GAAP reconciliation comments and calculations on the last page of today's press release. I will now turn the call to Hans Helmerich, President and CEO. After Hans, John Lindsay and I will make additional comments, and we'll then open the call for questions.

Thanks, Juan Pablo. Good morning, everybody. We were pleased with the fourth quarter's record-setting results in terms of both quarterly revenue and rig activity. When the -- we ended our fiscal year as the most active land driller in the U.S. and continue to lead today with 228 contracted rigs. Our outlook for 2012 remains positive, notwithstanding considerable macroeconomic uncertainty. A significant 25% plus recovery in oil prices over the last couple of months has calmed some of the market's concerns over drilling activity levels going into next year. While natural gas prices continue to soften, now falling somewhere below $3.50 per M, many expect gas-directed rig reductions to be more than offset by oil and gas liquids-rich rig additions. Though Apache's no stranger to the volatility associated with macro geopolitics and today, the prospect of slowing global economic growth, heightened turmoil in the Middle East and the widespread sovereign debt crisis all promised to provide continuing volatility going forward. But even some legitimate hand-wringing over serious issues like these should not dampen the positives derived from the true energy revolution associated with the growing number of domestic, unconventional shale plays. After completely transforming the natural gas markets in this country over the last several years, this shale revolution has now fully engaged an increasing number of oil and liquid-rich basins. With prospective areas being added to the list regularly, it's challenging, really, to grasp the sheer scope and scale of drillable inventory that is being added to customer backlog. It represents literally years of drilling visibility, most of which is still in the early development phase. The whole service industry is busy positioning itself for the drilling requirements and the related equipment necessary to best engage these opportunities ahead. We started early and have been in a fleet repositioning exercise for over 10 years. I won't go into a detailed history of that effort here, except to say, we were fortunate prior to the advent of this shale revolution to have already designed, manufactured and gained valuable operational experience with the FlexRig. It would later come to be recognized as the land industry's first high-efficiency, high-performance rig. Of course, we didn't know at the time how suitable a safer, faster moving and more capable rig would be for the emerging shale plays. Thankfully, in those early days, the FlexRig's potential to meaningfully impact the economics of unconventional reservoir development in the Barnett Shale and the Piceance Basin was not lost on Devon and Williams [ph] as both became early and important sponsors of our efforts to improve well cycle times. Since then, we've led the U.S. land industry in what we have for some time called a new build replacement cycle. Because the shale revolution creates a new opportunity set, the increasingly complex drilling requirements are not well suited for the traditional rig refurbishment efforts where just select new equipment is simply retrofitted to an old derrick and substructure. But in the end, these refurbished rigs are unable to deliver to the higher performance standard. We expected to see a steepening industry obsolescence curve as these old refurbished rigs work less and less consistently and are increasingly difficult to maintain and adequately crew up. We're finally seeing this now. The land rig newsletter recently reported over 150 mechanical rigs have been retired by public contractors this year in the U.S. compared to only 100 rigs since 2006. We've been hydrating as well, and in the last 8 months, we have sold 6 conventional rigs, 5 of which were SCR and one mechanical. In addition, we announced today that we decommissioned 7 mechanical rigs, marking our 100% exit of H&P mechanical rig business. So we're now out of that business today. This move further solidifies our unique profile, which features 90% FlexRigs with a full 83% of those being AC powered. The takeaway is that we are not only the youngest, most capable and best positioned fleet for the opportunities presented by our customers' growing drilling inventory, but we are actually extending that advantage as we move forward into 2012. Today's announcement of 17 initial -- additional new build orders brings our total number of contracted orders since January of this year to over 71. In the last year, our peers have announced plans to build a number of new builds on spec. We've been fortunate to continue a long run of securing long-term contracts at premium day rates. Since July 1 of this year, we have secured 36% more contracted new build orders than our 4 largest publicly traded peers combined. In closing, my appreciation goes out to all of our folks that work hard to produce these results and drive forward our success. I'd like to turn the call now over to Juan Pablo.

Thank you, Hans. As announced earlier today, the company reported $435 million in income from continuing operations for fiscal 2011, representing an increase of about 50% as compared to the prior year. We were also pleased to see a sequential quarter-to-quarter improvement, reporting $122 million in income from continuing operations for the fourth quarter, as compared to $110 million during the third quarter. As will be further discussed during this call, we expect continuing growth into the first quarter of fiscal 2012, primarily as a result of an increasing level of activity in our U.S. land segment which continues to experience relatively strong market conditions. Net cash provided by operating activities was approximately $980 million during fiscal 2011. For the same year, capital expenditures totaled $694 million, which was lower than our prior estimate as a result of both cost efficiencies and timing of procurement related to our new build program. Our capital expenditures estimate for fiscal 2012 is approximately $1.1 billion, but the actual spending level for the year may again vary, depending primarily on the timing of procurements related to the company's ongoing new build construction program. Approximately 75% to 80% of this CapEx estimate is expected to be related to our new build program, 15% to 20% to maintenance CapEx and the remainder to special projects. At this point, we expect to be able to fully fund this CapEx program from existing cash and from cash to be provided by operating activities during fiscal 2012. Depreciation expense for fiscal 2011 was reported at $315 million. Given the continuing growth of our fleet, we expect our total annual depreciation expense to increase to approximately $380 million during fiscal 2012. As the company continues to grow, general and administrative expenses are also expected to increase to approximately $105 million during fiscal 2012. Interest expense after capitalized interest is expected to decrease to approximately $15 million during fiscal 2012. With a debt-to-cap ratio of approximately 10%, the company's debt level remained at $350 million at the end of the fiscal year, including $115 million scheduled for repayment during the fourth quarter of fiscal 2012. Our investment portfolio, primarily comprised of 8 million shares of Atwood Oceanics and 867,500 of Schlumberger, recently had a pretax market value of approximately $440 million and an after-tax value of approximately $285 million. Our tax rate for continuing operations during fiscal 2012 is, at this point, expected to be between 36% and 37%. I will now turn the call to John Lindsay, and after John's comments, we will open the call for questions.

Thank you, Juan Pablo, and good morning. The following are fourth quarter 2011 results for our 3 operating segments, U.S. Land, Offshore and International, as well as the outlook for the first fiscal quarter of 2012 and a few trends we are seeing in the business. Let's begin with our U.S. Land segment fourth fiscal quarter results, where U.S. Land operating income increased 9% sequentially to $192 million, as the U.S. Land segment took delivery of 11 new build FlexRigs during the fourth fiscal quarter. Revenue days increased 5% to 19,947, representing 217 average active rigs in the fourth quarter. An average of 141 rigs were active under term contracts, an average of 76 rigs were active in the spot market. Average rig revenue per day increased by $579 to $26,549. Average rig expense per day increased by $187 to $12,935. Average rig margin per day increased by $392 to $13,614. Our FlexRig new build program continues to deliver impressive results, including the 17 rigs announced today. Since January of this year, we have contracts to build and operate a total of 71 new builds and currently, 47 remain under construction and are being completed at the rate of approximately 4 FlexRigs per month. These newly contracted rigs are expected to be utilized in the Fayetteville Shale, Eagle Ford Shale, Bakken Shale and the Permian basin, and consist of 8 FlexRig5s, 6 FlexRig3s and 3 are FlexRig4s. Of the 47 remaining under construction, 38 will be delivered in fiscal year 2012 and the remaining 9 will be delivered in fiscal 2013. Considering a cadence of 4 rigs per month, 10 additional delivery slots remain in our calendar year 2012 schedule. The outlook for U.S. Land during the first fiscal quarter remains positive. As of today, we have 228 contracted rigs and 91% utilization rate. Of these 228 rigs, 147 are under term contracts and 81 are in the spot market, including 78 FlexRigs. In the first fiscal quarter of 2012, we expect revenue days to increase by approximately 5%, based on current contractual commitments. An average of 144 rigs are under term contracts during fiscal 2012, including an average of 148 for the first fiscal quarter. We expect average rig revenue per day in the first quarter to improve by $200 to $300, excluding expense increases that are passed through to customers. Average rig expense per day is expected to increase with the majority of the increase being wage-related and contractually passed on to customers. Therefore, we expect slightly improved average rig margin per day for the first fiscal quarter of 2012. Before moving to the next segment, I want to expand upon a point Hans made in his comments. An industry trend we expected several years ago, may now have reached the tipping point, whereby legacy mechanical rigs are being retired at a higher rate than in previous cycles. In addition to the rig retirement trend, another example of mechanical rig obsolescence is the comparison of mechanical rig activity at the peak in 2008, which was approximately 1,000 active rigs and today, are approximately 750 active mechanical rigs. And those are both in a similar total active rig count environment in a range of 1,850 to 1,900 total rigs. The attrition rate of the mechanical rig fleet of approximately 25% over a 3-year period, compared to the AC drive rig count increasing by approximately 65%, is significant. Today, there are over 200 mechanical rigs working in U.S. unconventional resource plays, and several of our customers believe those rigs are not well suited for more complex drilling, safety and environmental requirements and we expect many to be replaced by more efficient AC drive rigs as the replacement cycle progresses. Keep in mind, approximately 35% of the active mechanical fleet are large, publicly traded contractors, and H&P has exited the mechanical market in the U.S. and international completely. Now turning to the Offshore segment for fourth fiscal quarter results, where offshore operating income decreased by approximately $1 million sequentially to $11.9 million. Revenue days increased 10% sequentially to 701 days, as 2 rigs began accruing revenue days earlier than originally expected. Average rig revenue per day decreased by $241 to $54,176. Average rig expense per day increased by $3,796 to $32,393, primarily due to higher-than-anticipated mobilization expenses for platform rig start-up. Average rig margin per day decreased by $4,037 to $21,783. The outlook for offshore as of today, the segment has 7 rigs active and 2 rigs stacked. In the first fiscal quarter of 2012, we expect offshore revenue days to decrease by approximately 4% to 5% from fourth quarter levels and average rig margin per day to be roughly flat from fourth quarter levels. Now the outlook for the International segment, where fourth quarter results showed significant improvements. International Land operating income increased by approximately $4 million sequentially to $3.5 million during the fourth quarter. The primary factors driving the improvement were increased activity in Ecuador and Tunisia. Revenue days increased 13% sequentially to 1,625. Average rig margin per day increased by $2,337 to $7,690. The outlook for International as of today, the company's International Land segment has 19 active rigs and 5 stacked rigs. An additional rig is currently being shipped to Bahrain and it should begin operations in the second fiscal quarter of 2012, bringing our total rig count in Bahrain to 4 FlexRigs. Five rigs are active in Colombia, 5 in Argentina, 4 in Ecuador, 3 in Bahrain and 2 in Tunisia. Of the 5 stacked rigs, 4 are located in Argentina and 1 is located in Colombia. In the first fiscal quarter of 2012, we expect International Land revenue days to sequentially increase by approximately 6% and average rig margin per day to sequentially fall by 10% to 12%, resulting from costs associated with moving 2 stacked conventional rigs to access markets with higher potential work prospects. You've heard us previously express a belief that the International Land segment has long-term FlexRig growth potential. Following are 2 examples for that belief. First, U.S. unconventional shale play activity has a global reach. Many of the international unconventional basins with fit H&P strategy, and U.S. FlexRig unconventional shale performance, should provide opportunities for that expansion. Secondly, impressive FlexRig performance in Bahrain, Tunisia and South America. In each of these areas, FlexRigs have cut cycle times by half and are delivering well counts in excess of twice what each conventional rig previously was providing. And the customer has been able to reduce their contracted rig count by half. So in summary, unconventional plays in the U.S. Land market are shaping the competitive landscape by a shift to drilling more complex horizontal and directional wells. Whether oil, gas or liquid-rich production is the target, more and more operators trust H&P to provide FlexRigs. This ongoing complexity factor presents pure opportunities for old conventional rigs and lower technology product offerings that should provide more opportunities for H&P with our high-efficiency AC drive FlexRig fleet, quality personnel and critical organizational support systems. We remain encouraged by conversations with customers for additional new builds. And now, I'll turn the call back to Juan Pablo.

Thank you, John and let me just clarify my reference to the number of Schlumberger shares in our investment portfolio, that number is 967,500 shares. And with that, Clint, we will now open the call for questions, please.

[Operator Instructions] Our first question comes from the side of Robin Shoemaker with Citi.

John, you mentioned briefly the breakdown of the new orders between Flex 5, 4 and 3. So I don't -- I didn't write those down quick enough. But where is the bulk of the -- are most of the new rigs going out Flex 5, for the deeper, horizontal type of drilling?

Yes, Robin. The Flex 5, that's really been the design criteria behind it. As we've mentioned over the years, we continue to see the laterals get longer and the hook loads tend to get higher and higher torque requirements. So that's typically the case. We do have FlexRig5s that are going into the Fayetteville, we also have some in Marcellus and we'll have some in the Eagle Ford. And, of course, the Fayetteville's kind of a new play for us. But that's really what the rig is targeted toward. I mean, the FlexRig5 really builds on a lot of the Flex 3 advantages and then, of course, the FlexRig4s, the pad drilling FlexRig4s have really drilled more pad truck type work than any rig in the business, and so we've really just increased that capability.

Okay, and so some of these -- can you say again what the numbers were of the 17 Flex 5, 4 and 3 is?

Eight were Flex 5s, 6 were Flex 3s and then there were 3 Flex 4s.

Okay. And on the same topic, are these typically -- how do these breakout? Are they 2-year or 3-year term contracts, or is 2-year more common?

We're -- these particular rigs average over 4 -- these 17 rigs average over 4 years in term, I think it's 4.2 years per rig.

Okay, and am I correct, is that longer than the terms you were signing, say, earlier this year on average?

Yes. We've entered into some longer-term contracts. But in general, and really going back to 2006, on average, we've averaged -- it's been slightly over 3 years. Very seldom have we had any contracts, very few I can even think of that have been under 3 years. We've had several that have been 4 and 5 and even some 7-year term contracts over since 2006.

Okay. One final question then. On the cost of building a Flex 5, 4, or 3, has there been any meaningful increase at your Houston facility or has it actually helped level or decline with the higher rate of production at that facility?

Robin, this is Hans. I'm going to swing back to -- it was a good question on term because we know that some of our peers have signed 1 year term for new builds, and your point underscoring just that we stay with the long-term contract approach. In terms of your question about cost, the Flex 5 is a larger, more capable rig and will cost a little bit more. We've talked about our average cost and we don't give a lot of granularity on cost because of the competitive nature of it. But the average being in the $16 million, $16.5 million range and we have seen some oil field inflation there, but it's been offset by what you referenced in your question, just the economies of scale and our experience level of pulling out man hours per ton, time per ton have helped offset any price increases. But we're pretty confident that those expenses and costs are higher for the industry.

Our next question comes from the side of Jim Crandell with Dahlman Rose. James Crandell - Dahlman Rose & Company, LLC, Research Division: Hans, you talked about years of industry visibility for horizontal drilling in the shales in the U.S. and indeed certain independents have talked about another 10 years plus drilling at current levels. Do you see the visibility? Can you comment particularly on the major oil and liquids-rich shale plays at this point? The Eagle Ford, looks like Permian and Bakken, and talk about whether you believe that these rigs have the potential or these rigs, excuse me, these plays have the potential for significant ramp up in activity if the economics remain good during 2012?

Sure, Jim, and I'll let John add any of his comments. I think that the size of the inventory is again unique to this most recent cycle, where, as you remember, you've been doing this 30-plus years typically, and I have too. But typically, you're almost constrained to more of a budget cycle. But instead of talking about 6 months or a year now, our customers are talking about literally hundreds of wells to drill, that can get into the thousands, and the point I just wanted to make is we're just in a different phase of this business where you have additional basins being added and then you mentioned, like the Eagle Ford basins that continue to ramp up in their own scope and scale. So it's -- you almost have to step back and take a breath and realize, yes, there's still a lot of drilling to do. The other thing is we were talking 6 months ago, a year ago, about how many rigs we were running to secure leases. So a lot of the drilling has still been in the phase of trying to define the aerial extent of some of these plays, that's still going on somewhat. And I just wanted to make the point that I think we're in the early development phase of a number of these basins, with basins being added all the time. I don't know how much we want to try to get lots of details and granularity to what we see, Jim, you and other guys on this call probably have as good a visibility to that as we do. But I wanted to make the larger point that I think we're on the front end of this. John, do you have anything to add?

Jim, I might add to that. I agree that, especially the AC drive rig count is going to grow in the Eagle Ford, the Permian and the Bakken and a few other basins. I think from H&P's perspective, we definitely see incremental growth in our rig count. But as I mentioned in my comments, what you hear from our customers and other operators is that not every AC rig is incremental growth, it's replacement. And so it's replacing rigs whether they're mechanical or in some cases SCR rigs that can't do the work as efficiently. And so, I don't really know how much rig count growth per se you see from the levels that we are today. We see a lot of demand in the Eagle Ford, we see a lot of demand in the Permian and the Bakken, and so you would think that there would be rig count growth, but at the same time, I believe there's also a replacement cycle ongoing. And of course, what you said is we're considering that in today's pricing environment, with oil prices where they are and of course natural gas prices being as weak as they are. Now who -- what happens if oil -- pardon me, if natural gas prices improve, then obviously you would expect to see further ramp up from here. James Crandell - Dahlman Rose & Company, LLC, Research Division: Okay. That's a good answer. And my second question for both of you guys is you talked about the mechanical rigs becoming increasingly obsolete, and this year is the turning point in terms of retirement. How about the electrical SCR rigs, which were built in the '70s and early '80s and the competitiveness of those units as we see more FlexRigs out in the field, and it would seem to me as if while those are certainly much better rigs, that they are not competitive with the newer FlexRigs either.

No, I think, that's a great point, Jim. And we kind of focus on the mechanical just because it's just so clear and obvious to us. But as you know, we've been taking market share from that segment of SCR rigs that you just talked about. If you look at the rig count today and the type of mix, segment mix, that exists, mechanical rigs still make up 42% of that, SCR rigs, 33%, and then the AC drive rigs, just around 25%. So your points are great when you can really add mechanical rigs and SCR rigs. So nearly 75% of the fleet has been susceptible to the higher performing, high-efficiency rigs, taking market share from both of those segments. And it is a similar thought process of you have these 25-year-old SCR rigs that still require capital investment, still are less consistent and the performance doesn't match what we're doing. So your point's a good one. We were focused on the mechanical rigs, but the point could really be extended to the SCR segment as well.

Our next question comes from the side of Joe Hill with Tudor, Pickering, Holt. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Guys, we're seeing some of your competition talk up some of their non-land rig businesses a little bit. But I'm going to talk a little bit about directional here, and one competitor in particular is talking about being able to steer a well with some topside equipment and whatnot. What are your thoughts with regards to how much of a competitive advantage that gives that competitor? And I know you guys own a rotary steerable incubator right now, where do you see yourselves in 2 or 3 years in terms of your ability or desire to even offer a comparable service?

Hey Joe, this is John. I'm not aware completely on who the competitor is, and we won't go into that here. I have heard various competitors talk about their directional drilling business and competencies and they have some access to that. Obviously, us, with the rotary steerable business, we see that as a potential. The -- we've said for many, many years that the FlexRig operating system and the ability that we have with the data set that we acquire, offers us some upside potential in that space. And so I think clearly with the shift of 30% of oil wells being directional and horizontal, to now 70% industry, 80% for H&P, you're going to have more and more focus on the directional drilling component, the horizontal drilling component, that's going to play a larger role in the future. If, in fact, a contractor plays a role in that, it'd be hard to imagine that H&P wouldn't play a significant role in that process. Let's face it. It's a -- that would be a fairly major shift from how the business has been handled over the last, really forever. It's typically been directional drilling companies. So I think we'll have a place at the table if, in fact, that trend happens. And there are obviously with the rotary steerable company we have, there are efforts ongoing. Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And kind of changing gears here a little bit. We're hearing some stories about LNG [ph] rigs. Can you give us any comment on how you guys view those rigs and what you see the future for those rigs as?

You're really just talking about compressed natural gas essentially on location, as opposed to it being coming in through a pipeline, is that what you're referencing? Joe Hill - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes.

Yes. That's a potential. We've got bi-fuel rigs out there working today that are burning a combination of diesel and natural gas. That's a very good solution. As you begin to go straight natural gas, you've got pipeline constraints and I think the answer to that could be this compressed natural gas avenue. But again, there's still some logistical hurdles. The industry is not set up for that. But obviously, much like as you begin to think about changing the infrastructure in the U.S. in terms of over the road trucks. I mean, it's possible and it is something that can happen. The great news for H&P is that, again not to keep picking on mechanical rigs, but that isn't going to happen on a mechanical rig, that's going to happen on an AC rig, a rig that's generating AC power, and is really the only place that's going to have an application for that.

Our next question comes from the side of Dave Wilson with Howard Weil.

Hans, on the, or John, on the 17 new builds with the 3 different customers, is there any customer overlap with the 4 that were mentioned in last quarter in the 20 new builds there? And are these new customers to H&P?

There would be some overlap, Dave. And we're restricted, as you know, from kind of giving names and places. But yes, there is some overlap.

And so but the other -- they're not new customers to H&P?

No, not. Well, fairly recently new, but not completely new. Again, because as Hans mentioned, there is some overlap from the last call.

Sure. Okay. And then we've talked about replacement and the new builds replacing the less efficient mechanical SCR rigs. But at some point, do we get enough adds to where this efficiency starts to eat into the demand for the rigs? Is there -- it might still be early and based upon some of your comments, it doesn't sound like it's something a near-term worry. But are you seeing evidence of that or you think we'll ever get to that point?

Well, I think, there's certainly a possibility of that. There's going to be -- I would say, Dave, that, that was one of the reasons coming off of the latest downturn. We thought it was a big advantage not to have gone to the sideline and to have come out of the gate as quickly as we did with the new builds, and then being able to ramp up to the 4 month, because as you're suggesting in your question, at some point, there's a possibility, if the window doesn't close, it at least being reduced because you've run the course of this replacement cycle. We think that is some time off, and we also think related to our comments just about how people are continuing to add this drilling inventory that it's very difficult to look back on a historic rig count and pinpoint what is the proper rig count with the better mix of high-efficiency rigs, but then also just the number of basins and the drilling intensity that they require. So history's helpful, but I'm not sure a certain guide in that. So I don't know if that's helped answer the question, but I think it is one of the reasons we wanted to lead the business in this effort. And I think to put it into context, I mentioned that because I think it's an impressive number that we're -- we've had 36% more contracts awarded to us in the -- since July than our top 4 competitors combined. So it's a significant lead that we have today over our peers.

Sure. Now I appreciate the additional color there. One final one, if I may. I just want to get your thoughts on margin degradation going forward. I mean, because you just mentioned you have a pretty healthy number of rigs under term contract and the cost inflation, particularly on the labor side, can be passed through. But it seems like from an industry perspective, cost creep manages to find its way in somehow. You think it's sort of that this is something that can be prevented, or is it just part of the business and the business cycle?

Well Dave, I think we're positioned as well if not better than anyone as far as managing the cost side. If you consider the continuity of our fleet, we've got a bunch of Flex 3s, a bunch of Flex 4s, we've been working them a long time. I think we've got as a good handle on that as anybody like we've -- like I've commented. We think most of the cost increases, most of the inflation are going to be costs that can be passed through, there clearly will be some labor increases. But as we said, we're not expecting a huge margin growth, but I think one thing to consider, I think Hans touched on it before, but just to recap it is, we have pretty significant margin premiums over the rest of the market. And so, and that's as a result of our performance. So but there's no doubt there is a slowing in the margin growth. I mentioned natural gas prices. Right now, you've got a shifting going on from gas, dry gas to the oil and liquids-rich. You get a little pickup in natural gas prices, that could have an impact on day rate growth and margin growth in the future as well.

The next question comes from the side of Scott Gruber with Bernstein Research. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Given that we're now several years beyond the shale gas land grab of 2007, 2008, are you now starting to see a more significant shift toward pad drilling, as the leasehold drilling trend slows?

Well, that shift is occurring, and we've talked about it some before that in our minds, it has increasing application, not just in areas where the environmental impact sensitivity is real, but also in areas, the Eagle Ford is a good example, just where there's pad drilling because it's a more effective and efficient way to exploit the reservoir. So I don't know if we've seen anything -- John, you might add, if we've seen anything that indicates that is disproportionately ramping up or if we just see kind of a steady migration in that direction.

Well, I think you kind of touched on it Hans, with the -- typically it's been driven by environmentally sensitive areas and in areas that are heavily urban areas. But we are seeing it in the Eagle Ford, we are seeing it in the Fayetteville Shale, we are seeing it to a certain extent in the Woodford. I think we'll see some of that actually in the Permian. And so I think that does lead us to believe that there's going to be more pad drilling. Keep in mind this, as we drill wells more quickly in a single-well pad environment, that means you're using trucks more frequently. And so often, what you'll find are rigs that may have improved moving capabilities but they're waiting on trucks. And so that's not good for anybody. So if you can move the rig less frequently, drill more wells on a pad, then that has an application as well. So yes, I think it's going to continue to go that direction. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: But it sounds like overall, it's more of a steady migration today than any step-function change.

It's kind of hard to call. Well I can -- from 2 years ago, it's definitely ramped up. I mean, we've seen this -- we've kind of -- it feels like we've been talking about this for a long time, but we've seen it steadily ramp up over the last year or so. And -- but compared to 2 or 3 years ago, yes, it's been a steady ramp up in an area that we hadn't seen pad drilling before. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Okay. And then with horizontal drilling now dominating in Canada as well, and generally a lower quality fleet up North, is there any interest today in pushing into Canada and establishing a presence?

Well, Scott, we've talked about that before. I really think our best strategy would be what we have done, which is we have our larger customers kind of pull us through into the basins where they really want us. I -- there are very good contractors in Canada. I can't speak to -- I was kind of thinking earlier about the AC market share, we know there's 25% in U.S. land. I don't know what the AC market share is in Canada, but obviously there's a couple of contractors up there that have AC drive. I suspect there's some opportunities. But the other thing about Canada is you've got shortened drilling season, that doesn't sound like a lot of fun to deal with. We have a lot of demand in lower 48. We said last, I think last call that we feel like lower 48 is the place to be in North America and it will continue to be. And I think just considering International, think about AC, percentage of AC rigs internationally, I don't think it even registers. So that's really where the -- I think the big opportunities are, are other international basins with unconventional plays. Scott Gruber - Sanford C. Bernstein & Co., LLC., Research Division: Okay, and then a final question. You reviewed the outlook for the mechanical rigs and obviously made the decision to retire. Was there a similar review of the platform business and its importance in the portfolio today? Is there any desire to exit that business?

Well, that's a segment that we look at regularly, and it's one that we've said there's probably not a lot of growth opportunities there and at least we've changed our approach to the business where we would encourage a customer to make the full investment in the platform, including the top sides. They become so specific to the installation and so highly spec-ed that it probably makes sense for us to help in a design and construction mode and then as a labor contract, but probably not where we own that asset. So I think it's a business that provides very attractive returns to us, but we see in a mature phase today.

Our next question comes from the side of Brian Uhlmer with Global Hunter Securities.

I had a question, maybe I'm a little more bullish than some of the people asking you questions, but could we talk a little bit about expanding capacity, whether it's in Houston or in Oklahoma or looking at other sites for expanding capacity and getting above kind of that 4 per month run rate, if that's possible: a, in the short run; and b, what your longer-term thoughts are on that?

That's something that we continue to look at and consider. As you know, it's more than just rolling additional iron out, you're having to manage your training and the field execution of that, and so that's a big focus of ours, is making sure we continue to lead in terms of field performance, and we want to be able to look at any increase in cadence in that context. You also have supply-chain issues and supply-chain management issues in terms of availability of long lead items. But the other, I think, consideration for us is all of our new builds have been under customer contracts, and so it really is a demand-pull approach to the business. If we saw the visibility of that kind of demand and you said that you're bullish, we tend to be bullish to. If we saw that, I think we'd begin to seriously solve for how we increase capacity, but we're not at that point today, and I think it's something that we'll just watch carefully going forward.

And excuse me, sorry, do you think that 4 is your limit or there is potential if need be, on a demand pull you could go to 4.5 or 5 in the short run, with some more just changing around shifts and overtime and things like that, or is 4 pretty well maxed out?

I would not say that 4 is maxed out. So I think it involves just some of those other considerations.

Okay. Good deal. And following up on kind of the cost side. Obviously, the labor issues are well-known, with trying to find people that want to work in the patch. But on the other side of cost side, on the equipment and replacement and R&M side, are you seeing cost creep there as well? And do you see that debottlenecking at all, as some of these suppliers are expanding their capabilities for -- on the R&M side to service your parts?

Brian, this is John. I can't speak to at least in 2011. We haven't seen a huge increase in pricing for products that we're buying. But it stands to reason that you would begin to see that in coming quarters if the activity continues where it is or continues to ramp up. That would make sense. We've talked about the cost pass-through provisions on wages. There's also a cost pass-through provision on oil field inflation. Now that's got some delay to it. But nevertheless, there is some cost pass-through provision that we can get some success with there.

Okay, and that's kind of just the sum of some of the R&M components and parts on a percentage basis that you pass-through. After the quarter ends, are you going to see a little bit of lumpiness in your margins just on that regard, is that what you're saying?

As we get the producer price index for oil field supplies and as we see that percentage increase a certain amount, then we have the ability to pass-through that documented cost increase, that's inflation, that's inflationary base. So it's -- it really doesn't have to do with whether you're wearing something out at a faster pace. It has to do with the oil field inflation. But an important point to make here is, and it kind of goes back to my point earlier, we're in a better position to manage our costs than anyone else. Well, because of the age of our fleet, because of the quality of our fleet, we're also in a position to better manage higher productivity ramps. As I mentioned, we're drilling wells in half the time in a lot of cases. Well, that puts -- it's the same amount of work over half the time. So it increases wear on equipment. And we're really in a better position. If you think about 20 or 30-year-old rigs that are trying to ramp up to these higher rates of activity, higher rates of productivity, now that's going to drive costs up from that perspective, too. And that may be a trend that you see going forward in some of the companies that have some older assets that they continue to drive that equipment and it's wearing out quickly -- more quickly, and has to be overhauled or it has to be replaced.

Our next question is from the side of Tom Curran with Wells Fargo Securities.

Returning to the 17 new build awards in the quarter, not to hyper-analytically parse the pressure lease, but can we take the language "3 exploration and production companies" to mean that none of these 3 included any of the majors?

No, don't look at it that way.

Okay, I didn't think so, and I know there was a similar question earlier, but I didn't catch all of it. So I assumed it might have already been answered. And then of the 3, which had the largest number of new builds in its award? And what was that number?

I think the largest single portion was 10. I'm seeing a nod [ph], so yes, 10.

Okay. And that was a tender for 10 rigs or a series of tenders that in aggregate totaled 10?

No, that represented 10 of the 17 number.

Okay. Turning to current Tier 1 economics. A 2-part question here. One is, with the contracts you've recently signed and are currently negotiating that are 3 years, what's the cash on cash payback there currently? And then, given how weak the quarter was for your arch rivals when it comes to Tier 1, incremental Tier 1 contracts, as well as the weakening outlook for their remaining idle Tier 3 rigs, would you expect them to step up the intensity of their bidding in the spot market when it comes to Tier 1? In other words, could we see an amplification of competition on a pricing basis from here forward?

No, I think that could be offset by most of the folks that are capable of adding new builds are sold out for all of '12, or most of '12. So if you have demand that shows up in the system, it won't be easily or readily relieved by additional incremental new builds. So now, Tom, if the things weaken and back off, it's going to obviously have the opposite effect. But to the part of your question, I think, and we saw some anecdotal evidence of this recently, our peers are pricing their new builds and then they still have some spec new builds they have to place, but they're pricing those at significant discount to what we command, both in terms of day rates and term. And we're very comfortable, or I think you guys should be, about the level of returns that we're receiving in the new builds that we're announcing. So we can give you some more granularity on that if you want.

That would be great, and I'll follow-up off-line. Two more questions here, please. The first is, if spot rates were to plateau at the current level and hold there, and your contracted Tier 2 count was also to remain flat, at -- in which quarter would the Tier 1 rigs rolling over stop rolling to higher rates?

I know that doesn't happen for a little while, but I'll ask JP to add some color on that.

Sure. Tom, there's -- as you know, there's a lot of moving variables that go into the answer to your question. But a simple way to answer it is, if we were to hold or see spot day rates be flat for the next several quarters, what we would see is, given our term contracts that are already in place, we would see a slight increase, perhaps a few hundred dollars over the next 4 or 5 quarters.

Okay. And then the last one for me here. KCA Deutag just inked a contract for a second rig in Poland, was that an opportunity you had a chance to bid on and if so, did you? And then, just more broadly, could you expound upon your strategy for Europe? Are you marketing one or more of the FlexRig generations into that market or have you designed a fit-for-purpose model? And are you focusing on or only open to entering for specific customers?

Tom, this is John. We have looked at the European shale plays, Poland, specifically, and we've talked with several customers, we've made visits. We believe we do have the solution. I don't know which tender you are particularly addressing, but we have bid on some. And I think what we find is that the rates are -- the rates and the returns are not going to meet our hurdle rates. But what we are encouraged by is that the customers that are on the ground there that do have acreage positions are customers of H&P in the U.S. with FlexRigs. They know our capability. I think as they begin to develop those resources, assuming that, that happens in a reasonable time, then I think we'll be involved in that. What we do continue to hear is that it seems like every quarter or 2 well, it's not in 2012, it's in 2013, and then you'll hear some folks talk about 2014. As you know, there's pretty significant infrastructure hurdles to getting pressure pumping and other oilfield related things in place. So it's going to be -- I think it's going to be slow, but I do think as we said in our international comments, we have some real -- we feel like there's some real upside in international long term, it's just a question of how long is long term.

And our last question comes from the side of Mike Breard with Hodges Capital Securities.

Your cash flow is running well ahead of your capital expenditures. Have you discussed paying possibly a special dividend or a substantial increase in your regular quarterly dividend?

Well, as we go into a free cash flow mode, Mike, we're going to solve for how we return that to shareholders, and a dividend increase would be a consideration. We have a nice record of paying out dividends for, how many years, Juan Pablo?

Over 30, I believe.

Yes, I know it is over 30. That's something we would certainly look at, Mike. But we don't have anything to announce on this call in that regard.

Okay. And then one last question. Your new day rates, have you broken the $30,000 level yet on the new rig?

We're trying to decide how much to say.

I believe there may have been some that were North country operations, Mike. As you can imagine in the Bakken, some of these plays, you've got all the winterization and there's also some pretty high spec drill pipe that's in place. Now these wells used to be $18,000, $19,000, and we're seeing them going to $22,000, $23,000, so all of that obviously drives up the investment, and so I think that's where we're headed.

Okay, but it in general the highest day rates are still in the mid to upper $20,000?

Yes. Upper, yes.

There are no more questions at this time.

Everyone went to lunch. Well, thanks very much for joining the call. Appreciate it.

Thank you, and have a good day.

This concludes today's conference. You may now disconnect.