Helmerich and Payne Inc (HP) 2011 Q4 法說會逐字稿

Good day, everyone and welcome to today's program, the fourth-quarter and fiscal 2011 year-end earnings conference call. At this time all participants are in a listen only mode. Later you will have the opportunity to ask questions during the question-and-answer session. (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, Incorporated. 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 US 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. We ended our fiscal year as the most active land driller in the US, and continue to lead today with 228 contracted rigs.

Our outlook for 2012 remains positive, notwithstanding considerable macroeconomic uncertainty. The 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.

The oil patch is 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 promise 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 backlogs. It represents literally years of drilling visibility, most of which is still in the early development phase.

The oil 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 as both became early and important sponsors of our efforts to improve well cycle times.

Since then, we've led the US 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 oil derrick and sub structure. But in the end, these refurbished rigs are unable to deliver to the higher performance standard.

We've expected to see a steepening industry obsolescence curve as these oil 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 US, compared to only 100 rigs since 2006.

We've been high-grading as well. In the last eight months, we have sold six conventional rigs, five of which were SCR and one mechanical. In addition, we announced today that we decommissioned seven 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 take away 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 dayrates. Since July 1 of this year, we have secured 36% more contracted new build orders than our four 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 US 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 procurement 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 the 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 (sic - see correction below) shares 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 three operating segments, US land, offshore, and international, as well as the outlook for the first fiscal quarter of 2012, and a few trends that we are seeing in the business.

Let's begin with our US land segment fourth fiscal quarter results, where US land operating income increased 9% sequentially to $192 million, as the US 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 four 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 eight FlexRig5s, six FlexRig3s, and three are FlexRig4s.

Of the 47 remaining under construction, 38 will be delivered in fiscal year 2012, and the remaining nine will be delivered in fiscal 2013. Considering a cadence of four rigs per month, 10 additional delivery slots remain in our calendar year 2012 schedule.

The outlook for US 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 a 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, or 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 three-year period, compared to the AC drive rig count increasing by approximately 65% is significant. Today, there are over 200 mechanical rigs working in US 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 US 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 two 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 a 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 seven rigs active and two 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 five 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 four FlexRigs.

Five rigs are active in Columbia, five in Argentina, four in Ecuador, three in Bahrain, and two in Tunisia. Of the five stacked rigs, four are located in Argentina, and one 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 two 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.

The following are two examples for that belief. First, US unconventional shale play activity has a global reach. Many of the international unconventional basins would fit H&P's strategy and US 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 US 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 fewer opportunities for old conventional rigs and lower technology product offerings, but 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's shares in our investment portfolio, that number is 967,500 shares and with that, Clint, we will now open the call for questions, please.

Absolutely. (Operator Instructions). Our first question comes from the site of Robin Shoemaker with Citi. Go ahead, your line is open.

John, you mentioned briefly the breakdown of the new orders between Flex5, 4, and 3, so I didn't write those down quick enough, but where is the bulk, are most of the new rigs going out Flex5 for the deeper horizontal type of drilling?

Yes, Robin. The Flex5, that's really been the design criteria behind it, as we've mentioned over the years, we continue to see the lateral's 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 is kind of a new play for us, but that's really what the rig is targeted toward.

The FlexRig5 really builds on a lot of the Flex3 advantages, and then of course the FlexRig4s, the pad-drilling FlexRig4s have really drilled more pad-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 Flex5, 4, and 3 is?

Eight were Flex5s, six were Flex3s, and then there were three Flex4s.

Okay, and on the same topic, are these typically, how do these break out? Are they two- year or three- year term contracts or is two- year more common?

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

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

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

Okay, one final question then. On the cost of building a Flex5, 4, or 3, has there been any meaningful increase at your Houston facility or has it actually held level or declined 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 one-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 Flex5 is a larger, more capable rig, and will cost a little bit more. We've talked about our average costs, 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.

Okay, great. Thanks, Hans.

Our next question comes from the site of Jim Crandell with Dahlman Rose. Go ahead, your line is open.

Hans, you talked about years of industry visibility for horizontal drilling in the shales in the US, and indeed certain independents have talked about another 10 years plus of 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 plays have the potential for a 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, and I have too. Typically you're almost constrained to more of a budget cycle, but instead of talking about six 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 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 six months ago, a year ago about how many rigs 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 of 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.

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. So you would think that there would be rig count growth, but at the same time I believe there's also 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 what happens if natural gas prices improve? Then obviously you would expect to see further ramp up from here.

That's good answers. My second question for both of you guys as you talked about the mechanical rigs becoming increasingly obsolete, and this year is a turning point in terms of retirements. How about the electrical SCR rigs, which were built in the 1970s and early 1980s 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 point's a great one.

You can really add mechanical rigs and SCR rigs so nearly 75% of the fleet as being 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're focused on mechanical rigs but the point could really be extended to the SCR segment as well.

Great. Okay, thank you guys.

Our next question comes from the site of Joe Hill with Tudor, Pickering, Holt. Go ahead, your line is open.

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, who is talking about being able to steer a well with some top side equipment and what not, and 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 two or three years, in terms of your ability or desire to even offer a comparable service?

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. We 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 all 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, and that's going to play a larger role in the future.

If in fact a contractor plays a role in that, it would be hard to imagine that H&P wouldn't play a significant role in that process. Let's face it, that would be a fairly major shift from how the business has been handled over the last well, 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.

Okay, and kind of changing gears here a little bit, we're hearing some stories about LNG 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?

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 US, in terms of over the road trucks. 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. It's going to happen on an AC rig, a rig that's generating AC power, and is really the only place that is going to have an application for that.

Okay, thanks, John. I'll turn it over.

Our next question comes from the site of Dave Wilson with Howard Weil. Go ahead, your line is open.

Great. Good morning, gentlemen. Hans, or John, on the 17 new builds with the three different customers, is there any customer overlap with the four 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.

Sure. And so but the other, they are not new customers to H&P?

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

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? I know it might still be early and based upon some of your comments, it didn't sound like something -- a near-term worry but do you see any evidence of that, do you think we'll ever get to that point?

Well, I think there is 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 four a 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 is 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 -- because I think it's an impressive number that we've had 36% more contracts awarded to us since July than our top four competitors combined, so it's a significant lead that we have today over our peers.

I appreciate the additional color there. One final one, if I may. I just wanted to get your thoughts on margin degradation going forward. I mean, as 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. Do you think that this is something that can be prevented, or is it just part of the business in 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 Flex3 and a bunch of Flex4s, been working them a long time and I think we've got as good a handle on that as anybody.

Like I had 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, and 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 that's as a result of our performance.

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 pick up in natural gas prices, that could have an impact on day rate growth and margin growth in the future as well.

Great. Thanks for taking the questions. I'll turn it back over.

The next question comes from the site of Scott Gruber with Bernstein Research. Go ahead, your line is open.

Great quarter. Given that we're now several years beyond the shale gas land grab of 2007 and 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, 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, 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.

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 two years ago, it's definitely ramped up. 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, but compared to two or three years ago, yes it's been a steady ramp up in an area that we hadn't seen pad drilling before.

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 pull us through into the basins where they really want us. There are very good contractors in Canada. I can't speak to, I was thinking earlier about the AC market share. We know there's 25% in US 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 a shortened drilling season and that doesn't sound like a lot of fun to deal with. We have a lot of demand in lower 48. We said 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 big opportunities are, other international basins with unconventional plays.

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, and 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-speced that it 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 it in a mature phase today.

Okay, great. Thanks for the color.

Our next question comes from the site of Brian Uhlmer with Global Hunter Securities. Go ahead, your line is open.

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 that four 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 it 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 too. If we saw that, I think we would 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 do you think that four is your limit or there's potential, if need be on a demand pull, you could go to 4.5 or five in the short run with some more just changing around shifts and over time and things like that or is four pretty well maxed out?

I would not say that four 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 labor issues are well known with trying to find people that want to work in the patch, but on the other side of the 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 a sum of some of the R&M components and parts on a percentage basis that you passed through after the quarter ends. You can 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 inflationary-based. So it's really, 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, both 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.

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. 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, 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, as they continue to drive that equipment, and it's wearing out more quickly, and it has to be overhauled or it has to be replaced.

That's very helpful, thank you.

Our next question comes from the site of Tom Curran with Wells Fargo Securities. Go ahead, your line is open.

Returning to the 17 new build awards in the quarter, not to hyper-analytically parse the Press Release, but can we take the language three exploration and production companies to mean that none of these three 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 assume it might have already been answered. And then of the three, which had the largest number of new builds in its award, and what was that number?

I think the largest single portion was 10. It seemed odd, 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 two part question here. One is, with the contracts you've recently signed and are currently negotiating that are three 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 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?

Oh, I think that could be offset by most of the folks that are capable of adding new builds are sold out for all of 2012 or most of 2012. 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, 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 are pricing those at significant discount to what we command both in terms of dayrates and term.

And we're very comfortable, or I think you guys should be, about the level of returns that we're receiving and the new builds that we're announcing. So we can give you some more granularity on that if you want.

That will be great and I'll follow-up offline. 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, 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, 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 dayrates 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 four or five 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're 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 US with FlexRigs. They know our capability, I think as they begin to develop those resources, assuming 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 two, 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 oil field-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 real upside in international long term. It's just a question of how long is long term?

Okay, thanks for the color and taking the extra time. I appreciate it.

And our last question comes from the site of Mike Breard with Hodges Capital Securities. Go ahead, your line is open.

Another nice quarter. Your cash forward 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 have to solve how we return that to shareholders and a dividend increase would be a consideration. We have a nice record of paying a dividend for how many years, Juan Pablo?

Over 30, I believe.

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.

And then one last question, your new dayrates, have you broken the $30,000 level yet on the new rigs?

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 of the winterization, and there's also some pretty high spec drill pipe that's in place, and these wells used to be $18,000, $19,000 and we're seeing them go to $22,000, $23,000. So all of that obviously drives up the investment, and so I think that's where we're had it.

Okay, but in general, the highest dayrates are still in the mid to upper $20,000s?

Yes. Upper.

Okay, thank you.

There are no more questions at this time.

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

Thank you. Have a good day.

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