Helmerich and Payne Inc (HP) 2012 Q1 法說會逐字稿

Good day, everyone, and welcome to today's program. 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 will be recorded and I will be standing by if you should need any assistance. It's now my pleasure to turn the call over to Juan Pablo Tardio, Vice President and CFO. Please go ahead, sir.

Thank you and welcome, everyone, to Helmerich & Payne's conference call and webcast corresponding to the first quarter of fiscal 2012. With us today are Hans Helmerich, Chairman 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, Chairman and CEO. After Hans, John Lindsay and I will make additional comments and will then open the call for questions.

Thanks, Juan Pablo. Good morning, everyone. As the Company continues to grow, we hit three notable milestones for our most recent quarter. We recorded our all-time record level of income from continuing operations. We also reached our best-ever levels for revenue and rig activity for the last quarter.

On this call, we will detail some of the drivers that enabled this performance and walk through some of our expectations going forward into 2012, including some moderation in the second quarter as daily expenses returned to more expected levels from this quarter's significantly reduced number.

Before that discussion, let me comment for a moment on the dire state of the natural gas market. Prices are plummeting. We see storage overflowing and an ample behind-the-pipe supply, so the question becomes how much downward pressure may this bring to bear on the domestic land drilling market.

Clearly a combination of these factors in previous cycles would have resulted in a predictable drop of the rig count. In fact, for decades, natural gas pricing was the single most important barometer for the overall rig count. Today, oil and liquids-rich gas have transformed the domestic drilling landscape.

Oil-directed drilling has been on a steady march up while dry gas-drilling has lost ground. And while the gas-directed count will even now most likely accelerate its decline trend, many expect any fallout to be partially or fully offset by displaced rigs being redirected to oil and liquids-rich targets. This transition has been underway since the summer of 2008 and may well become more pronounced and impactful. It has been combined with the transition towards more complex well design and higher performance rig requirements.

We would expect higher-performing tier one AC drive rigs will be best positioned to make the transition while older, underperforming rigs will be more likely to be less sidelined, unable to secure the customer sponsorship to be mobilized and re-tasked for other work. It has become a type of a zero-sum game where oil and liquids-rich gas continue to gain over dry gas and where high-efficiency rigs continue to displace mechanical and SCR rigs.

We are fortunate to have a customer roster with substantial multi-year drilling inventory capable of shifting targets and taking advantage of strong oil prices. Also, we're well-positioned with the most modern and capable fleet in the industry and by having a historically small exposure in terms of rigs focused on dry gas. Less than 10% of our total active US fleet is currently engaged in dry gas-directed drilling on the spot market.

Additional dry-gas directed rigs are under term contracts and we would anticipate some of those to transition to oil and liquids-rich targets over time as well. We've been asked if some demand for new builds will be satisfied by higher- end dislocated rigs during 2012. Our focus will remain the same because we are coming off such a robust order book from 2011 that totaled 71 fully contracted new builds.

We continue to deliver four rigs each month on time and on budget. We have 40 orders remaining in the queue, approximately 30 to complete in fiscal 2012, and 10 slotted for 2013.

Some of our peers continue to have significant numbers of their announced 2012 new-build programs without contracts. We would expect to see some of those deliveries delayed and one would think their appetite for additional spec new-builds would be suppressed.

In the meantime, we're solving more for 2013 as we have all but seven slots fully contracted and spoken for in calendar 2012. Notwithstanding the added uncertainty of depressed natural gas prices, we remain upbeat that our business model of delivering premium drilling services will remain in strong demand and provide us with attractive opportunities in 2012 and beyond.

Before closing, let me mention that this is my first call as Chairman, having assumed that title with dad's passing three weeks ago. Lots of nice things have already been written and said about him, so I won't do that here. Having worked together for 30 years, I do remember he would say there are more important things than quarterly earnings. Think more about the kind of Company you want to build in the long-term.

And while he loved business and was part of this Company for 60 years, he would say there are more important things than being the best business person around. So especially for the younger analysts and investors on this call, let me pass on his encouragement to us to be folks of strong character, good parents, to make an impact on our churches and communities. So in his memory, I'll share those thoughts for all of us today. And with that, I'll turn the call back to Juan Pablo.

As announced earlier today, the Company reported $144 million in income from continuing operations for the first quarter of fiscal 2012, representing an increase of almost 20% as compared to the immediately preceding quarter. This very significant increase was mainly attributable to our US Land segment, where we experienced continuing improvements in pricing and activity levels, and a very favorable reduction in daily rig expenses.

As Hans mentioned, our US Land daily rig expenses are expected to return to a normalized level during the second quarter. Nevertheless, we do expect continuing overall growth in revenue and rig activity as we transition to the second fiscal quarter, primarily as a result of an increasing number of FlexRigs in our US Land segment.

Our capital expenditures estimate for fiscal 2012 remains at approximately $1.1 billion. Our depreciation and our general and administrative expense estimates for the year also remain at approximately $380 million and $105 million respectively. Interest expense after capitalized interest is now expected to decrease to approximately $13 million during fiscal 2012, and our tax rate for continuing operations during the year is expected to be approximately 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. My comments will be on the operational results for our first fiscal quarter 2012 for our three operating segments -- US Land, Offshore, and International, as well as the outlook for the second fiscal quarter of 2012. I'll begin with our US Land segment first fiscal quarter results where US Land operating income increased 17% sequentially to $225 million as the US Land segment took delivery of 11 new built FlexRigs during the first fiscal quarter.

Revenue days increased 5% to 20,968 days representing 228 average active rigs in the first quarter. An average of 145 rigs were active under term contracts, an average of 83 rigs were active in the spot market.

Average rig revenue per day increased by $312 to $26,861 per day. Average rig revenue per day for rigs working on term contract during the first fiscal quarter was approximately 5% higher than average rig revenue per day for rigs working in the spot market.

Average rig expenses per day decreased by $643 to $12,292 per day primarily as a result of what we believe were only temporary reductions in maintenance and supply costs. Consequently, average rig margin per day increased by $955 to $14,569 per day.

The outlook for US Land during the second fiscal quarter remains positive. H&P remains the most active US Land contractor, as we have 236 contracted rigs today and 23 idle rigs, a 91% utilization rate. Of these 236 rigs, 152 are under term contracts and 84 are in the spot market, including 82 FlexRigs. Of the rigs in the spot market, 63 are drilling in areas that typically target oil and/or liquid-rich gas.

In the second fiscal quarter of 2012 we expect revenue days to increase by approximately 2% to 3%. Based on current contractual commitments, an average of 152 rigs are under term contracts for the second fiscal quarter of 2012, an average of 148 rigs for the last three quarters of fiscal year 2012, and an average of 121 rig for fiscal year 2013.

Average rig revenue per day in the second quarter may improve slightly, up to $200 per day excluding expenses that are passed through to customers. While average rig expense per day quarter to quarter is difficult to predict, we expect the base level of average rig expense per day to return to a $12,700 a day range similar to previous quarters, excluding any expense increases that would be passed through to customers. We do expect wages to increase during the second quarter in a range of approximately $500 per day.

Our FlexRig new build program continues to lead the industry in delivering advanced technology, AC drive rigs on time and on budget. Including the three additional new FlexRigs announced today, during the past 13 months, we've announced signed term contracts to build and operate a total of 74 new FlexRigs, and currently, 40 remain under construction and are being completed at the rate of approximately four rigs per month.

The three newly contracted rigs are expected be utilized in the Eagle Ford Shale, the Bakken Shale, and the Permian Basin and all three are FlexRig 3s. Of the 40 remaining under construction, approximately 30 are expected to delivered in fiscal year '12 and 10 in fiscal '13. Considering a cadence of four rigs per month, seven additional delivery slots remain in our calendar year '12 schedule.

A quick review of our new build success of delivering FlexRigs on time with safe and efficient operations. One year ago we had 198 rigs operating in US Land, and we announced our new build cadence was increasing to three rigs per month beginning in January of 2011. We successfully delivered three rigs per month from January through September, plus we increased our cadence to four rigs per month beginning in October.

As of today, we've delivered a total of 40 new FlexRigs since our conference call on January 27, 2011. In addition to our rig construction group delivering rigs on time, we are also proud that the H&P rig leadership and crews on the 40 newly commissioned FlexRigs were able to deliver safety performance during the first year of operation at a rate approximately two times better than the industry average.

Now we'll talk about the Offshore segment, and our operating income increased slightly to $12.2 million. Revenue days decreased 1% sequentially to 697 days; average rig margin per day increased by $388 to $22,171 per day. Outlook for Offshore. As of today, the Company's offshore segment has seven rigs active and two rigs stacked although our rig in Trinidad is returning to the US and is expected to stack at end of the second fiscal quarter.

In the second fiscal quarter, we expect offshore revenue days to decrease by approximately 10% and expect average daily margins to decrease by 10% to 15% as some rigs transition between projects.

And now I'll turn to the International segment where International Land continues to show improvements quarter to quarter. Operating income increased by approximately $4.4 million sequentially to $7.9 million during the first quarter. Revenue days increased 6% to 1,729 days. Average rig margin per day increased by $1,325 to $9,015 a day. The primary factor driving the increase in average rig margin per day was a $1.6 million retroactive one-off day rate adjustment.

On the last call, we discussed moving two stacked conventional rigs to access markets with higher potential work prospects, and we expected those to occur during the first fiscal quarter; however, now those rig moves are occurring in the second quarter and today both rigs have contracts.

Outlook for International. As of today, the Company's International segment has 20 active rigs and an additional 2 rigs contracted and in transit between countries. Six rigs are active or contracted in Columbia; five in Argentina; five in Ecuador; four in Bahrain; and two in Tunisia. Of the four stacked rigs, three are located in Argentina and one is located in Colombia.

In the second fiscal quarter of 2012, we expect International Land revenue days to be sequentially flat as one rig became idle in Colombia, and the two rigs currently in transit will not have a significant affect on revenue days until the third or fourth fiscal quarters. Given the absence of the $1.6 million retroactive adjustment payment and the recent stacking of one rig in Colombia, we expect average rig margin per day to sequentially fall by 10% to 15%.

One highlight I would like to point out regarding the International segment. Included in today's 20-rig active fleet is the first FlexRig 3 contracted and active in Colombia. You've heard us talk previously about the impressive FlexRig 4 performance in Argentina and Colombia, and this contract is a result of that exceptional performance.

As you may recall, the FlexRig 3 is designed to exploit deeper wells than the FlexRig 4 while maintaining fast rig moves and it's well suited for the majority of wells that we're going to be seeing internationally. We believe the international market in general appears to be improving for FlexRigs in South America and the Middle East as a result of H&P's performance in safety, drilling, and rig moves.

In each of these regions FlexRigs have cut well cycle times in half and are delivering well counts in excess of twice what each conventional rig previously was able to provide.

In closing, we believe the current trends are advantageous to H&P where unconventional oil and liquid-rich plays have proven to be a game changer in the US Land market as operators shift to drilling more complex horizontal and directional wells. This drilling complexity factor presents real challenges for old conventional rigs and lower-technology product offerings.

An example of this change was commented on during our last earnings call. An industry trend where we expected several years ago may have reached a tipping point whereby legacy mechanical rigs are being retired at a higher rate than in previous cycles. Another data point to keep in mind. As well complexity increases and natural gas prices soften, our three largest public competitors' active fleets rely heavily on their old conventional fleets to maintain their current activity levels.

The competitors' fleet composition of active mechanical and SCR rigs ranges from 50% to 75%. In a very strong market where both oil and natural gas pricing is high, the old conventional rig fleet is at a lower risk of being stacked. But in a sub-$3 gas price environment when dry-gas drilling is losing favor, the bottom-tier performing mechanical and SCR rigs are more likely going to be stacked and are a less likely candidate to be redirected and mobilized to oil and liquid-rich basins.

H&P, on the other hand, no longer operates or markets mechanical rigs, and less than 10% of our active US Land fleet today is made up of SCR rigs. The rest of H&P's active fleet in US Land, over 90% of it, is made up of AC drive advanced technology FlexRigs. These market trends, along with encouraging conversations with customers for additional new builds, provide us with confidence that more opportunities for new FlexRigs will continue. And now I'll turn the call back to Juan Pablo.

Thank you, John, and Alicia, we will now open the call for questions, please.

Thank you. (Operator Instructions) We'll take our first question from William Conroy at Pritchard Capital Partners. Your line is open.

Good morning, and thanks for taking my question.

Good morning.

Really, John, just wanted to ask you about the last point you made, which was the potential for additional new build opportunities and ask you to just flesh that out a little bit. How do you see that playing out in light of what looks like the near term environment and can you maybe just give us a little bit more color on the level of interest or the market for additional new builds? Maybe not in the next -- during the current fiscal year, but as we get into next fiscal year?

Sure, William. The-- right now we're probably eight or nine months out as far as our next new build delivery slot that would be available. We have quite a few conversations still ongoing with customers regarding some of those new build slots. Most of those conversations are in the calendar year 2012. Occasionally we'll have some discussions regarding 2013.

I really think what's driving it is much of what Hans and I tried to portray, which is the complexity of wells and how those wells are changing over time, and especially now with some softness in the dry gas basins, you're seeing rigs being redirected quite often. And in a lot of cases on the lower end rigs, I think what we're seeing is a lot of those rigs are getting stacked because they're not getting moved because of the cost associated with moving them as well as just the overall performance.

So, we believe that if you look at the overall market in terms of available AC drive rigs, we think there's opportunities to continue to add. And again, I think the biggest challenge right now is that we're about eight or nine months out.

Thanks very much, appreciate it.

We'll take our next question come from John Daniel with Simmons and Company. Your line is open.

Hi. Really, just one from me this morning. I understand the theory about the new rigs displacing the old rigs, but I would assume that some of these old rigs don't want to go quietly. And so, at this point have you seen any price discounting by your peers? And if not, at what point do you expect the price discounting to begin and then how would that influence your pricing strategy?

This is Hans, and I don't think we're seeing that yet in full force, but if you go back coming off of the last downturn, what developed is a pretty clear bifurcation in the marketplace, and there was discounting as you inferred from those lower-performing rigs. So, we would expect that that could happen and they won't go quietly.

We've seen again coming off of that down turn, the higher-performing rigs get taken up quickly and the activity has been very strong across the board, not just with our tier one rigs but with our peers. And so, to the first question and to your question as well, I think that there will be a transition time and the market will absorb some of this.

We've just come off -- I wouldn't read too much into our three rig announcement. We've just come off the holidays and kind of the turmoil around gas prices, and I think the market will take a certain amount of time to settle down, but I don't think the longer term trends towards a replacement cycle really get pushed to the side. I think that's something that continues to run going forward.

Okay. But is it safe for me to assume then, Hans, as you look at the market today that it's reasonable to assume that, as we get towards the back half of the year, all else being equal that pricing begins to trend lower?

Well, I guess I'm a strong believer in the segmentation of the business and that we've seen it. There was some question going into this last recovery in '10 and '11, would there really be a differentiation and a segmentation, and in fact, there has been and you've seen the pricing related to that. So, the notion that there's this drag effect.

I think that may happen just on the margin, because I really think the customer's determined to have the right equipment matched with his development and exploitation challenges, and I just think that the segmentation becomes very clear and it won't have the contamination or contagion that you might expect.

Okay. Fair enough. Thanks for taking the time. Take care.

Thank you.

We'll take our next question come Waqar Syed with Goldman Sachs. Your line is open.

We can't hear you. Are you there?

Yes, can you hear me now?

Just a little bit. You have to speak a lot louder.

Just one second -- Hello, can you hear me now?

Good.

Sorry about that. Just first question. Do you have any guidance on deferred taxes? Were any taxes deferred in the quarter, and what do you think for the remainder of the year?

Waqar, that's a good question. This is Juan Pablo, we had approximately $187 million of deferred income taxes in fiscal 2011, and our best guess at this point is that we have a similar amount during the year distributed throughout the four quarters, perhaps the first quarter maybe a little higher than the other ones, but it's hard to tell by how much.

Okay. And secondly, Hans, do you see any cancellations of contracts that we saw previously? Do you fear that could happen or is there any talk on that, as -- you have companies lay off their dry gas rigs, I know they have some of your high end rigs under term contracts there?

Waqar, I think what we're seeing is a much more orderly and smooth transition in this market going forward than what we all lived through from the fall of '08 into early '09 and I think that was more related to the financial crisis and a board room decision of wanting to make sure companies preserve their liquidity and just trying at great lengths to secure that.

So, I think this is more of a normal orderly process and it's why I mentioned to John, I don't think it will have a huge drag going forward on pricing and again, we're hoping that -- we've really been in this transition since the gas-directed rig count peaked in July of 2008. So, I think companies look at it in a fresh way trying to project gas prices and then the combination of things.

But as we mentioned, we're encouraged by just the sheer inventory level, especially the customers represented in our customer roster have to redirect towards oil and gas liquids-rich drilling. So, that's where I think some of the order comes in and the smoothness in the transition.

You had mentioned -- you probably mentioned before as well, and I was kind of -- I joined in late, but would you say about 30% of your rigs are currently working in traditionally just the dry gas place, is that right?

Well, it's actually -- what we tried to talk about is on the spot market, we have 20, 21 rigs in that category. So, it really represents 10% of what our active spot market rigs are doing. Then we have additional rigs that are under term contract, and we're seeing now the customer again in kind of an orderly way is making the decision whether or not to redirect that rig. So, I'm glad you asked, because I think it's an important point that in the spot market, just 10% of our rigs are directed towards dry gas.

Okay.

Waqar, this is John. Another example in you look at the Haynesville, I think at our peak we had 28 rigs working in the Haynesville. Today we're down to 5 or 6, but all of those rigs and most of those 28 were on-term contracts. And those rigs have all been moved to either the Eagle Ford, the Permian, or the Cain and Woodford.

None of those rigs were stacked -- I mean essentially the customers were using the best rigs in the basins they can make the most money with. And so I think that's what we're going to -- as Hans alluded to, I think that's what we're going to continue to see is the best rigs being mobilized to the basins where the economics are the best.

One other question just on a big picture. When we look at the rig count in the US, by our estimates about 70% of all drilling right now, if not more is on oil and liquids-rich, and there is very little limited dry gas drilling going on, and only in maybe the Haynesville and Northeast Marcellus, there is some rigs in any meaningful way they're drilling for dry gas.

The rest of the places like the Barnett or Fayetteville and others, there are very few rigs that are drilling. And so, even if you cut them by 50, the impact is not that huge in the overall rig count. Do you see it that way, as well?

I think so. Yes, I think that's what we'll see, Waqar. You're right, the numbers aren't big, although the Haynesville -- I don't know what the latest is in the Haynesville, but that's still a pretty active basin. But I think a lot of those rigs will continue to migrate out.

So, we had 180 to at its peak. Now it's down to maybe 90 rigs. So, even if you have like a 50% reduction it's another maybe 40, 50 rigs to go. Is that kind of fair?

Yes. And Waqar, this is Hans again. I think you're making our point that we've already seen a lot of the transition take place and what is remaining in the queue. We're just in a very good position with the quality of our fleet to continue to make the transition and it be less disruptive.

Okay. Thank you very much. Appreciate it.

We'll take our next question from Scott Gruber with Bernstein Research. Your line is open.

Yes, good morning, gentlemen. Hans, you've discussed the outlook for additional FlexRig orders in the US, but with interest in some shale development programs progressing now down in Latin America, we do have established positions. Is there a potential for International FlexRig orders to begin complementing domestic orders possibly later this year, or is that still off of the horizon?

Well, I think the answer is, we hope to see, and I think we will see, and we're having conversations with customers about adding to our FlexRigs into the international part of our fleet. And then it gets back, Scott, to exactly what your kind of focused on, is that a end of a 2012 event or a 2013 event, and our thought is it's a 2013 event, but tough to predict.

I said recently that we have seen less focus and interest from our customers recently than we had six or nine months ago, but I think coming off of the holidays we're starting to have some additional conversations and talks. So, that kind of ebbs and flows, but I think you should focus more on it being impactful later in 2013 than later in 2012.

Okay. So that would be a 2013 delivery of equipment, or 2013 placement of the orders for FlexRigs?

Well, we don't have anything really to tell you or announce in terms of rig orders being placed. And we're pretty disciplined around not doing that until we have signed contracts, but I do think the interest level is there from customers, and you've heard us say before that part of what we're hoping to lever off is the satisfied group of customers in our roster that wants to take us into -- and the whole service complement that they've been successful with here domestically, take that into international markets, and so we would expect that to occur.

Okay. Great. That's all for me. Thanks.

Thank you.

We'll take our next question come Brad Handler with Credit Suisse. Your line is open.

Hello, thanks very much. Good morning,.

Good morning.

Good morning.

Couple of follow-up questions please around your cost guidance, I just want to make sure I understood it. You mentioned a $500 a day labor increase. Is that fully implemented in this second fiscal quarter?

Yes, Brad, it will be fully implemented in the second quarter.

Okay. So, there's $500 a day on average. I think you mentioned $12,700 a day average expense per day guidance? Is that right?

Well, the $12,700, Brad, is really a reference to a more normalized cost, like what we've seen over the last couple of quarters. And as we've said, it's hard to nail the number right now, but it's kind of the range that we're thinking.

Understood.

We spent -- every quarter we spend a lot of time and effort on trying to work on costs and controlling costs and working on a lot of different systems and processes, and this quarter turned out very, very nicely. We would love to see the next quarter turn out nicely, but I think we have to take into account kind of what the average has been and so that's why we're talking that $12,700.

I think I see. If you were at $12, 300 and you add for labor, it doesn't sound like you're anticipating any of those lower maintenance or lower supply costs to go away this quarter. In other words, so you might be able to keep that lower level of cost. I don't know want to make too much of numbers that I think maybe you're saying are indicative, but is that what you're suggesting for us?

Brad, this is Juan Pablo. I think that the $12,700 level that was mentioned excluded any increased expenses that would be passed through to customers through increased day rates. And so the $12,700 would be the base and then the 500, and if there were are any other pass throughs would be additive to that.

Oh, I see. Okay. All right, I think that clarifies it, great, thank you. Second question, unrelated. Maybe you can just help me understand something a little better. If you have a rig that's on term contract and it's -- you mobilize it to a different basin, presumably a liquids-rich basin, what happens to the expenses of that mote?

Brad, this is John. Those expenses are contractually covered by the customer. And so if whatever the mote cost is, we're kept whole on that, and likewise with if you were to move from a lower-cost basin to a higher cost per day basin, as it relates to labor and maintenance and supply, we would also have that pass through, as well. So we're kept whole on our margins. But likewise if you went from a higher cost to a lower cost basin, then you would also adjust the day rate accordingly.

Sure, so the individual expense. If there is transition to take place, we might expect reimbursables to go up on the revenue base over say the next couple of quarters; is that reasonable?

Well, that is true. I don't know that it's necessarily true that we're going to have a large movement of rate. As I mentioned earlier, we've gone from I believe 28 rigs in Haynesville down to 5 or 6. I think we'll continue to have rigs migrate out of basins, but I don't think they are going to be a lot of dollars tied up in it. I don't see a real large number of rigs that will take place over the next couple of quarters.

I see. Okay. So, perhaps adjusting the current rate in the mid to high 50s is maybe a sustainable level for reimbursables? At least as it relates to that issue, I suppose?

I don't really have the details to answer that, Brad.

Okay. All right, well, very good. Appreciate the answers. I'll turn it back.

Okay. Thanks.

We'll take our next question from Dave Wilson with Howard Weil. Your line is open.

Good morning, gentlemen. Wanted to revisit a topic here on supply and demand, and wondering if you could clarify your thoughts on that topic, given the supply coming into the market for 2012 of about 200 rigs, and about an equal amount of mechanical rigs still working it, and based upon some of the previous questions on day rate levels and where you see those.

To me it looks like the supply and demand in the near term for the upcoming years is pretty well set and pricing really hasn't moved dramatically one way or another to signal an imbalance, but wanted to see if you could provide some clarification. I know you've mentioned ebbs and flows, but basically your thoughts on how this could play out. Is it possible that these mechanical rigs continue to work because they take a discount on the pricing?

Well, yes and I'm sure you'll see them discount pricing. But I think we have enough history now to show that there will be a group of customers that still won't find that to be an acceptable fit. And when you mention, Dave, the number of new builds coming in '12. Our guess it will be a little less than that, but not enough to quarrel over.

But when you look at a fleet the size of the US land fleet and the amount of activity, that to me is not a daunting number. And like John mentioned in his comments, you had 180 plus rigs officially retired last year, and that, in my mind, is not a process that's worked itself out.

That needs to continue for years and years to come, where you have that amount of attrition or potentially more so. We don't see a big imbalance occurring and we still see a very strong preference for higher-performing rigs and the complexity of the well designs, and the type of drilling is continuing to increase, and so all of those trends are favorable to our outlook, and keep us from being overly concerned with the pricing dynamic.

Okay. Thanks for the clarification on that and then a follow-up, unrelated, if I could. I was just wondering on the new builds, and how much lead time you need in order to get the rigs delivered. In other words, how long is the shelf life on those seven remaining 2012 spots? I mean, basically where a customer comes to you and says I want a rig in December 2012, what is the latest date you could take that order?

Well, it's a fair question. But, I guess it's a little more complicated than that behind the scenes, if you will, in terms of, we have -- we try to accommodate a customer on their preferred delivery, and so it has slots that are open in different times of the year.

So, maybe a general way of thinking about it is in terms of behind the scenes, our construction process is about a six-month process. We have some slots available in the fall and then, of course, in '13. I don't know if that's giving you the clarification you're asking for?

No, that's good, thank you. And that's it for me. I'll turn the call back over.

Okay. Thank you.

We'll take our next question from Jim Crandell with Dahlman Rose. Your line is open.

Thank you. And my sympathies, Hans, your father was a great man.

Thanks, Jim.

Hans or John, you're known as having excellent relationships with the majors. And if you look at some of their build programs over the course of 2011, many have ramped up significantly over the course of the year, in terms of numbers of rigs working such as BHP, Marathon, Oxy, Shell, Chevron, just to name a few. And as you look at these company's rig additions programs, without going into additional customers, but overall the majors, do you see these companies, certain of them, in the midst of major addition programs? And the builds we saw these companies do over the past year could be replicated in 2012?

Well, and I'll let John add some thoughts too, but my first thought is that, like you point out, 2011 was a very strong year. We had 71 total new builds, which a year ago would have been more than we would have expected, and I think it's important strategically that we got these in place. That they're fully contracted that they're in our Q. I think what will happen, Jim, going forward is, we're hearing from customers that they have multi-year plans, and, as you know, not hundreds but thousands of wells to drill.

They're going to migrate to a higher concentration of tier one rigs over time. But practically speaking, I think as everyone transitions into the first of the year, they're kind of watching the landscape and taking an account of what's going on in the marketplace. And so, in our minds, it's a timing issue and it's not disruptive for the longer term but in the shorter term, we're probably in a transition period.

Okay, Hans, if you look at some of these companies and if you look at a Marathon, which has gone from 9 to 24 over the past year, or Shell from 14 to 25 or Chevron to 11 from 27, I mean are these the types of companies that could be at 35 to 40 rigs a year from now and they still are in the midst of a significant ramp up. After all, Exxon operates 63 rigs, and Occidental is up over 50, as well.

Well, and I think as you point out, when you look down our customer list, and we can't speak for our customer, except to say they believe their field operations, and their ability to execute, and their ability to do that on scale, and to have the capital structure, and the personnel, and the expertise, and the experience to do all those things would suggest that the rig levels you talked about are not their maximum, and that they're capable of doing a lot more. And I think they see it as a strategic strength. So, we don't think they're done either, Jim.

Okay, Hans, if you were to take that question just a little bit different direction and just look at the international companies, some of which have never really been in the US market to a meaningful extent. Number one, do you see some of the international companies that have just gotten in over the past year in the midst of a build? And are you having conversations with large companies that don't have any representation in the US shales, and do you think we could see more new companies, meaning more International Companies entering the US market, as they've done in the last year or two?

Yes, I think that's an important trend and dynamic to watch and as you know, some of these JV relationships are occurring because these larger NOCs are coming in, and as they gain some of the operations, they will be interested in having the best available solution, and it won't just be H&P but it will be a complement of the folks that the service providers that do it the best, And safety is a very keen requirement for them.

All those things are accretive to our position and then I think it just flows into they're over here to gain the experience because they see the international opportunities in their backyards and in other areas of interest that they have, and so I think it would be natural continuation for that to impact our international footprint, as well. So, the size, the type of players, their focus on performance, efficiency, safety, all of those things are positive for us and I think you'll see it making an impact.

Okay. Thank you, Hans.

Thank you.

We'll take our next question from Joe Hill with Tudor Pickering. Your line is open.

Good morning.

Hey, Joe.

John, I think you mentioned that you were at 152 term contracts today, and if we look at kind of the progression you had talked about in the past, you should see about a drop of about 10 over the balance of the year. What do you think the odds are today that you can actually end the year at 152 or better?

The fiscal year?

Yes, sir.

I think that's reasonable. I mean, we're giving you a snapshot of current contractual commitments. As you know, as rigs roll off of term, some roll into the spot and some roll back into another term contract. A lot of variables are involved there, but I think it's 150 to 152 is reasonable. I think we talked about 148 rigs on average of the last three quarters of '12 for the fiscal year, so I think that's a reasonable number.

Okay. And then this is a little bit more nuanced. But are you seeing any change in the demand for the type of equipment given the change we're seeing in activity in the different basins. That is, we're losing gas activity and we're picking up oil activity and I was just wondering whether or not you're seeing more or less demand for, say, skiddable equipment?

Joe, I really haven't -- I really haven't noticed any difference. The Flex 5's been popular. The Flex 3 has pad capability although fewer wells on a pad and we're seeing -- as we've said before, we actually have customers going to pad drilling in areas that don't have the environmental concerns and issues like you would have somewhere like in Colorado.

So, I think it's economic based. I think it just makes good sense to do that, but I really haven't seen it change much. I mean we've have nice demand for that and would expect that it would continue.

Okay, that's good color. I'll turn it over, thanks.

All right, Joe, thanks.

Thank you.

And we'll take our next question from Robin Shoemaker at Citi. Your line is open.

Yes, thank you. Just on that last question, I want to make sure. So, you've got about 30 new term rigs on term contract that will start between now and the year. So, the 152 you would add the 30, right? And so the year-end number I had something like 182 or so, or were you referring to -- is that right way to think about it or --?

Robin, this is Juan Pablo. One other variable of course that impacts the equation is the number of rigs that are currently on term that are rolling off. And during the next -- during the last three quarters of the fiscal year, we have approximately 43 of those that are rolling off.

Okay, so you are thinking in terms of a net of like 152 at the end of the year with the 30 new contracts?

Yes, and potentially additional contracts that would lead us to over 150 at the end of the fiscal year, yes.

Okay, understood. Okay, so my only other question, then, was that when we look at this oil rig count increasing, gas rig count decreasing, it seems it thus far is kind of a wash that there -- the one's offsetting the other, and that the real kind of unknown here is whether or not there are some new liquids-rich shale plays that emerge over the next year or so that, like the Utica or the Tuscaloosa, that may turn out to be new dynamic shale plays that would absorb a lot of rigs et cetera, et cetera. So do you currently have rigs operating in some of these newer, less-frequently talked about shale plays, and are any of your conversations about potential new builds relating to these plays?

Robin, this is John. We don't have any rigs working in the Utica today. The rigs that would most likely -- obviously that would be most likely to move to the Utica in the future would be rigs coming out of the Marcellus that are drilling dry gas. That's always a possibility, but we don't have any in the Utica now.

We do have some existing customers that are using FlexRigs in other US basins that have acreage positions in the Utica, so we wouldn't be surprised to see some activity in the Utica. I don't really have a feel for when that would be. We do have rigs working in Louisiana, FlexRigs that are capable of doing work in the Tuscaloosa shale.

Again, we've got customers that have acreage positions there, as well. But don't -- we aren't -- to my knowledge we're not actually drilling any Tuscaloosa shale wells currently. I really can't think of anything that's new out there, but I think the point to keep thinking about is, as rigs are redirected, use the Haynesville as an example. There's only -- there's almost 100 rigs working there, only 40 are AC drive. There's not many mechanical rigs, which you wouldn't be surprised at that, but there's close to 50 SCR or a little over 50 SCR rigs running.

Some of those rigs are probably capable of doing some of this work in the Eagle Ford or Permian, but some of them may not be. And so, that's where I think we continue to see questions or decisions made by customers on whether they're going to pay to move that rig 300 or 400 or 500 miles, or whether they're going to go another route with a newer rig.

Okay. So, nothing on the horizon that you could see where there's a new shale play that's got a whole lot of customer interest that would translate into possible new FlexRig construction?

Well, I think -- this is Hans, Robin. I think we're early on in the Utica. It's going to be a significant play. And there are others that kind of fit your headline or category, but I think the other thing to think about is, as the customer focuses his technical teams and geo science work over to oil and gas-rich liquids, you've got a lot of activity that won't be necessarily headliner status that continues to -- and I guess that's an important take away from this call, is, I can't think of a cycle where you have some uncertainty, and we've described the uncertainty, but that you have this kind of fallback of so much inventory and so much economical drilling.

Usually when you have price concerns it makes everything uneconomic. Today, you have this strange delta between the natural gas prices and oil prices, but on the oil side, you've got a lot of work to be done that I think we have successfully transition to. So, that's hopefully the encouragement coming from the gulf.

Yes. Okay. Well, thank you.

Thank you.

We'll take our next question from Jack Moore with Harpswell Capital. Your line is open.

Thanks, and again my condolences for you as well, Hans.

Thanks, Jack.

Can you just give some more color on how you see the rig demand market evolving, aside from the trend away from gas and towards liquids? What else do you see with respect to who the customers are and what they're looking for, in terms of specs?

Well, besides just some of the general things that we've talked about in terms of the type of drilling and the laterals are longer and the wells are more complex, I think one of the things that will continue to evolve is, you'll shift into a more exploitation development concentration that becomes more factory-like and that's a positive for us.

So, where other rigs might have been more suitable to do some definition work, as they go into a phase two, or a modality where they're really focused on their development, then I think it enhances our potential. And then, I would expect you'll continue to see a trend towards pad drilling and the benefits it has in terms of environmental impact, and the reduction of support services required for the same number of wells. So, we're watching all of those things, and I think are very well-positioned for that development.

I agree and I appreciated the comment you gave on trying not to be myopic and manage quarter-to-quarter. I think that you certainly do your investors a big service by maintaining the long-term focus. That's great. Can you talk about crews and how many people are working on rigs now versus a couple of years ago, and what you see as your ability to satisfy your need for additional employees?

Well, I think we've continued to develop our training capabilities. And one of the benefits as we've gotten bigger, we have the benefit of being able to seed the rigs coming online with experienced H&P folks, and you have a mentoring dynamic and kind of a team-building dynamic there.

So, I think we're actually in better shape today than we were in the last build cycle in '06 through '08. So, there are areas where available labor is more challenging than where it might be otherwise, but even that, I think our guys do a good job of attracting training, and then retaining folks that want to be a part of the Company and want to be part of the culture that we have.

Yes. That's great. Well, thanks very much.

Thank you.

Our final question is a follow-up from John Daniel with Simmons and Company. Your line is open.

Hey, thanks for putting me back in, and sorry to be the evil self side guy that wants to focus on quarter-over-quarter changes but --

That doesn't make you evil, John.

Well, after -- the guy before me was pretty nice, so here I come and mess everything up. But you mentioned that roughly 43 rigs will roll off contract in the coming quarters, and I presume a number of those are in liquids-riches areas. What I'm wondering is, the customers that are using those rigs now that will be rolling off contract, are they indicating a desire to re-sign those rigs; and if so, are they looking at six month terms, well to well, can you just frame for us that discussion?

John, the majority of those -- a large number of those 43 are more towards the back half of the fiscal year.

Okay.

The impression we have right now is that in most cases that we're aware of, the customer wants to keep the rig and we would be surprised if they released the rig. There's always exceptions, but overall we feel pretty encouraged by the level of interest. A lot of the rigs that are going to roll off are Flex 3s and as you know, Flex 3s are in high demand regardless of the area.

Yes.

So, we feel really good about the position; and again, many of the those 40, at least we would expect, will roll back into a term contract. Again, it's going to be based on customer needs in the basin, and what the demand is going to be.

Right, but the feeling today is a good one?

Yes, I feel real confident. I feel real good about our customers and their budgets going forward. No doubt there's some concern with natural gas prices, but there's a lot of plans out there that customers have for 2012 that are going to require FlexRigs to get it done.

Okay. Fair enough and then just a last one for me. Presumably you'll see some rigs in the dry gas market, certainly the ones that are on spot get released. Is there any noticeable difference, in terms of leading edge day rates between those rigs that are in the spot on the dry gas versus where they might migrate to?

I don't think there's a major difference, John.

Okay.

We'll look at that and make certain that that isn't different than that, but I think it's going to be basically the same.

Okay. Great. Thanks and great quarter.

Thanks, John.

There are no further questions at this time.

Thank you, Alicia, and thank you, everybody, for joining us and have a good day.

This concludes today's teleconference. You may now disconnect and enjoy the rest of your day.